M S O P THIRD T V R DRAFT APRIL 26, · PDF fileTEG D EHYDRATION UNIT E ... field gas entering...

EXXONMOBILE PRODUCTION COMPANY ONSHORE GAS TREATING FACILITY [OTF]

THEODORE, MOBILE COUNTY, AL Facility No.: 503-4011

MAJOR SOURCE OPERATING PERMIT THIRD TITLE V RENEWAL DRAFT APRIL 26, 2017

(THIS PAGE LEFT BLANK INTENTIONALLY

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TABLE OF CONTENTS

PROCESS DESCRIPTION ...................................................................................................................................... 5

NOTABLE CHANGES ........................................................................................................................................... 6

FACILITY-WIDE EMISSION REQUIREMENTS ......................................................................................................... 7

STATE REGULATIONS ........................................................................................................................................................ 7 ADEM Admin. Code R. 335-3-4-.01(1)(a) and (b), “Visible Emissions” for Control of Particulate Emissions ......................... 7 ADEM Admin. Code R. 335-3-5-.03 (1), (2) “Petroleum Production” ........................................................................................ 7 ADEM Admin. Code R. 335-3-6 “Control of Organic Emissions” ............................................................................................... 8 ADEM Admin. Code R. 335-3-14-.04 “Prevention of Significant Deterioration (PSD) Permitting” ......................................... 8 ADEM Admin. Code R. 335-3-16-.03, “Major Source Operating Permits” (MSOP) .................................................................. 8 ADEM Admin. Code R. 335-3-16-.10, “Permit Shield” ................................................................................................................ 8

FEDERAL REGULATIONS ..................................................................................................................................................... 8 New Source Performance Standards (NSPS) .......................................................................................................... 8

40 CFR 60 Subpart A, “General Provisions” ................................................................................................................................ 8 40 CFR 60 Subpart KKK, “Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing

Plants” [NSPS KKK] ........................................................................................................................................................................ 9 40 CFR 60 Subpart LLL, “Standards of Performance for Onshore Natural Gas Processing: SO2 emissions” ........................... 9 40 CFR 60 Subpart OOOO, “Standards of Performance for Crude Oil and Natural Gas Facilities” [Quad O] ........................ 9 40 CFR 60 Subpart OOOOa, “Standards of Performance for Crude Oil and Natural Gas Facilities” [Quad Oa] .................... 9

National Emission Standards for Hazardous Air Pollutants (NESHAP) ................................................................... 9 40 CFR 63, Subpart A, “General Provisions” ............................................................................................................................... 9 40 CFR 63, Subpart HH, “National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production

Facilities” ..................................................................................................................................................................................... 10 40 CFR 64, “Compliance Assurance Monitoring” (CAM) ...................................................................................... 10

FACILITY-WIDE EMISSIONS ............................................................................................................................................... 10

BOILER REQUIREMENTS ....................................................................................................................................11

STATE REGULATIONS ...................................................................................................................................................... 11 ADEM Admin. Code R. 335-3-4-.01(1)(a) and (b), “Visible Emissions” for Control of Particulate Emissions ....................... 11 ADEM Admin. Code R. 335-3-4-.03(1), “Fuel Burning Equipment” for Control of Particulate Emissions ............................ 12 ADEM Admin. Code R. 335-3-5-.01(1)(a), “Fuel Combustion” for Control of Sulfur Compound Emissions ......................... 12 ADEM Admin. Code R. 335-3-14-.04 “Prevention of Significant Deterioration (PSD) Permitting” ....................................... 13 ADEM Admin. Code R. 335-3-16-.03, “Major Source Operating Permits” (MSOP) ................................................................ 14

FEDERAL REGULATIONS ................................................................................................................................................... 14 New Source Performance Standards (NSPS) ........................................................................................................ 14

40 CFR 60 Subpart A, “General Provisions” .............................................................................................................................. 14 40 CFR 60 Subpart Dc, “Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating

Units” ........................................................................................................................................................................................... 14 National Emission Standards for Hazardous Air Pollutants (NESHAP) ................................................................. 14

40 CFR 63 Subpart A, “General Provisions” .............................................................................................................................. 14 40 CFR 63 Subpart DDDDD, “National Emissions Standards for Hazardous Air Pollutants for Industrial, Commercial, and

Institutional Boilers and Process Heaters” ................................................................................................................................ 14 40 CFR 63 Subpart JJJJJJ, “National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and

Institutional Boilers Area Sources” ............................................................................................................................................ 15 40 CFR 64, “Compliance Assurance Monitoring” (CAM) ...................................................................................... 15

BOILERS EMISSIONS ........................................................................................................................................................ 15

EMERGENCY ENGINE REQUIREMENTS ...............................................................................................................16

STATE REGULATIONS ...................................................................................................................................................... 16 ADEM Admin. Code R. 335-3-4-.01(1)(a) and (b), “Visible Emissions” for Control of Particulate Emissions ....................... 16 ADEM Admin. Code R. 335-3-14-.04 “Prevention of Significant Deterioration (PSD) Permitting” ....................................... 16 ADEM Admin. Code R. 335-3-16-.03, “Major Source Operating Permits” (MSOP) ................................................................ 17

FEDERAL REGULATIONS ................................................................................................................................................... 17 NEW SOURCE PERFORMANCE STANDARDS (NSPS) .............................................................................................................. 17

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40 CFR 60 Subpart A, “General Provisions” .............................................................................................................................. 17 40 CFR 60 Subpart IIII, “Standards of Performance for Compressions Ignition Internal Combustion Engines” [NSPS IIII] . 17

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAP) ...................................................................... 17 40 CFR 63, Subpart A, “General Provisions” ............................................................................................................................. 17 40 CFR 63 Subpart ZZZZ, “National Emission Standards for Hazardous Air Pollutants (HAPs) for Stationary Reciprocating

Internal Combustion Engines (RICE)” [RICE MACT] .................................................................................................................. 17 40 CFR 64, “COMPLIANCE ASSURANCE MONITORING (CAM)” ............................................................................................. 19 EMERGENCY ENGINE EMISSIONS ....................................................................................................................................... 19

SIMPLE CYCLE COMBUSTION TURBINE REQUIREMENTS .....................................................................................20

STATE REGULATIONS ...................................................................................................................................................... 20 ADEM Admin. Code R. 335-3-4-.01(1)(a) and (b), “Visible Emissions” for Control of Particulate Emissions ....................... 20 ADEM Admin. Code R. 335-3-14-.04 “Prevention of Significant Deterioration (PSD) Permitting” ....................................... 21

FEDERAL REGULATIONS ................................................................................................................................................... 22 NEW SOURCE PERFORMANCE STANDARDS (NSPS) .............................................................................................................. 22

40 CFR 60 Subpart A, “General Provisions” .............................................................................................................................. 22 40 CFR 60 Subpart GG, “Standards of Performance for Gas Turbines” [NSPS GG] ................................................................ 22

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAP) ...................................................................... 24 40 CFR 63, Subpart A, “General Provisions” ............................................................................................................................. 24 40 CFR 63, Subpart YYYY, “National Emission Standards for Hazardous Air Pollutants for Stationary Combustion

Turbines” ..................................................................................................................................................................................... 24 40 CFR 64, “COMPLIANCE ASSURANCE MONITORING (CAM)” ............................................................................................. 24 TURBINE EMISSIONS ....................................................................................................................................................... 24

TEG DEHYDRATION UNIT REQUIREMENTS .........................................................................................................25

STATE REGULATIONS ...................................................................................................................................................... 25 ADEM Admin. Code R. 335-3-16-.03, “Major Source Operating Permits” (MSOP) ................................................................ 25

FEDERAL REGULATIONS ................................................................................................................................................... 25 National Emission Standards for Hazardous Air Pollutants (NESHAP) ................................................................. 25

40 CFR 63, Subpart A, “General Provisions” ............................................................................................................................. 25 40 CFR 63, Subpart HH, “National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production

Facilities” ..................................................................................................................................................................................... 25 TEG DEHYDRATION UNIT EMISSIONS ................................................................................................................................ 26

SULFUR RECOVERY SYSTEM /THERMAL OXIDIZER REQUIREMENTS .....................................................................27

STATE REGULATIONS ...................................................................................................................................................... 27 ADEM Admin. Code R. 335-3-4-.01(1)(a) and (b), “Visible Emissions” for Control of Particulate Emissions ....................... 27 ADEM Admin. Code R. 335-3-5-.03 (1), (2), and (3) “Petroleum Production” ........................................................................ 28 ADEM Admin. Code R. 335-3-14-.04 “Prevention of Significant Deterioration (PSD) Permitting” ....................................... 29 ADEM Admin. Code R. 335-3-16-.03, “Major Source Operating Permits” (MSOP) ................................................................ 31


40 CFR 60 Subpart A, “General Provisions” .............................................................................................................................. 31 40 CFR 60 Subpart LLL, “Standards of Performance for Onshore Natural Gas Processing: SO2 emissions” [NSPS LLL] ...... 31

40 CFR 64, “Compliance Assurance Monitoring” (CAM) ...................................................................................... 31 SRU/THERMAL OXIDIZER POTENTIAL EMISSIONS ................................................................................................................. 32

FLARE REQUIREMENTS .....................................................................................................................................33

STATE REGULATIONS ...................................................................................................................................................... 33 ADEM Admin. Code R. 335-3-4-.01(1)(a) and (b), “Visible Emissions” for Control of Particulate Emissions ....................... 33 ADEM Admin. Code R. 335-3-5-.03 (1), (2), and (3) “Petroleum Production” ........................................................................ 34 ADEM Admin. Code R. 335-3-14-.04 “Prevention of Significant Deterioration (PSD) Permitting” ....................................... 35

FEDERAL REGULATIONS ................................................................................................................................................... 35 40 CFR 64, “Compliance Assurance Monitoring” (CAM) ...................................................................................... 35

FLARE POTENTIAL EMISSIONS ........................................................................................................................................... 36

STORAGE TANK REQUIREMENTS .......................................................................................................................37

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STATE REGULATIONS ...................................................................................................................................................... 37 ADEM Admin. Code R. 335-3-6 “Control of Organic Emissions” ............................................................................................. 37 ADEM Admin. Code R. 335-3-16-.03, “Major Source Operating Permits”.............................................................................. 37


40 CFR 60 Subpart A, “General Provisions” .............................................................................................................................. 38 40 CFR Part 60 Subpart Kb, “Standards of Performance for Storage Vessels from Petroleum Liquids” ............................... 38

40 CFR 64, “Compliance Assurance Monitoring (CAM)” ...................................................................................... 38 TANK POTENTIAL EMISSIONS ............................................................................................................................................ 38 RECOMMENDATIONS ...................................................................................................................................................... 39

ATTACHMENT A: DRAFT PROVISOS ...................................................................................................................40

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EXXONMOBIL PRODUCTION COMPANY ONSHORE GAS TREATING FACILITY [OTF]

THEODORE, MOBILE COUNTY, AL Facility No.: 503-4011

STATEMENT OF BASIS

The proposed Title V Major Source Operating Permit (MSOP) third 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.

ExxonMobil Production Company was issued the existing MSOP on June 27, 2011 with a modification date of June 19, 2012 for the Onshore Treating and Processing Facility (OTF Plant) located at 6000 Deakle Road, Theodore, Mobile County, AL. The permit had an expiration date of June 18, 2016.

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 December 3, 2015. Additional information and revisions to the application was submitted on March 29, 2016. The proposed MSOP would expire on ???

ONSHORE GAS TREATING FACILITY [OTF] Facility No.: 503-4011 STATEMENT OF BASIS

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PROCESS DESCRIPTION

The sour gas feed for the facility is produced and gathered from offshore gas wells. Field gas and produced liquids are delivered from the offshore platforms through separate pipeline systems. The field gas entering the onshore facility is delivered to a slug catcher vessel where any entrained liquids are separated from the gas. The gas flows from the slug catcher through filter/coalescing vessels. The gas is then sweetened in primary amine contactors, which removes carbon dioxide and various sulfur compounds from the gas. The sweetened, high-pressure wet gas is then dehydrated to pipeline water content specifications in glycol contactors. This gas is sent to either the DCP Midstream plant [Facility No. 503-8085] or the Williams Field Services plant [Facility No. 503-8056] where entrained hydrocarbon liquids are removed from the gas stream. Facility fuel is delivered from pipeline after liquids extraction. The rich amine solution, containing the absorbed sour gases and some co-absorbed hydrocarbons, leaves the high-pressure amine contactor and is flashed to a lower pressure. The sour hydrocarbon-rich flash gas is routed to the plant vapor recovery unit for compression and recycled back to the produced gas plant inlet. Various other low pressure gas streams in the plant are also routed to the vapor recovery unit for recycle back to the plant inlet. The rich amine solutions from the high pressure amine contactors are heat-stripped in the primary amine regenerator tower to remove the acid gas components and produce lean amine for reuse in the high pressure contactors. The amine solvent is continuously circulated between the contactors and regenerator in the gas sweetening process. Acid gas leaving the amine regeneration column is cooled to condense water vapor and routed through the sulfur recovery systems (i.e. acid gas enhancement unit, two typical four stage Claus elemental sulfur production units and two tail gas clean up units) where various sulfide compounds are converted into molten, elemental sulfur. The tail gases leaving each sulfide conversion system are sent to a thermal oxidizer for burning. The rich glycol solution leaving the glycol contactor is flashed to a lower pressure in a separator vessel. The flash gas is routed to the vapor recovery unit for compression and sent back to the plant produced gas inlet. The flashed liquid phase is routed to the glycol regeneration column, where absorbed water and hydrocarbons are stripped from the glycol by heating and natural gas stripping. The glycol regenerator overhead vapors are routed through a water cooled condenser to remove hydrocarbons and then to the facility flare for thermal destruction. The produced liquids stream from the offshore platforms is sent to the plant inlet liquids separator (three phase separator). From the inlet liquids separator the produced water is routed to storage tanks for secondary separation, and then routed to filtration and pumped to disposal wells. The hydrocarbon stream in the produced liquids is a mixture of diesel and natural gas liquids. The liquid hydrocarbon stream from the inlet liquids separator is routed to a surge tank and then to a stripper system, where the liquid is heat-stripped to remove H2S and volatiles. The sour overhead from the stripping system is cooled and routed to the vapor recovery unit for compression to the produced gas plant inlet. The sweet hydrocarbon stream is routed to storage tanks, from which it is trucked out for recovery at a local liquids refinery. The gas flashed from the liquids at the onshore inlet liquids separator is routed to the vapor recover compressors. All the liquids handling vessels and tanks in the onshore facility are vapor space controlled, with any evolved gases routed to the vapor recovery compressors. Plant heat source is primarily provided by two, 91.7 MMBTU/hour boilers and by waste heat recovery systems associated with sulfur recovery systems, thermal oxidizers, and electricity


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generating turbines. Three 5,000 BHP, gas-fired, simple cycle combustion turbine (i.e. SCCT) engines provides electrical power generation for the facility. Two emergency gas flares, one high pressure and one low pressure, are also located at this facility. The significant sources of air pollutants at this facility along with applicable requirements, expected emissions and proposed monitoring are noted in the on the following pages.

NOTABLE CHANGES

During this renewal, several notable changes will be made to the permit in order to demonstrate compliance with new and/or modified federal and state requirements:

• 40 CFR 63 Subpart HH [Oil and Gas MACT] has been modified since the issuance of the last permit renewal. The changes affected both area and major sources of HAPs. The facility is now required to calculate the optimum glycol circulation rate or establish a maximum alternate glycol circulation rate. The facility chose to establish an alternate glycol circulation rate and supporting documents were provided to the Department on April 21, 2008; however, the rate was not included in the permit. The rate will be included during this renewal.

• Each emission monitoring section and compliance and performance test section of the permits will be restructured during this renewal.

• The PSD/BACT Limit which requires that the facility burn fuel gas with an H2S content of 0.10 grains/100 Scf or less in the turbine engines was removed from the permit during the last renewal. After further review of the facility files and discussion with the facility, it has been determined that the requirement was inadvertently removed from the permit during the last renewal. This requirement is being placed back into the permit during this renewal.

• Remove applicability to 40 CFR 60 Subpart Kb for the tanks because they do not store liquids in the storage vessels that would meet the maximum true vapor pressure requirements and the storage vessels would not meet the design capacity requirements for applicability under this subpart. It is possible that the storage vessels were deemed subject to this subpart in order for the facility to have flexibility in the types of liquids stored in the tanks. The facility has no future plans to store liquids that would be meet the requirements of this subpart.

• On May 3, 2017, Exxon requested to remove the requirement to limit acid gas flaring of high sulfur gas flaring to 40 hours per calendar quarter. This hourly limit for flaring was introduced in the 2006 Title V permit renewal. The limit is believed to have been placed in the permit to ensure that all acid gas sulfur masses that are flared are properly accounted for as sulfur feed for the SRU. There is not a regulatory basis for the limit (not required by state or federal regulation) and the facility believes that the limit is not necessary because they are able to quantify emissions when acid gas is routed from the SRU to the flare. Also during acid gas flaring the hours of flaring are maintained and the sulfur reduction efficiencies are correctly calculated to demonstrate compliance with 40 CFR 60 Subpart LLL [NSPS LLL]. Exxon submitted two years of historical data to demonstrate that the facility has not exceeded the hourly limit during each calendar quarter in 2015 and 2016. Based on the information provided and the fact that I cannot there is no documented reason nor justification for the limit being included in the permit, I recommend that this requirements is removed from the permit during this renewal.


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FACILITY-WIDE EMISSION REQUIREMENTS

Applicable facility-wide regulations for the OTF Plant are found in the following table:

EMISSION POINT

DESCRIPTION POLLUTANT EMISSION LIMIT

REGULATIONS

Each Stationary Source 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)

Petroleum Production Facilities H2S Burn gas with >

0.10 Rule 335-3-5-.03(1) Rule 335-3-5-.03(2)

grains of H2S/scf of gas; 20 ppbv

offsite

Oil and Natural Gas Production Facilities

Affected facility: Each Tri-ethylene Glycol (TEG) dehydration unit process vent

HAPs 4,674 gpm Max glycol

circulation rate

§63.760(b)(2); §63.764(d)(2)(ii) 40 CFR 63 Subpart HH

Onshore Natural Gas Processing Facilities

Affected facility: Each sweetening unit and Each sweetening unit follow by a sulfur recovery unit (SRU)

SO2 Sulfur recovery efficiencies >

calculated allowable

§60.640(a) 40 CFR 60 Subpart LLL

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

STATE REGULATIONS

Applicability :

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

Several of the emission sources located at this facility are subject to the requirements of these subparts. The specific monitoring and recordkeeping requirements shall be discussed in the individual sections.

Applicability:

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

These regulations apply 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) of gas. The OTF Plant would handle sour gas that contains 0.10 grain of H2S/scf of gas or more; therefore, the facility would be subject to


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the applicable requirements of these regulations. The sulfur recovery system/thermal oxidizers and flares would be used to comply with this regulation. Requirements for this regulation will be discussed in the sections for the sulfur recovery system/thermal oxidizers and the flares.

Because the OTF is also subject to the requirements of 40 CFR 60 Subpart LLL [NSPS LLL] the requirements of ADEM Admin. Code r. 335-3-5-.03(3), compliance with NSPS LLL shall be complied with to demonstrate compliance with this regulation.

Applicability:

ADEM Admin. Code R. 335-3-6 “Control of Organic Emissions”

This chapter is applicable for emission sources emitting 100 Tons per year (TPY) or more of VOC emissions. This chapter would not be applicable to emission sources at the OTF Plant.

Applicability:

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

The OTF Plant is a 100 ton per year source with respect to PSD since the facility is equipped with a sulfur recovery plant. Therefore, each proposed project has to be evaluated to determine if there is a significant emissions increase and a significant net emissions increase above the de minimus levels for each pollutant. PSD applicability will be discussed in each section of this document.

Applicability:

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

The OTF Plant has been deemed a major source of criteria pollutants (have the potential to exceed 100 tons per year (TPY) or more) and a major source of Greenhouse House Gases (GHG). The facility is not a major source of hazardous air pollutants (HAPs) emissions (have the potential to exceed 10 TPY or more for a single HAP or 25 TPY or more for a combination of HAPs). Therefore, the OTF Plant would be subject to the requirements of this regulation.

Applicability:

ADEM Admin. Code R. 335-3-16-.10, “Permit Shield”

The facility has requested a permit shield requesting that compliance with the conditions of the permit should be deemed compliance with any applicable requirements as of the date of permit issuance. The appropriate documentation for this request was included in the renewal application.

FEDERAL REGULATIONS

NEW SOURCE PERFORMANCE STANDARDS (NSPS)

Applicability:

40 CFR 60 Subpart A, “General Provisions”

Provided that affected sources located at the plant are subject to one of the applicable subparts found under this part, the facility shall comply with this subpart as specified in the applicable subpart.


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Applicability:

40 CFR 60 Subpart KKK, “Standards of Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing Plants” [NSPS KKK]

The OTF Plant is not subject to the requirements of this subpart for affected sources that were constructed, reconstructed, and modified after January 20, 1984 and on or before August 23, 2011. By definition of this subpart the OTF Plant does not meet the definition of a natural gas processing plant under this subpart because it is not engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. No liquids are extracted from the natural gas entering into the plant and no fractionation occurs; therefore, this subpart would not be applicable.

Applicability:

40 CFR 60 Subpart LLL, “Standards of Performance for Onshore Natural Gas Processing: SO2

emissions”

The two amine sweetening units each followed by a sulfur recovery unit (SRU) (S-108 and S-109) would be subject to the requirements of this subpart since the units were constructed after January 20, 1984 but on or before August 23, 2011. The requirements of this subpart will be discussed later in the sulfur recovery system/thermal oxidizer section.

Applicability:

40 CFR 60 Subpart OOOO, “Standards of Performance for Crude Oil and Natural Gas Facilities” [Quad O]

The subpart applies to affected source constructed, modified or reconstructed prior to August 23, 2011 and on or before September 18, 2015. The facility current does not have any affected sources which would be subject to the requirements of this subpart.

Applicability:

40 CFR 60 Subpart OOOOa, “Standards of Performance for Crude Oil and Natural Gas Facilities” [Quad Oa]

This subpart would not be applicable because there have not been any modification or reconstruction of the facility after September 18, 2015 which would have triggered applicability to this subpart.

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS (NESHAP)

Applicability:

40 CFR 63, Subpart A, “General Provisions”



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Applicability:

40 CFR 63, Subpart HH, “National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities”

The OTF Plant is an area source of HAPs with respect to this subpart since it does not meet the major source definition under this subpart. The plant is equipped with a tri-ethylene glycol [TEG] dehydration unit which is an affected area source under this subpart. The requirements of this subpart will be discussed later in the TEG section.

40 CFR 64, “C OMPLIANCE ASSURANCE MONITORING” (CAM)

This subpart is applicable to an emission source provided the source meets all of 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)]. Applicability to this subpart will be discussed in the individual sections for each emission source.

FACILITY-WIDE EMISSIONS

The emissions from all emission sources located at the plant are summarized in the table below. Fugitive emissions are included in the Total VOC emissions and they account for 10.79 TPY of the total VOC emissions.

FACILITY-WIDE POTENTIAL EMISSIONS (TPY)

PM SO2 NOX CO VOC TOTAL HAP CO2e

22.696 2,290.4516 765.455 425.593 49.709 17.470 208,899.78


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BOILER REQUIREMENTS

The facility is equipped with two natural gas fired boilers each of which produces steam for the plant.

EMISSION POINT DESCRIPTION POLLUTANT

EMISSION LIMIT †

REGULATIONS

EAL-6801

EAL-6802

91.7 MMBtu/hr, Gas Fired Boiler No. 1


PM

CO

NOX

SO2

Fuel H2S

17.3 Lbs/Hr

17.1 Lbs/Hr

16.7 Lbs/Hr

2.4 Lbs/Hr

10 grains/100 scf of gas

Or 160 ppmv

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

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

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

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

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

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)

† Limits for each unit

The boilers’ applicability to the state and federal regulations will be discussed in the following section.

STATE REGULATIONS

Applicability :


The boilers would be subject to the requirements of these regulations.

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. COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES

Method 9 or Method 22 found in 40 CFR 60, Appendix A would be used to demonstrate compliance with the opacity standards. When Method 22 is used to determine the duration of emissions, the method has to be conducted by an individual who is familiar with the procedures. When Method 9 is used to determine opacity, it has to be conducted by an individual who is certified to use this


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procedure. Visual inspections and visible emissions observations are both required to be conducted during daylight hours. EMISSIONS MONITORING

Provided that visible emissions are observed from the boilers in excess of the opacity standards, a visible emission observation shall be conducted. RECORDKEEPING AND REPORTING REQUIREMENTS

A record of each occurrence when a visible emissions observation was conducted should be recorded and maintained. A deviation should be reported to the Department within 48 hours or 2 working days when a visible emissions event occurs.

Applicability:

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

The boilers would be subject to this regulation since the facility is located in Mobile County which is a Class I County under this regulation.

EMISSION STANDARDS

Particulate matter (PM) emissions from the utility boilers shall not exceed 17.3 Lbs/hr, the allowable determined using the following equation:

E= [1.38] * [H-0.44]

where, E= Emissions (lb/MMBtu) and H= Heat Input (MMBtu/hr)

COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES

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.

EMISSIONS MONITORING

Since the fuel gas burned in the boilers would be natural gas there would not be a need for emission monitoring. PM emissions from natural gas fired boiler should not be significant enough to warrant monitoring.

RECORDKEEPING AND REPORTING REQUIREMENTS

A record of the hours of operation shall be maintained and the boilers’ heat input should be calculated in order to determine PM emission from each boilers.

Applicability:

ADEM Admin. Code R. 335-3-5-.01(1)(a), “Fuel Combustion” for Control of Sulfur Compound Emissions

The boilers would be subject to this regulation since the facility is located in Mobile County which is a Category I County under this regulation. SO2 emissions from fuel burning equipment located in a Category I county is limited to 1.8 pounds per million BTU of heat input (lb/MMBtu of heat


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input). The allowable emissions under this regulation would be 165.06 Lbs/hr for each boiler; however, the facility took more stringent SO2 limits (2.4 Lbs/hr) in order to comply with PSD/BACT requirements for the boilers. Compliance with the PSD/BACT SO2 limit would demonstrate compliance with this regulation.

Applicability:


The facility underwent a PSD review and accepted BACT limits for CO, NOX, SO2 emissions and limits on the H2S concentration of the fuel gas which can be burned in the boilers.

EMISSION STANDARDS

Emissions limits for each of the boilers can be found on the summary page of the boiler section of this Statement of Basis.


To demonstrate compliance with PSD/BACT limits for NOX and CO emissions, performance testing is required to be conducted using the following methods and procedures:

• 40 CFR Part 60 Appendix A, Method 1 or 1a to determine the sample site • 40 CFR Part 60 Appendix A, Method 2 or 2A or 2B or 2C or 2D or 2E to determine the

volumetric flow rate of the effluent gas • 40 CFR Part 60 Appendix A, Method 3 or 3A or 3B or 3C to determine the gas analysis • 40 CFR Part 60 Appendix A, Method 4 to determine the moisture in the stack gas • 40 CFR Part 60 Appendix A, Method 7 or 7A or 7B or 7C or 7D or 7E to determine NOX

emissions • 40 CFR Part 60 Appendix A, Method 10 or 10A or 10B to determine CO emissions • 40 CFR Part 60 Appendix A, Method 19 to determine SO2 and NOX emission rates

To demonstrate compliance with the fuel gas limit and the PSD/BACT SO2 limit, the facility is required to sample the fuel gas for its H2S content gas using one of the following methods and procedures:

• Tutwiler procedures found in 60.648 of 40 CFR Part 60, • Chromatographic analysis procedures found in ASTM E-2060 • Stain tube procedures found in GPA 2377-86 • Methods and procedures provided by the stain tube manufacturer • Other methods approved by the Department

The fuel gas shall also be tested for it Btu heat content by utilizing the ASTM Analysis Method D1826-77 or an equivalent method.


The facility must conduct performance testing on the boilers at least once every five years to determine CO and NOX emissions. The test should consist of three (3) one hour runs and emissions factors in units of Lbs/MMBtu should be determined for each of the boilers.

Sampling of the fuel gas for its Btu heat content and its H2S content is required no less than once every six (6) months.


Records of deviations, results of performance tests, boiler maintenance, fuel gas heat content, fuel gas H2S content, fuel gas consumption, boiler heat input, boiler operating hours and boiler emissions


Page 14

shall be maintained. A periodic monitoring report (PMR) is required to cover a semi-annual calendar basis and must be submitted to the Department within 30 days of the ending of the reporting period.

Applicability:


The boilers would be subject to the requirements of this regulation since they are located at a major source facility. To comply with the requirements of this regulation the facility is required to monitor and record the hours of operation, fuel gas consumption, and emissions from the boilers.

FEDERAL REGULATIONS


Applicability:



Applicability:

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

Since the boilers were constructed after June 9, 1989 and their maximum design heat input capacity is greater than or equal than 10 MMBtu/hr but less than 100 MMBtu/hr they would be subject to the requirements of this subpart. Natural gas-fired units are only subject to the requirement to maintain a record of the amount of fuel burned during each calendar month for a period of two years following the date of such record [60.48c(g)(2), (i)].


Applicability:



Applicability:

40 CFR 63 Subpart DDDDD, “National Emissions Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters”

This subpart is only applicable to boiler and process heaters located at a major source of HAPs. The OTF Plant is not a major source of HAPs.


Page 15

Applicability:

40 CFR 63 Subpart JJJJJJ, “National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers Area Sources”

This subpart is applicable to boiler and process heaters located at an area source of HAPs. The boilers would be located at an area source of HAPs; however, natural gas fired boilers as defined in §63.11237 are not subject to this subpart or any requirements in this subpart [§63.11195(e)].


The boilers would not be subject to the requirements of CAM since they are not equipped with a control device to comply with their emission standards.

BOILERS EMISSIONS

BOILER POTENTIAL EMISSIONS

EMISSION

SOURCE

(TPY)

PM 2.5/10 SO2 NOX CO VOC TOTAL

HAP CO2e

EAL-6801 (BOILER 1) 2.91 10.27 73.15 74.90 2.10 0.72 45,902.40

EAL-6802 (BOILER 2) 2.91 10.27 73.15 74.90 2.10 0.72 45,902.40

TOTAL BOILER EMISSIONS 5.82 20.54 146.3 149.8 4.2 1.44 91,804.8


Page 16

EMERGENCY ENGINE REQUIREMENTS


EMISSION L IMIT †

REGULATIONS

Fire Pump A &

Fire Pump B

Generator A

Generator B

(2) 287 BHP, Caterpillar 3306, Diesel Fire Pump Engines

390 BHP, Cummins NT-966-G5, Blackstart Gnerator, Diesel Engine

166 BHP, Cummins 6BT5.9-G2, Onan Generator [Communication Tower Backup], Diesel Engine

HAPs Work or Management

Practices

§63.6585(c) §63.6590(a)(1)(iii) §63.6603(a)

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)

The emergency engines’ applicability to state and federal regulations will be discussed in the following section.

STATE REGULATIONS

Applicability:


The engines would be subject to this regulation; however, since natural gas is burned as fuel in the engines the actual PM emissions should be negligible. Therefore, no monitoring would be required. Provided that visible emissions are observed from the engines, Method 9 of 40 CFR 60 Subpart A shall be utilized to determine opacity from these units.

Applicability:


When these engines were initially placed into service they did not undergo a PSD review since emergency generators were not subject to any state or federal regulations. Due to the limited use (fire suppression or protection, startup of a turbine, and backup generation) of these emergency engines and the engines’ size, there is no reason to believe that the engines’ emissions would have exceeded any de minimus thresholds under this subpart.


Page 17

Applicability:


The emergency engines would be subject to the requirements of this regulation since they are located at a facility that is a major source. These units were previously classified as insignificant activities under this regulation. However, any emission source that is subject to a MACT, NSPS, or NESHAP subpart is not allowed to be a trivial or insignificant source. Since, the engines are subject to a 40 CFR 63 Subpart ZZZZ, they can no longer be classified as an insignificant activity.

FEDERAL REGULATIONS


Applicability:


Provided that the engines are subject to one of the applicable subparts found under this part, the facility shall comply with this subpart as specified in the applicable subpart.

Applicability:

40 CFR 60 Subpart IIII, “Standards of Performance for Compressions Ignition Internal Combustion Engines” [NSPS IIII]

This regulation is applicable to compression ignition (CI) stationary engines that commenced construction after July 11, 2005 and that meets the applicable manufactured date. Based on the permit application, each of the engines at the plant were constructed (1993 listed in the permit application) prior to the effective date for this subpart and neither has been modified or reconstructed since the effective date. Therefore, there are no requirements for these engines under this subpart.


Applicability:


The emergency engines are subject to 40 CFR 63 Subpart ZZZZ; therefore, the applicable General Provisos of Subpart A found in Table of 8 of subpart ZZZZ should be met.

Applicability:

40 CFR 63 Subpart ZZZZ, “National Emission Standards for Hazardous Air Pollutants (HAPs) for Stationary Reciprocating Internal Combustion Engines (RICE)” [RICE MACT]

Since the emergency generator engines were constructed at the plant prior to June 12, 2006, the engines would be existing sources under this subpart. There are no operating limitations, fuel requirements or performance test requirements for these units under this subpart; however, there are work or management practices that must be complied with.


Page 18

EMISSIONS STANDARDS

The following work or management practices must be met for emergency stationary CI engines, except during periods of startup or during emergency (Table 2d No. 4):

• 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 requirement)

• 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.

Each engine, 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. Also the engine must be operated and maintained according to the manufacturer's emission-related written instructions or a maintenance plan must be developed. The maintenance plan must provide to the extent practicable for the maintenance and operation of the engine in a manner consistent with good air pollution control practice for minimizing emissions [Table 6 No. 9]

An existing emergency stationary RICE located at an area source of HAP emissions must be equipped with a non-resettable hour meter if one is not already installed.

During periods of startup, the facility must 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 [§63.6625(h)].

In order for engines to be considered an emergency stationary RICE, the unit must be operated as specified in §63.6640 f(1) through (4). Any operation other than emergency operation, maintenance and testing, emergency demand response, and operation in non-emergency situations for 50 hours per year is prohibited. If the engines are not operated according to the requirements in §63.6640 f(1) through (4) of this section, the engine will not be considered an emergency engine under this subpart and must meet all requirements for non-emergency engines. The RICE MACT does not limit emergency operation of the engine as specified in §63.6640 f(1). RECORDKEEPING AND REPORTING Maintenance records, records of hours of operation recorded via the non-resettable hour meter, hours of operation for emergency, non-emergency, and demand response operations, and records of the notification of an emergency situation shall be maintained for each of the engines. No reports are required under this subpart for emergency engines as long as the engines do not meet the requirements found in §63.6650(h). However, for Title V purposes a semi-annual periodic monitoring report (PMR) would be required to report deviations during each monitoring period.


Page 19

40 CFR 64, “C OMPLIANCE ASSURANCE MONITORING (CAM)”

The emergency generator engines would not be subject to the requirements of CAM since they do not have an emission standard/limitation they are required to comply with.

EMERGENCY ENGINE EMISSIONS

The potential emissions from the emergency engines are provided in the table below. The units are emergency and they are typically only operated during readiness testing and maintenance periods (non-emergency hours); however, the facility is allowed to operate engines continuously during emergency; therefore, the emissions are based on continuous operation.

EMERGENCY ENGINE POTENTIAL EMISSIONS (TPY)

PM2.5/10 SO2 NOX CO VOC Total

HAPs CO2e

FIRE PUMP A & B 5.519 5.168 77.964 16.819 6.307 0.041 2,891.238

Power Gen A 3.767 3.504 52.954 11.432 4.292 0.028 1,964.43

Power Gen B 1.621 1.489 22.557 4.862 1.840 0.012 836.142

TOTAL ENGINE EMISSIONS 10.906 10.162 153.475 33.113 12.439 0.081 5,691.810


Page 20

SIMPLE CYCLE COMBUSTION TURBINE REQUIREMENTS

The three simple cycle combustion turbines (SCCT) are used to generate electricity at the plant.

EMISSION POINT DESCRIPTION POLLUTANT EMISSION

L IMIT† REGULATIONS

INDIVIDUAL SOURCES

ZAN-8902A

ZAN-8902B

ZAN-8902C

Three (3) 5,000 BHP, US Turbine Corporation, UST-3800 (K01-KB5), simple cycle combustion turbines (SCCT)

CO 5.0 Lbs/Hour 335-3-14-.04(9) [PSD/BACT Limit]

NOx

27.9 Lbs/Hour

AND

Not to exceed >150 ppmv @15% O2, dry basis

OR as calculated using the

equation in §60.332(a)(2)

335-3-14-.04(9) [PSD/BACT Limit] §60.332(a)(2) and (c), [NSPS GG]

SO2

S

1.4 Lbs/Hour AND

<150 ppmv @15% O2, dry basis OR

Sulfur content in the fuel gas shall not exceed 0.8% by weight (8,000 ppmw)

335-3-14-.04(9) [PSD/BACT Limit] §60.333(a), [NSPS GG]

§60.333(b), [NSPS GG]

H2S Fuel gas H2S content shall not exceed 10 grains/100

Scf

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

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)


The turbines’ applicability to the state and federal regulations will be discussed in the following section.

STATE REGULATIONS

Applicability :


Each turbine engine would be subject to these regulations; however, since natural gas is burned as fuel in the turbine ENGINES the actual PM emissions should be negligible. Therefore, no monitoring would be required. Provided that visible emissions are observed from the turbines, Method 9 or Method 22 of 40 CFR 60 Subpart A would be utilized to determine opacity from these units.


Page 21

Applicability:


The facility underwent a PSD review and accepted BACT limits for CO, NOX, SO2 emissions on the turbine engines.

EMISSION STANDARDS

Emissions limits for each of the turbines can be found on the summary page of the SCCT engine section of this document.


To demonstrate compliance with the PSD/BACT limits established for NOX and CO emissions the following requirements shall be meet:

Periodic testing shall be conducted using the following methods and procedures:

• EPA’s “Conditional Test Method (CTM-034)” • 40 CFR Part 60 Appendix A, Method 19

Performance testing shall be conducted using the following methods and procedures:

• For NOX emissions, the methods and procedures specified in §60.335(a), which are used to demonstrate compliance with NSPS GG by determining the NOX concentration in the exhaust gas, shall be used to calculate NOX emissions (Lbs/hr) from each turbine engine.

• For CO emissions, the following methods and procedures shall be used to demonstrate compliance with the PSD/BACT Limits:

o 40 CFR Part 60 Appendix A, Method 10 or 10A or 10B

o Method ASTM D6522-00, as incorporated in §60.17

o Other methodology approved by the Department

To demonstrate compliance with the fuel gas limit and the PSD/BACT SO2 limit, the facility is required to sample the fuel gas for its H2S content gas using one of the following methods and procedures:

• ASTM Analysis Method D1072-80 • ASTM Analysis Method D 3031-81 • ASTM Analysis Method D 4084-82 • ASTM Analysis Method D 3246-81 • Chromatographic analysis or an equivalent method • Other methods approved by the Department

The fuel gas shall be tested for it Btu heat content by utilizing the ASTM Analysis Method D1826-77 or an equivalent method.


Except as allowed by the permit, the facility must conduct performance testing at least once every 5 years and periodic testing at least once every 6 months on the turbine engines in order to


Page 22

demonstrate compliance with the PSD/BACT Limits. Sampling of the fuel gas for its Btu heat content is also required no less than once every six (6) months.


Records of deviations, results of performance and periodic tests, fuel gas heat content, fuel gas H2S content, fuel gas consumption, turbine heat input, operating hours and turbine emissions shall be maintained. A periodic monitoring report (PMR) is required to cover a semi-annual calendar basis and must be submitted to the Department within 30 days of the ending of the reporting period. If applicable an Excess Emission Report shall be submitted as specified in §60.7(c) and §60.634(j).

FEDERAL REGULATIONS


Applicability:


Provided that the turbines are subject to one of the applicable subparts found under this part, the facility shall comply with this subpart as specified in the applicable subpart.

Applicability:

40 CFR 60 Subpart GG, “Standards of Performance for Gas Turbines” [NSPS GG]

The three SCCT located at the plant, are subject to the requirements of this subpart since they have a heat input at peak load equal to or greater than 10 MMBtu/hr (calculated heat input of 48.2 MMBtu/hr), they were constructed after October 3, 1977, and they have not been reconstructed or modified on or before February 18, 2005. EMISSIONS STANDARDS

Nitrogen Oxide (NOX )Emissions

To demonstrate compliance with NSPS GG the turbines are required to either maintain NOX emissions at less than or equal to 150 part per million (ppmv) (calculated in the May 2, 2011 Statement of Basis for this facility; originated during proposed changes to the plant see August 8, 1990 correspondence) or below the allowable calculated using the equation below as found in §60.332(a)(2).

��%�� =

0.0150 �14.4�� + �

where, STD= allowable NOx emission concentration (percent by volume at 15% oxygen and on a dry basis. To convert from % by volume to ppmv, multiply your % by volume by 10,000. Y= manufacturer's rated heat rate at manufacturer's rated peak load (kilojoules per watt hour), or actual measured heat rate based on lower heating value of fuel as measured at actual peak load for the facility. The value of Y shall not exceed 14.4 kilojoules per watt hour.


Page 23

F = NOX emission allowance for fuel-bound nitrogen as defined in §60.332(a)(4). The use of F in the equation is optional as specified in §60.332(a)(3). Sulfur dioxide (SO2) Emissions

The facility is required to comply with NSPS GG, the SO2 emissions standards found in §60.633(a) which requires that the fuel gas burned in the turbine engines does not discharge any gases which contains a sulfur content in excess of 150 ppmv of SO2 corrected to 15% oxygen on a dry basis or §60.633(b) which requires that the fuel gas sulfur content does not exceed 0.8% by weight (8,000 ppmv). The facility elected to demonstrate compliance with the SO2 emission standards by burning natural gas, as defined in §60.331(u), as fuel in the turbine engines. To demonstrate that the fuel gas burned in the turbines meets one of the standards, the facility either uses sales gas produced at the plant or purchased buyback gas from its end user. The sales gas is monitored for its H2S content continuously to demonstrate that the H2S content is less than 4 ppmv as required by the plant. Also the fuel gas is sampled once every 6 months for its sulfur content. Compliance with the PSD/BACT fuel gas limit which requires that the facility burn a fuel gas in the turbines with a maximum H2S content of 10 grains/100 Scf shall also demonstrate compliance with this subpart for SO2 emissions. COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES

To comply with NSPS GG for NOX emissions, the facility is required to conduct performance testing on each turbine engine to determine the NOX concentration in the fuel gas utilizing the methods and procedures found in §60.335(a). To comply with NSPS GG and the PSD/BACT Emission limit for SO2 emissions, the facility elected to sample the fuel gas burned in each turbine engine using one of the following methods to determine the sulfur content: ASTM Analysis Method D1072-80 or ASTM Analysis Method D 3031-81 or ASTM Analysis Method D 4084-82 or ASTM Analysis Method D 3246-81 or chromatographic analysis or equivalent method. EMISSIONS MONITORING

For emission monitoring, the facility is required to conduct performance testing as required in §60.335 for each of the turbines to determine the NOX concentration in the fuel gas at least once every five years as specified in §60.334(h)(2). To demonstrate compliance with the SO2 emission standards the facility is required to burn only natural gas in the turbine engines and test the fuel gas for its sulfur content at a frequency of no less than once every 6 months to show that that H2S content in the fuel gas is less than the allowable. The flow rate and/or parameters utilized for flow rate calculations of the fuel gas used in the turbine engines shall be measured and recorded continuously. RECORDKEEPING AND REPORTING REQUIREMENTS

Records of the performance testing, fuel gas sampling, and excess emission shall be maintained to demonstrate compliance with this subpart. A semi-annual report is required to report excess emission events to the Department.

Applicability:

40 CFR 60 Subpart KKKK, “Standards of Performance for Stationary Combustion Turbines” [NSPS KKKK]

The turbines would not be subject to the requirements of this subpart since they were constructed on or before February 18, 2005 and they have not been modified or reconstructed since that date.


Page 24


Applicability:


Provided that the turbines are subject to one of the applicable subparts found under this part, the facility shall comply with this subpart as specified in the applicable subpart.

Applicability:

40 CFR 63, Subpart YYYY, “National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines”

The turbines would not be subject to the requirements of this subpart since they are not located at a major source of HAP emissions.


The turbine engines would not be subject to the requirements of CAM since they are not equipped with a control device to meet an emission standard/limitation.

TURBINE EMISSIONS

TURBINE ENGINE POTENTIAL EMISSIONS (TPY)

PM2.5/10 SO2 NOX CO VOC Total

HAPs CO2e

ZAN-8902A (TURBINE A)

1.39 6.13 122.20 21.90 0.44 0.211 23,225.41

ZAN-8902B. (TURBINE B) 1.39 6.13 122.20 21.90 0.44 0.211 23,225.41

ZAN-8902C (TURBINE C)

1.39 6.13 122.20 21.90 0.44 0.211 23,225.41

TOTAL TURBINE EMISSIONS 4.17 18.39 366.6 65.7 1.32 0.633 69,676.23


Page 25

TEG DEHYDRATION UNIT REQUIREMENTS

Applicable requirements for the tri-ethylene glycol (TEG) dehydration units are found in the following table:


LIMIT REGULATIONS

TEG-A TEG-B

Tri-ethylene Glycol (TEG) dehydration unit process vent HAPs

4,674 gph Max glycol

circulation rate

§63.760(b)(2); §63.764(d)(2)(ii)

The TEG dehydration units’ applicability to the state and federal regulations will be discussed in the following section.

STATE REGULATIONS

Applicability:


The OTF Plant has been deemed a major source of criteria pollutants and GHG emissions; therefore, the TEG units would be subject to the requirements of this regulation.

FEDERAL REGULATIONS


Applicability:


Provided that affected sources located at the plant are subject to one of the applicable subparts found under this part, the facility shall comply with this subpart as specified in the applicable subpart. The general provisions of this subpart shall be complied with as specified in §63.764(a) and Table 2 of Subpart HH.

Applicability:

40 CFR 63, Subpart HH, “National Emission Standards for Hazardous Air Pollutants from Oil and Natural Gas Production Facilities”

The OTF Plant is an area source of HAPs with respect to this subpart since it does not meet the major source definition under this subpart. An affected facility under this subpart for an area source of HAPs is each tri-ethylene glycol [TEG] dehydration unit. Since the OTF Plant is equipped with two TEG units, each would be subject to the requirements of this subpart. In the May 2, 2011 Statement of Basis the facility was determined to be located in an Urban-1 County; however, it was not located within an UA plus offset and UC Boundary as defined in §63.760.

GENERAL STANDARDS

The general standards specified in §63.764(d)(2) and provided below shall be met for the TEG dehydration unit.


Page 26

• The facility must determine the optimum glycol circulation rate using the following equation found in §63.764(d)(2)(i)

LOPT= 1.15 × 3.0 �� !"#$× % &×�'($�

)*+,/.�/0

where,

LOPT = Optimal circulation rate, gal/hr

F = Gas flowrate (MMSCF/D)

I = Inlet water content (lb/MMSCF)

O = Outlet water content (lb/MMSCF)

3.0 = The industry accepted rule of thumb for a TEG-to water ratio (gal TEG/lb H2O)

1.15 = Adjustment factor included for a margin of safety

• The TEG unit must be operated such that the actual glycol circulation rate does not

exceed the optimum circulation rate calculated using the equation above OR the facility must calculate an alternate circulation rate using GRI-GLYCalcTM, Version 3.0 or higher as required in §63.764(d)(2)(ii). The facility has chosen to establish an alternate circulation rate. Based on the April 21, 2008 Notification of Compliance Status (NOCS) submitted to the Department, the maximum glycol circulation rate is 4,674 gallons per hour (77.9 gallon per minute).

• At all times the owner or operator must 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 [§63.764(j)].


The plant is required to maintain a record of the determination specified in paragraph §63.764 (d)(2)(ii) in accordance with the requirements in §63.774(f) and submit the Initial Notification in accordance with the requirements in §63.775(c)(7) [63.774 (f)]. The initial notification was submitted on April 21, 2008. If operating conditions change and a modification to the optimum glycol circulation rate is required, the owner or operator shall prepare a new determination in accordance with paragraph §63.764(d)(2)(i) or (ii) of this section and submit the information specified under §63.775(c)(7)(ii) through (v) [§63.764(d)(2)(iii)]. If a notification of process change is required as a result of changes being made to the process or changes to the information submitted in the original Notification of Compliance Status Report, a report including the information in §63.775(f) should be submitted within 180 days after the change is made. For title V purposes the facility is required to submit BTEX emissions with their annual Title V fee inventory.

TEG DEHYDRATION UNIT EMISSIONS

TEG flash tank gases are routed to a vapor recovery unit and when the VRU is not operated the vapors are routed to the low pressure flare for combustion.


Page 27

SULFUR RECOVERY SYSTEM /THERMAL OXIDIZER REQUIREMENTS

The OTF plant is equipped with two sulfur recovery systems consisting of two trains each of which includes a sweetening unit, acid gas enrichment unit, sulfur recovery unit, tail gas clean-up unit and thermal oxidizer are found in the following table:


LIMIT REGULATIONS

Sulfur Recovery System, w/:

S-108 S-109

Sweetening Unit Acid Gas Enrichment Unit Sulfur Recovery Train No. A Sulfur Recovery Train No. B

CO

NOX

19.6 Lbs/Hr

18.8 Lbs/Hr

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

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

SO2 373.0 Lbs/Hr

and

% Sulfur Reduction Efficiency > the

calculated efficiency based on acid gas sulfur feed

(Ltons/day) and H2S Content

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

Rule 335-3-14-.04(9)(b) 40 CFR 60 Subpart LLL

(2) Sulfur Recovery Trains, Each w/:

Sulfur Recovery Unit Tail Gas Clean-up Unit Thermal Oxidizer Opacity


AND No 6 min avg. >

40%

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

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

H2S

Burn gas with 0.10 grains or more of

H2S/scf

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

20 ppbv offsite Rule 335-3-5-.03(2)

SO2 Oxidation Efficiency

98% Rule 335-3-14-.04(9)(b)

The sulfur recovery system’s applicability to the state and federal regulations will be discussed in the following section.

STATE REGULATIONS

Applicability :


The thermal oxidizers associated with each of the sulfur recovery units would be subject to the requirements of these regulations.


Page 28

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. EMISSIONS MONITORING

Provided that the sulfur plant is being operated and facility operating personnel notices that at any time visible emissions are observed from one of the thermal oxidizers in excess of the opacity standards, a visible emission observation shall be conducted. When Method 22 is used to determine the duration of emissions, the method has to be conducted by an individual who is familiar with the procedures. When Method 9 is used to determine opacity, it has to be conducted by an individual who is certified to use this procedure. Visual inspections and visible emissions observations are both required to be conducted during daylight hours. COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES

Method 9 or Method 22 found in 40 CFR 60, Appendix A would be used to demonstrate compliance with the opacity standards. RECORDKEEPING AND REPORTING REQUIREMENTS

A record of each occurrence when a visible emissions observation was conducted should be recorded and maintained. A deviation should be reported within 48 hours or 2 working days when a visible emissions event occurs.

Applicability:

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

The OTF Plant handles sour gas that contains 0.10 grains of hydrogen sulfide per standard cubic feet (H2S/scf) of gas or more the facility; therefore, the thermal oxidizers are used to comply with these regulations.

EMISSIONS STANDARDS

The thermal oxidizer is required to burn sour gas in order to maintain the ground level concentrations of hydrogen sulfide (H2S) at less than twenty part per billion beyond the plant property limits, average over a thirty (30) minute period. Venting to atmosphere shall not exceed 15 continuous minutes while vessels or equipment are being depressured and/or emptied and the reduced pressure will not allow flow of the process gas to the combustion device.


Compliance is met by burning or recycling to the process all process gas that can be vented to atmosphere. Since the thermal oxidizers are subject to CAM, the monitoring plan under CAM which requires the facility to maintain a minimum firebox temperature will also be used to demonstrate compliance with the requirement to burn.


Page 29


A record of events when a process gas stream was not burned in the facility flare or thermal oxidizers or when venting occurred for greater than 15 minutes shall be maintained.

Because each amine sweetening unit followed by a SRU is subject to the requirements of 40 CFR 60 Subpart LLL the requirements found in ADEM Admin. Code r. 335-3-5-.03(3) would not be applicable to these units. Compliance with subpart LLL shall demonstrate compliance with this state regulation. Per ADEM Admin. Code R. 335-3-10(2), NSPS emission standards supersedes the emission standards in this chapter.

Applicability:


As mentioned previously, the OTF Plant is a 100 TPY source with respect to PSD because the facility is equipped with a sulfur recovery plant. In order to comply with Best Available Control Technology (BACT) requirements the facility accepted sulfur recovery efficiency limits that were more stringent than those specified in 40 CFR 60 Subpart LLL, they accepted BACT limits for carbon monoxide (CO), nitrogen oxide (NOX) and sulfur dioxide (SO2) emissions, and they accepted a minimum oxidation efficiency for the thermal oxidizer. Compliance with PSD/BACT requirements shall demonstrate compliance with NSPS LLL.

EMISSION STANDARDS

• In order to determine the minimum sulfur recovery reduction efficiency (%) limits the facility is required to use the table below instead of Table 1 and 2 found in NSPS LLL.

ACID GAS H2S Content (Y) [Mole %]

SULFUR FEED (X) [LTON/DAY]

X < 2.0 2.0 ≤ X ≤ 15.0 15.0 < X

Y ≥ 1 0.0% 100-(15.0)(Y)-0.37 % Lesser of 100-(9.7)(Y)-0.99 %

—OR—99.8% Y < 1 0.0% 79.0% 79.0%

• At least 98% of the sulfur compounds leaving each thermal oxidizer shall be emitted as

SO2.

• The PSD/BACT limits for SO2, NOX, CO are found on the summary section of the Sulfur Recovery System Requirements.


The sulfur recovery reduction efficiency shall be determined using the following equations:

Sulfur recovery reduction efficiency (%) = 100 ×[2%3456789: 0×),)*<% 3=7

345670×>?89:

#@A5BC7D(�%3=7A5BC0]

[2%3456789: 0×),)*<% 3=7345670×>

?89:#@A5BC7D]

where X is defined as the sulfur feed rate (rate at which sulfur compounds enter the sulfur recovery system in long tons per day (LTD)) and E is defined as the sulfur compound emission rate (rate at which sulfur compounds are emitted from the thermal oxidizer) which is determined during performance testing.


Page 30

The sulfur feed rate (X) shall be determined using the following equation:

X [Sulfur feed rate (LTD)] =F × G� × �

where,

the constant K =3.707 x 10-5 in units of long tons per dry standard cubic feet (LTon/dScf)

Qa= the average volumetric flow rate of acid gas from sweeting unit in units of dScf/day

Y= the average H2S concentration in acid gas feed from sweetening unit, percent by volume, expressed as a decimal

The minimum oxidation efficiency shall be determined based on the combined TRS concentrations in the thermal oxidizer stack. If the TRS concentration is less than or equal to 5 part per million volume (ppmv), the oxidation efficiency is 98%; however, if the TRS concentration is greater than 5 ppmv the oxidation efficiency shall be calculated as follows:

Oxidation Efficiency% =100% × [�HI��J$#% 3=7K5BC0(�LJ%

3=7K5BC0]

�HI��J$#% 3=7K5BC0

where,

TRS= Thermal Oxidizer Stack total reduced sulfur emissions, determined during Each stack test.

Total SO2= Thermal Oxidizer stack SO2 Emissions, determined during each stack test.

Performance testing to determine SO2, CO, NOX and TRS emission rates is required to be conducted using the following methods and procedures:

• 40 CFR Part 60 Appendix A, Method 1 or 1a • 40 CFR Part 60 Appendix A, Method 2 or 2A or 2B or 2C or 2D or 2E • 40 CFR Part 60 Appendix A, Method 3 or 3A or 3B or 3C • 40 CFR Part 60 Appendix A, Method 4 • 40 CFR Part 60 Appendix A, Method 6 or 6A or 6B or 6C • 40 CFR Part 60 Appendix A, Method 7 or 7A or 7B or 7C or 7D or 7E • 40 CFR Part 60 Appendix A, Method 10 or 10A or 10B • 40 CFR Part 60 Appendix A, Method 15 • 40 CFR Part 60 Appendix A, Method 16A or 15

EMISSIONS MONITORING Monitoring to determine the sulfur recovery reduction efficiency requires determining the sulfur feed rate once every 24 hours, determining the average acid gas volumetric flowrate from the sweetening unit (using a continuous flowmeter) averaged and recorded at least once per hour during each 24 hour period, and determining the average acid gas H2S concentration in the flow from the sweetening unit once every 24 hours at equal intervals. The sulfur emission rate, is required to be determined during performance testing which is conducted at least once every 12 months. Performance testing requires three, one hour runs to determine SO2, CO, NOX and TRS emission rates (in units of Lbs/hr). RECORDKEEPING AND REPORTING REQUIREMENTS

During each of the performance test runs the thermal oxidizer’s firebox temperature is required to be recorded and emissions from each thermal oxidizer shall be measured and recorded simultaneously. Records of each deviation, each performance test, each shutdown and startup of the gas sweetening unit, acid gas enrichment unit, sulfur recovery unit, tail gas treating unit and


Page 31

thermal oxidizer shall be maintained. Records of the three hour rolling average CMS calculation of the sulfur recovery efficiency, sulfur dioxide emissions and thermal oxidizer firebox temperatures, and records of periods when high sulfur gas exists are required to be maintained. Periodic Monitoring Reports (PMR) and Excess Emissions and CMS Performance and Summary Reports are required to cover a calendar semi-annual period and shall be submitted within 30 days of the end of the reporting period.

Applicability:


The sulfur recovery systems would be subject to the requirements of this regulation since they are located at a major source facility. To comply with the requirements of this regulation the facility is required to monitor and record the emissions from the sulfur recovery system.

FEDERAL REGULATIONS


Applicability:



Applicability:

40 CFR 60 Subpart LLL, “Standards of Performance for Onshore Natural Gas Processing: SO2

emissions” [NSPS LLL]

The two amine sweetening units each followed by a sulfur recovery unit (SRU) (S-108 and S-109) would be subject to the requirements of this subpart; however, as stated above the facility elected to comply with more stringent sulfur emission requirements under PSD regulations. §60.10(a) allows compliance with other requirements as long as the emission limitations and/or requirements are at least as stringent or more stringent than what is allowed. Compliance with the PSD/BACT limits will demonstrate compliance with this subpart. The test methods and procedures specified in §60.644, the monitoring requirements specified in §60.646, and the recordkeeping and reporting requirements specified in §60.647 must also be meet to demonstrate compliance with this subpart.


Applicability:

The requirement to burn off gases is considered to be a work practice and not an emission limitation. As defined in the CAM regulation, an emission limitation may be expressed in the form of a work practice, process parameter, or other form of specific design. Thus CAM is applicable and shall be utilized to ensure compliance with the requirement to burn the off gases


Page 32

The thermal oxidizers at the facility are utilized as control devices to burn gas containing greater than 0.10 grains of H2S/Scf.

EMISSION STANDARDS

The firebox temperature shall be maintained at greater than or equal to 1,210 oF for the S-108 unit and greater than or equal to 1,090 oF for the S-109 unit. COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES

The firebox temperature will be monitored continuously with a thermocouple or equivalent device.

EMISSIONS MONITORING The firebox temperature will be monitored continuously using a continuous emissions monitoring system (CEMS). RECORDKEEPING AND REPORTING REQUIREMENTS

A record of the hourly average and three-hour rolling average firebox temperature shall be maintained. A record of the time, date and results of each calibration shall be maintained if a thermocouple is being used. Each occurrence when the three-hour rolling average firebox temperature is less than the allowable shall be reported as a deviation. If the accumulated hours of deviation events occurring exceed 5% of the thermal oxidizer’s operating time during any quarterly reporting period, a Quality Improvement Plan (QIP) shall be developed and implemented.

SRU/THERMAL OXIDIZER POTENTIAL EMISSIONS

SRU/TO POTENTIAL EMISSIONS

EMISSION SOURCE

(TPY)

PM2.5/10 SO2 NOX CO VOC TOTAL HAP CO2e

S-108/109 0.86 1,633.74 82.34 85.85 0.62 0.213 13,578.00


Page 33

FLARE REQUIREMENTS

EMISSION POINT # DESCRIPTION POLLUTANT

EMISSION LIMIT REGULATIONS

F101 F102

High Pressure Emergency Flare Low Pressure Emergency Flare

H2S Burn gas with 0.10 grains or more of H2S/Scf of gas

<20 ppbv offsite concentration

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

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

SO2 No Limit provided that the Available Sulfur is less than or equal to 5 LTD

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

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)

The flares' applicability to the state and federal regulations will be discussed in the following section.

STATE REGULATIONS

Applicability :


The emergency flares would be subject to the requirements of these regulations.

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. EMISSIONS MONITORING

Provided that the flares are being utilized to burn a gas stream other than the pilot light fuel gas, and facility operating personnel notices that at any time visible emissions are observed from either of the flares in excess of the opacity standards, a visible emission observation shall be conducted. When Method 22 is used to determine the duration of emissions, the method has to be conducted by an individual who is familiar with the procedures. When Method 9 is used to determine opacity, it has to be conducted by an individual who is certified to use this procedure.


Page 34

Visual inspections and visible emissions observations are both required to be conducted during daylight hours. COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES

Method 9 or Method 22 found in 40 CFR 60, Appendix A would be used to demonstrate compliance with the opacity standards. RECORDKEEPING AND REPORTING REQUIREMENTS

A record of each occurrence when a visible emissions observation was conducted should be recorded and maintained. A deviation should be reported within 48 hours or 2 working days when a visible emissions event occurs.

Applicability:

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

The OTF Plant handles sour gas that contains 0.10 grains of hydrogen sulfide per standard cubic feet (H2S/scf) of gas or more the facility. The flares and thermal oxidizers are used to comply with this regulation.

EMISSIONS STANDARDS

The flares are required to burn sour gas in order to maintain the ground level concentrations of hydrogen sulfide (H2S) at less than twenty part per billion beyond the plant property limits, average over a thirty (30) minute period. Venting to atmosphere shall not exceed 15 continuous minutes while vessels or equipment are being depressured and/or emptied and the reduced pressure will not allow flow of the process gas to the combustion device.

According to ADEM Admin. Code R. 335-3-5-.03(3), provided that the available sulfur being processed at the plant is less than five (5) long tons per day (LTD), there is no limit on SO2 emissions.


Each process gas stream that can be routed to a flare shall be tested for its BTU and H2S Content.


Compliance is met by burning or recycling to the process all process gas that can be vented to atmosphere. Periodic monitoring to ensure that the offsite H2S concentration does not exceed 20 ppbv, is in the form of maintaining an assist gas to acid gas volume ratio at equal to or greater than 2.25 to 1.0.


A record of events when a process gas stream was not burned in the facility flares or thermal oxidizers, when venting occurred for greater than 15 minutes, and records of the assist gas to acid gas volume ratio shall be maintained.


Page 35

Applicability:


The flares would not be subject to the requirements of this regulation.

FEDERAL REGULATIONS

Applicability:


The requirement to burn off gases is considered to be a work practice and not an emission limitation. As defined in the CAM regulation, an emission limitation may be expressed in the form of a work practice, process parameter, or other form of specific design. Thus CAM is applicable and shall be utilized to insure compliance with the requirement to burn the off gases

The emergency flares at the facility are utilized as control devices to burn gas containing greater than 0.10 grains of H2S/Scf.

EMISSION STANDARDS

Presence of a spark or flame at the flare tip shall be maintained at all times when a process gas stream can be routed to the either of the emergency flares. COMPLIANCE AND PERFORMANCE TEST METHODS AND PROCEDURES

Provided a flame igniter or flame monitor is used each shall be maintained and calibrated as required by manufacturer’s specifications or other written procedures.

EMISSIONS MONITORING The flare tip shall either be equipped with a continuous sparking flame igniter that is monitored by an amp meter or an equivalent device, be equipped with a thermocouple or equivalent device to monitor a continuously burning pilot light, or monitored by visual observation. Calibrations of a flare monitor or flame igniter shall occur annually or as required by manufacturer’s specifications, whichever is more frequent. RECORDKEEPING AND REPORTING REQUIREMENTS

A record of the time, date and results of each occurrence when there was not a spark or flame present at the flare tip when a process gas stream could be routed to it, results of each visual observation (if required), results of each calibration, and any deviations and corrective actions taken. If the accumulated hours of deviation events occurring exceed 5% of the flares’ operating time during any quarterly reporting period, a Quality Improvement Plan (QIP) shall be developed and implemented.


Page 36

FLARE POTENTIAL EMISSIONS

FLARES POTENTIAL EMISSIONS

EMISSION SOURCES (TPY)

PM SO2 NOX CO VOC TOTAL HAPS CO2e

HP FLARE (F101) 0.85 307.32 7.94 43.20 0.61 0.209 13,344.98

LP FLARE (F102) 0.94 300.29 8.81 47.93 19.69 13.856 14,803.96

TOTAL FLARE EMISSIONS 1.79 607.61 16.75 91.13 20.3 14.065 28,148.94


Page 37

STORAGE TANK REQUIREMENTS



ABJ-4001 ABJ-4002 ABJ-4003 ABJ-4004 ABJ-9201 ABJ-9204 ABJ-9207 ABJ-201 ABJ-301 ABJ-6525

105,000 Gallon, Diesel Storage Tank 105,000 Gallon, Diesel Storage Tank 105,000 Gallon, Diesel Storage Tank 105,000 Gallon, Diesel Storage Tank 10,500 Gallon, Tri-ethylene Glycol Tank 10,500 Gallon, MDEA Storage Tank 10,500 Gallon, Flexsorb Storage Tank 60,500 Gallon, MDEA Storage Tank 37,500 Gallon, Flexsorb Storage Tank 147,000 Gallon, Diesel Storage Tank

H2S Burn gas with 0.10 grains or more of H2S/Scf of gas


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

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

The tanks' applicability to the state and federal regulations will be discussed in the following section.

STATE REGULATIONS

Applicability:

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

Provided that the vapors from the storage tanks contains a H2S concentration greater than 0.10 grains/Scf tank vapors must be burned. To comply with these regulations the facility has elected to equip each storage tank with a vapor recovery system to route the vapors to the flare for combustion or back through the process.

Applicability:

ADEM Admin. Code R. 335-3-6 “Control of Organic Emissions”

This chapter does not apply to sources that have a potential VOC emission rate of less than 100 tons per year [Rule 335-6-.01(1)(b)]. The storage tanks at this facility would not be subject to the requirements of this chapter since the VOC emissions from each tank would not exceed 100 tons per year.

Applicability:

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

Based on the type of material stored in the storage vessels, the emissions from each tank would be less than 5 TPY. Since the tanks are not subject to the requirements of a federal regulation they would be considered an insignificant source as defined in ADEM Admin. Code R. 335-3-16-.01(o). Insignificant activities are required to be listed in the permit application and calculations of emissions from these units provided.


Page 38

FEDERAL REGULATIONS


Applicability:



Applicability:

40 CFR Part 60 Subpart Kb, “Standards of Performance for Storage Vessels from Petroleum Liquids”

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. Each tank at the facility was constructed in 1992, with the exception of the ABJ-6525 tank which was constructed in 2009. Based on the design capacity for each tank and the maximum true vapor pressure (TVP) for each material stored in tank Nos. ABJ-4001, ABJ-4002, ABJ-4003, ABJ-4004, ABJ-201, ABJ-301 and ABJ-6525, this subpart would not be applicable to these tanks [§60.110b(b)].

Tanks ABJ-9201, 9204, and 9207 tanks do not meet the capacity requirements nor the max TVP requirements; therefore, they would not be subject to this subpart.


Vapors from these tanks are required to be burned provided that the H2S concentration is 0.10 grains/scf or more. Each tank is equipped with a vapor recovery system to route the vapors to the flare for combustion or back through the process. However, the pre-controlled emissions from a regulated air pollutants are not 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. Therefore, the storage vessels would not be subject to the requirements of this subpart

TANK POTENTIAL EMISSIONS

The emissions form the tanks are routed via a vapor recovery system to the facility flares for combustion.


Page 39

RECOMMENDATIONS

After reviewing ADEM’s Administrative Code of Regulations and the Code of Federal Regulations for newly promulgated and modified regulations, I recommend that ExxonMobil Production Company [A Division of Exxon Mobil Corporation] is issued a renewal for it Onshore Gas Treating Facility operating under Major Source Operating Permit (MSOP) No.: 503-4011. The facility addressed its applicability to new and modified regulations and should be able to meet the requirements of this permit and all federal and state requirements.

_________________________________ April 26, 2017 Harlotte Bolden-Wright Draft Date Air Division Energy Branch Industrial Minerals Section


Page 40

ATTACHMENT A: DRAFT PROVISOS

MAJOR SOURCE OPERATING PERMIT

Permitee: ExxonMobil Production Company [a Division of ExxonMobil Corporation]

Facility Name: Mobile Bay Onshore Gas Treating Facility

Facility No.: 503-4011

Location: 6000 Deakle Road; Mobile Co., Theodore, AL

In accordance with and subject to the provisions of the Alabama Air Pollution Control Act of 1971, as amended, Ala. Code 1975, §§22-28-1 to 22-28-23 (2006 Rplc. Vol.) (the "AAPCA") and the Alabama Environmental Management Act, as amended, Ala. Code 1975, §§22-22A-1 to 22-22A-15, (2006 Rplc. Vol.) and rules and regulations adopted thereunder, and subject further to the conditions set forth in this permit, the Permittee is hereby authorized to construct, install and use the equipment, device or other article described above.

Pursuant to the Clean Air Act of 1990, all conditions of this permit are federally enforceable by EPA, the Alabama Department of Environmental Management, and citizens in general. Those provisions which are not required under the Clean Air Act of 1990 are considered to be state permit provisions and are not federally enforceable by EPA and citizens in general. Those provisions are contained in separate sections of this permit.

Issuance Date: Draft April 26, 2017 Expiration Date: ????

Alabama Department of Environmental Management

Table of Contents

i

GENERAL PERMIT PROVISOS ........................................................................... 1

SUMMARY PAGE FOR UTILITY BOILERS ......................................................... 19

PROVISOS FOR UTILITY BOILERS .................................................................. 20

Applicability ..................................................................................................... 20

Emissions Standards ........................................................................................ 20

Compliance and Performance Test Methods and Procedures ............................... 21

Emission Monitoring ......................................................................................... 23

Record Keeping and Reporting Requirements ..................................................... 23

SUMMARY PAGE FOR THE EMERGENCY ENGINES .......................................... 27

PROVISOS FOR EMERGENCY ENGINES ........................................................... 28

Applicability ..................................................................................................... 28





SUMMARY PAGE FOR SIMPLE CYCLE COMBUSTION TURBINE ENGINES .......... 33

PROVISOS FOR SCCT ENGINES ...................................................................... 34

Applicability ..................................................................................................... 34





SUMMARY PAGE FOR THE SULFUR RECOVERY SYSTEM ................................. 45

PROVISOS FOR THE SULFUR RECOVERY SYSTEM .......................................... 46

Applicability ..................................................................................................... 46




Recordkeeping and Reporting Requirements ...................................................... 52

SUMMARY PAGE FOR EMERGENCY FACILITY FLARES .................................... 57

PROVISOS FOR EMERGENCY FACILITY FLARES ............................................. 58

Applicability ..................................................................................................... 58

Emission Standards .......................................................................................... 58




SUMMARY PAGE FOR TRI-ETHYLENE GLYCOL [TEG] DEHYDRATOR EMISSIONS .................................................................................................... 65

Table of Contents

ii

PROVISOS FOR TEG DEHYDRATOR UNIT EMISSIONS ..................................... 66

Applicability ..................................................................................................... 66




Recordkeeping and Reporting Requirements ...................................................... 67

APPENDIX A: UTILITY BOILER MONITORING .................................................. 69

APPENDIX B: SCCT ENGINE MONITORING ...................................................... 73

APPENDIX C: SULFUR RECOVERY SYSTEM MONITORING ............................... 77

APPENDIX D: EMERGENCY FLARES MONITORING .......................................... 83

1

General Permit Provisos

Federally Enforceable Provisos Regulations

1. Transfer

This permit is not transferable, whether by operation of law or otherwise, either from one location to another, from one piece of equipment to another, or from one person to another, except as provided in Rule 335-3-16-.13(1)(a)5.

Rule 335-3-16-.02(6)

2. Renewals

An application for permit renewal shall be submitted at least six (6) months, but not more than eighteen (18) months, before the date of expiration of this permit. The source for which this permit is issued shall lose its right to operate upon the expiration of this permit unless a timely and complete renewal application has been submitted within the time constraints listed in the previous paragraph.

Rule 335-3-16-.12(2)

3. Severability Clause

The provisions of this permit are declared to be severable and if any section, paragraph, subparagraph, subdivision, clause, or

phrase of this permit shall be adjudged to be invalid or unconstitutional by any court of competent jurisdiction, the judgment shall not affect, impair, or invalidate the remainder of this permit, but shall be confined in its operation to the section, paragraph, subparagraph, subdivision, clause, or phrase of this permit that shall be directly involved in the controversy in which such judgment shall have been rendered.

Rule 335-3-16-.05(e)

4. Compliance

(a) The permittee shall comply with all conditions of ADEM Admin. Code 335-3. Noncompliance with this permit will constitute a violation of the Clean Air Act of 1990 and ADEM Admin. Code 335-3 and may result in an enforcement action; including but not limited to, permit termination, revocation and reissuance, or modification; or denial of a permit renewal application by

the permittee.

Rule 335-3-16-.05(f)

(b) The permittee shall not use as a defense in an enforcement action that maintaining compliance with conditions of this permit would have required halting or reducing the permitted activity.

Rule 335-3-16-.05(g)

2



5. Termination for Cause

This permit may be modified, revoked, reopened, and reissued, or terminated for cause. The filing of a request by the permittee for a permit modification, revocation and reissuance, or termination, or of a notification of planned changes or anticipated noncompliance will not stay any permit condition.

Rule 335-3-16-.05(h)

6. Property Rights

The issuance of this permit does not convey any property rights of any sort, or any exclusive privilege.

Rule 335-3-16-.05(i)

7. Submission of Information

The permittee must submit to the Department, within 30 days or for such other reasonable time as the Department may set, any information that the Department may request in writing to determine whether cause exists for modifying, revoking and reissuing, or terminating this permit or to determine compliance with this permit. Upon receiving a specific request,

the permittee shall also furnish to the Department copies of records required to be kept by this permit.

Rule 335-3-16-.05(j)

8. Economic Incentives, Marketable Permits, and Emissions Trading

No permit revision shall be required, under any approved economic incentives, marketable permits, emissions trading and other similar programs or processes for changes that are

provided for in this permit.

Rule 335-3-16-.05(k)

9. Certification of Truth, Accuracy, and Completeness:

Any application form, report, test data, monitoring data, or compliance certification submitted pursuant to this permit shall contain certification by a responsible official of truth, accuracy, and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are

true, accurate and complete.

Rule 335-3-16-.07(a)

3



10. Inspection and Entry

Upon presentation of credentials and other documents as may be required by law, the permittee shall allow authorized representatives of the Alabama Department of Environmental Management and EPA to conduct the following:

Rule 335-3-16-.07(b)

(a) Enter upon the permittee’s premises where a

source is located or emissions-related activity is conducted, or where records must be kept pursuant to the conditions of this permit;

(b) Review and/or copy, at reasonable times, any

records that must be kept pursuant to the conditions of this permit;

(c) Inspect, at reasonable times, this facility’s

equipment (including monitoring equipment and air pollution control equipment), practices, or operations regulated or required pursuant to this permit;

(d) Sample or monitor, at reasonable times,

substances or parameters for the purpose of assuring compliance with this permit or other applicable requirements.

11. Compliance Provisions

(a) The permittee shall continue to comply with the

applicable requirements with which the company has certified that it is already in compliance.

Rule 335-3-16-.07(c)

(b) The permittee shall comply in a timely manner with applicable requirements that become effective during the term of this permit.

12. Compliance Certification

On, or before, ????? of each year, a compliance certification shall be submitted.

Rule 335-3-16-.07(e)

(a) The compliance certification shall include the following:

(1) The identification of each term or condition of this permit that is the basis of the certification;

4



(2) The compliance status;

(3) The method(s) used for determining the compliance status of the source, currently and over the reporting period consistent with Rule 335-3-16-.05(c) (Monitoring and Recordkeeping Requirements);

(4) Whether compliance has been continuous or intermittent;

(5) Such other facts as the Department may require to determine the compliance status of the source;

(b) The compliance certification shall be submitted to:

Alabama Department of Environmental Management Air Division

P.O. Box 301463 Montgomery, AL 36130-1463

and to:

Air and EPCRA Enforcement Branch EPA Region IV

61 Forsyth Street, SW Atlanta, GA 30303

13. Reopening for Cause

Under any of the following circumstances, this permit will be reopened prior to the expiration of the permit:

Rule 335-3-16-.13(5)

(a) Additional applicable requirements under the Clean Air Act of 1990 become applicable to the permittee with a remaining permit term of three (3) or more years. Such a reopening shall be completed not later than eighteen (18) months after promulgation of the applicable requirement. No such reopening is required if the effective date of the requirement is later than the date on which this permit is due to expire.

(b) Additional requirements (including excess emissions requirements) become applicable to an affected source under the acid rain program. Upon approval by the Administrator, excess emissions offset plans shall be deemed to be incorporated into this permit.

5



(c) The Department or EPA determines that this

permit contains a material mistake or that inaccurate statements were made in establishing the emissions standards or other terms or conditions of this permit.

(d) The Administrator or the Department determines that this permit must be revised or revoked to assure compliance with the applicable requirements.

14. Additional Rules and Regulations

This permit is issued on the basis of Rules and Regulations existing on the date of issuance. In the event additional Rules and Regulations are adopted, it shall be the permit holder’s responsibility to comply with such rules.

§22-28-16(d), Code of Alabama 1975, as

amended

15. Equipment Maintenance or Breakdown

(a) In the case of shutdown of air pollution control equipment (which operates pursuant to any permit issued by the Director) for necessary scheduled maintenance, the intent to shut down such equipment shall be reported to the Director at least twenty-four (24) hours prior to the planned shutdown, unless such shutdown is accompanied by the shutdown of the source which such equipment is intended to control. Such prior notice shall include, but is not limited to the following:

Rule 335-3-1-.07(1) & Rule 335-3-1-.07(2)

(1) Identification of the specific facility to be taken out of service as well as its location and permit number;

(2) The expected length of time that the air pollution control equipment will be out of service;

(3) The nature and quantity of emissions of air contaminants likely to occur during the shutdown period;

(4) Measures such as the use of off-shift labor and equipment that will be taken to minimize the length of the shutdown period;

(5) The reasons that it would be impossible or impractical to shut down the source operation during the maintenance period.

6



(b) In the event that there is a breakdown of equipment or upset of process in such a manner as to cause, or is expected to cause, increased emissions of air contaminants which are above an applicable standard, the person responsible for such equipment shall notify the Director within 24 hours or the next working day and provide a statement giving all pertinent facts, including the estimated duration of the breakdown. The Director

shall be notified when the breakdown has been corrected.

16. Operation of Capture and Control Devices

All air pollution control devices and capture systems for which this permit is issued shall be maintained and operated at all times in a manner so as to minimize the emissions of air contaminants. Procedures for ensuring that the above equipment is properly operated and maintained so as to minimize the emission of air contaminants shall be established.

§22-28-16(d), Code of

Alabama 1975, as amended

17. Obnoxious Odors

This permit is issued with the condition that, should obnoxious odors arising from the plant operations be verified by Air Division inspectors, measures to abate the odorous emissions shall be taken upon a determination by the Alabama Department of Environmental Management that these measures are technically and economically feasible.

Rule 335-3-1-.08

18. Fugitive Dust

(a) Precautions shall be taken to prevent fugitive dust emanating from plant roads, grounds, stockpiles, screens, dryers, hoppers, ductwork, etc.

Rule 335-3-4-.02

(b) Plant or haul roads and grounds will be maintained in the following manner so that dust will not become airborne. A minimum of one, or a combination, of the following methods shall be utilized to minimize airborne dust from plant or haul roads and grounds:

(1) By the application of water any time the surface of the road is sufficiently dry to allow the creation of dust emissions by the act of wind or vehicular traffic;

7



(2) By reducing the speed of vehicular traffic to

a point below that at which dust emissions are

created;

(3) By paving;

(4) By the application of binders to the road surface at any time the road surface is found to allow the creation of dust emissions;

Should one, or a combination, of the above methods fail to

adequately reduce airborne dust from plant or haul roads and grounds, alternative methods shall be employed, either exclusively or in combination with one or all of the above control techniques, so that dust will not become airborne. Alternative methods shall be approved by the Department prior to utilization.

19. Additions and Revisions

Any modifications to this source shall comply with the modification procedures in Rules 335-3-16-.13 or 335-3-16-.14.

Rule 335-3-16-.13 & Rule 335-3-16-.14

20. Recordkeeping Requirements

(a) Records of required monitoring information of the source shall include the following:

Rule 335-3-16-.05(c)(2)

(1) The date, place, and time of all sampling or measurements;

(2) The date analyses were performed;

(3) The company or entity that performed the analyses;

(4) The analytical techniques or methods used;

(5) The results of all analyses; and

(6) The operating conditions that existed at the time of sampling or measurement.

(b) Retention of records of all required monitoring data and support information of the source for a period of at least 5 years from the date of the monitoring sample, measurement, report, or application. Support information includes all calibration and maintenance

8



records and all original strip-chart recordings for continuous monitoring instrumentation and copies of all

reports required by the permit.

21. Reporting Requirements

(a) Reports to the Department of any required monitoring shall be submitted at least every 6 months. All instances of deviations from permit requirements must be clearly identified in said reports. All required reports must be certified by a responsible official consistent with Rule 335-3-16-.04(9).

Rule 335-3-16-.05(c)(3).

(b) Deviations from permit requirements shall be reported within 48 hours or 2 working days of such deviations, including those attributable to upset conditions as defined in the permit. The report will include the probable cause of said deviations, and any corrective actions or preventive measures that were taken.

22. Emission Testing Requirements

Each point of emission which requires testing will be provided with sampling ports, ladders, platforms, and other safety equipment to facilitate testing performed in accordance with procedures established by Part 60 of Title 40 of the Code of Federal Regulations, as the same may be amended or revised.

Rule 335-3-1-.05(3) & Rule 335-3-1-.04(1)

The Air Division must be notified in writing at least 10 days in advance of all emission tests to be conducted and submitted as proof of compliance with the Department’s air pollution control rules and regulations. To avoid problems concerning testing methods and procedures, the following shall be included with the notification letter:

(1) The date the test crew is expected to arrive, the date and time anticipated of the start of the first run, how many and which sources are to be tested, and the names of the persons and/or testing company that will conduct the tests.

Rule 335-3-1-.04

(2) A complete description of each sampling train to be used, including type of media used in determining gas stream components, type of probe lining, type of filter media, and probe cleaning method and solvent to be used (if test procedures require probe cleaning).

9



(3) A description of the process(es) to be tested

including the feed rate, any operating parameters used to control or influence the operations, and the rated capacity.

(4) A sketch or sketches showing sampling point locations and their relative positions to the nearest upstream and downstream gas flow disturbances.

A pretest meeting may be held at the request of the source

owner or the Air Division. The necessity for such a meeting and the required attendees will be determined on a case-by-case basis.

All test reports must be submitted to the Air Division within 30 days of the actual completion of the test unless an extension of time is specifically approved by the Air Division.

Rule 335-3-1-.04

23. Payment of Emission Fees

Annual emission fees shall be remitted each year according to the fee schedule in ADEM Admin. Code R. 335-1-7-.04.

Rule 335-1-7-.04

24. Other Reporting and Testing Requirements

Submission of other reports regarding monitoring records, fuel analyses, operating rates, and equipment malfunctions may be required as authorized in the Department's air pollution control rules and regulations. The Department may require emission testing at any time.

Rule 335-3-1-.04(1)

25. Title VI Requirements (Refrigerants)

Any facility having appliances or refrigeration equipment, including air conditioning equipment, which use Class I or Class II ozone-depleting substances as listed in 40 CFR Part 82, Subpart A, Appendices A and B, shall service, repair, and maintain such equipment according to the work practices, personnel certification requirements, and certified recycling and recovery equipment specified in 40 CFR Part 82, Subpart F.

No person shall knowingly vent or otherwise release any Class I or Class II substance into the environment during the repair, servicing, maintenance, or disposal of any device except as provided in 40 CFR Part 82, Subpart F. The responsible official shall comply with all reporting and recordkeeping requirements of 40 CFR 82.166. Reports shall

40 CFR Part 82

10



be submitted to the US EPA and the Department as required.

26. Chemical Accidental Prevention Provisions

If a chemical listed in Table 1 of 40 CFR Part 68.130 is present in a process in quantities greater than the threshold quantity listed in Table 1, then: (a) The owner or operator shall comply with the

provisions in 40 CFR Part 68. (b) The owner or operator shall submit one of the

following:

(1) A compliance schedule for meeting the requirements of 40 CFR Part 68 by the date provided in 40 CFR Part 68 § 68.10(a) or,

(2) A certification statement that the source is

in compliance with all requirements of 40 CFR Part 68, including the registration and submission of the Risk Management Plan.

40 CFR Part 68

27. Display of Permit

This permit shall be kept under file or on display at all times at the site where the facility for which the permit is issued is located and will be made readily available for inspection by any or all persons who may request to see it.

Rule 335-3-14-.01(1)(d)

28. Circumvention

No person shall cause or permit the installation or use of any device or any means which, without resulting in reduction in the total amount of air contaminant emitted, conceals or dilutes any emission of air contaminant which would otherwise violate the Division 3 rules and regulations.

Rule 335-3-1-.10

29. Visible Emissions

Unless otherwise specified in the Unit Specific provisos of this permit, any source of particulate emissions shall not discharge more than one 6-minute average opacity greater than 20% in any 60-minute period. At no time shall any source discharge a 6-minute average opacity of particulate emissions greater than 40%. Opacity will be determined by 40 CFR Part 60, Appendix A, Method 9, unless otherwise specified in the Unit Specific

provisos of this permit.

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

11



30. Fuel-Burning Equipment

(a) Unless otherwise specified in the Unit Specific provisos of this permit, no fuel-burning equipment may discharge particulate emissions in excess of the emissions specified in Part 335-3-4-.03.

(b) Unless otherwise specified in the Unit Specific

provisos of this permit, no fuel-burning equipment may discharge sulfur dioxide emissions in excess of the emissions specified in Part 335-3-5-.01.

Rule 335-3-4-.03

Rule 335-3-5-.01

31. Process Industries – General

Unless otherwise specified in the Unit Specific provisos of this permit, no process may discharge particulate emissions in excess of the emissions specified in Part 335-3-4-.04.

Rule 335-3-4-.04

32. Averaging Time for Emission Limits

Unless otherwise specified in the permit, the averaging time for the emission limits listed in this permit shall be the nominal

time required by the specific test method.

Rule 335-3-1-.05

33. Compliance Assurance Monitoring (CAM)

Conditions (a) through (d) that follow are general conditions applicable to emissions units that are subject to the CAM requirements. Specific requirements related to each emissions unit are contained in the unit specific provisos and the attached CAM appendices.

(a) Operation of Approved Monitoring 40 CFR 64.7

(1) Commencement of operation. The owner or operator shall conduct the monitoring required under this section and detailed in the unit specific provisos and CAM appendix of this permit (if required) upon issuance of the permit, or by such

later date specified in the permit pursuant to §64.6(d).

(2) Proper maintenance. At all times, the owner or operator shall maintain the monitoring, including but not limited to, maintaining necessary parts for routine repairs of the monitoring equipment.

12



(3) Continued operation. Except for, as applicable,

monitoring malfunctions, associated repairs, and required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments), the owner or operator shall conduct all monitoring in continuous operation (or shall collect data at all required intervals) at all times that the pollutant-specific emissions unit is operating. Data recorded during monitoring malfunctions, associated

repairs, and required quality assurance or control activities shall not be used for purposes of this part, including data averages and calculations, or fulfilling a minimum data availability requirement, if applicable. The owner or operator shall use all the data collected during all other periods in assessing the operation of the control device and associated control system. A monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid data. Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunctions.

(4) Response to excursions or exceedances.

(a) Upon detecting an excursion or exceedance, the owner or operator shall restore operation of the pollutant-specific emissions unit (including the control device and associated capture system) to its normal or usual manner of operation as expeditiously as practicable in accordance with good air pollution control practices for minimizing

emissions. The response shall include minimizing the period of any startup, shutdown or malfunction and taking any necessary corrective actions to restore normal operation and prevent the likely recurrence of the cause of an excursion or exceedance (other than those caused by excused startup or shutdown conditions). Such

actions may include initial inspection and evaluation, recording that operations returned to normal without operator action (such as through response by a computerized distribution control system), or any necessary follow-up actions to return operation to within the indicator range, designated condition, or below the applicable emission limitation or standard, as applicable.

13



(b) Determination of whether the owner or

operator has used acceptable procedures in response to an excursion or exceedance will be based on information available, which may include but is not limited to, monitoring results, review of operation and maintenance procedures and records, and inspection of the control device, associated capture system, and the process.

(5) Documentation of need for improved monitoring. After approval of monitoring under this part, if the owner or operator identifies a failure to achieve compliance with an emission limitation or standard for which the approved monitoring did not provide an indication of an excursion or exceedance while providing valid data, or the results of compliance or performance testing document a need to modify the existing indicator ranges or designated conditions, the owner or operator shall promptly notify the Department and, if necessary, submit a proposed modification to the permit to address the necessary monitoring changes. Such a modification may include, but is not limited to, reestablishing indicator ranges or

designated conditions, modifying the frequency of conducting monitoring and collecting data, or the monitoring of additional parameters.

(b) Quality Improvement Plan (QIP) Requirements 40 CFR 64.8

(1) Based on the results of a determination made under Section 33(a)(4)(b) above, the Administrator

or the permitting authority may require the owner or operator to develop and implement a QIP. Consistent with 40 CFR §64.6(c)(3), the permit may specify an appropriate threshold, such as an accumulation of exceedances or excursions exceeding 5 percent duration of a pollutant-specific emissions unit's operating time for a

reporting period, for requiring the implementation of a QIP. The threshold may be set at a higher or lower percent or may rely on other criteria for purposes of indicating whether a pollutant-specific emissions unit is being maintained and operated in a manner consistent with good air pollution control practices.

14



(2) Elements of a QIP:

(i) The owner or operator shall maintain a written QIP, if required, and have it available for inspection.

(ii) The plan initially shall include procedures for evaluating the control performance problems and, based on the results of the evaluation procedures, the owner or operator shall modify the plan to include procedures for conducting one or more of the following actions, as appropriate:

(I) Improved preventive maintenance practices.

(II) Process operation changes.

(III) Appropriate improvements to control methods.

(IV) Other steps appropriate to correct control performance.

(V) More frequent or improved monitoring (only in conjunction with one or more steps under paragraphs (2)(b)(ii)(I) through (IV) above).

(3) If a QIP is required, the owner or operator shall develop and implement a QIP as expeditiously as practicable and shall notify the Department if the period for completing the improvements contained in the QIP exceeds 180 days from the date on which the need to implement the QIP was

determined.

(4) Following implementation of a QIP, upon any subsequent determination pursuant to Section 33(a)(4)(b) above, the Department may require that an owner or operator make reasonable changes to the QIP if the QIP is found to have:

(i) Failed to address the cause of the control device performance problems; or

15



(ii) Failed to provide adequate procedures for correcting control device performance problems as expeditiously as practicable in accordance with good air pollution control practices for minimizing emissions.

(5) Implementation of a QIP shall not excuse the owner or operator of a source from compliance with any existing emission limitation or standard, or any existing monitoring, testing, reporting or recordkeeping requirement that may apply under federal, state, or local law, or any other applicable requirements under the Act.

(c) Reporting and Recordkeeping Requirements 40 CFR 64.9

(1) General reporting requirements

(i) On and after the date specified in Section 33(a)(1) above by which the owner or operator must use monitoring that meets the requirements of this part, the owner or operator shall submit monitoring reports to the permitting authority in accordance with ADEM Admin. Code R. 335-3-16-.05(c)3.

(ii) A report for monitoring under this part shall include, at a minimum, the information required under ADEM Admin. Code R. 335-3-16-.05(c)(3). and the following information, as applicable:

(I) Summary information on the number, duration and cause (including unknown cause, if applicable) of excursions or exceedances, as applicable, and the corrective actions taken;

(II) Summary information on the number, duration and cause

(including unknown cause, if applicable) for monitor downtime incidents (other than downtime associated with zero and span or other daily calibration checks, if applicable); and

16



(III) A description of the actions taken to implement a QIP during the reporting period as specified in Section 33(b) above. Upon completion of a QIP, the owner or operator shall include in the next summary report documentation that the implementation of the plan has been completed and reduced the likelihood of similar levels of excursions or exceedances occurring.

(2) General recordkeeping requirements.

(i) The owner or operator shall comply with the recordkeeping requirements specified in ADEM Admin. Code R. 335-3-16-.05(c)2. The owner or operator shall maintain records of monitoring data, monitor performance data, corrective actions taken, any written quality improvement plan required pursuant to Section 33(b) above and any activities undertaken to implement a quality improvement plan, and other supporting information required to be maintained under this part (such as data used to document the adequacy of monitoring, or records of monitoring maintenance or corrective actions).

(ii) Instead of paper records, the owner or operator may maintain records on alternative media, such as microfilm, computer files, magnetic tape disks, or microfiche, provided that the use of such alternative media allows for expeditious inspection and review, and does not conflict with other applicable recordkeeping requirements.

17



(d) Savings Provisions 40 CFR 64.10

(1) Nothing in this part shall:

(i) Excuse the owner or operator of a source from compliance with any existing emission limitation or standard, or any existing monitoring, testing, reporting or recordkeeping requirement that may apply under federal, state, or local law, or any other applicable requirements under the Act. The requirements of this part shall not be used to justify the approval of monitoring less stringent than the monitoring which is required under separate legal authority and are not intended to establish minimum requirements for the purpose of determining the monitoring to be imposed under separate authority under the Act, including monitoring in permits issued pursuant to title I of the Act. The purpose of this part is to require, as part of the issuance of a permit under title V of the Act, improved or new monitoring at those emissions units where monitoring requirements do not exist or are inadequate

to meet the requirements of this part.

(ii) Restrict or abrogate the authority of the Department to impose additional or more stringent monitoring, recordkeeping, testing, or reporting requirements on any owner or operator of a source under any provision of the Act, including but not limited to sections 114(a)(1) and 504(b), or state law, as applicable.

(iii) Restrict or abrogate the authority of the Department to take any enforcement action under the Act for any violation of an applicable requirement or of any person to take action under section 304 of the Act.

18



34. Permit Shield

A permit shield exists under this operating permit in accordance with ADEM Admin. Code 335-3-16-.10 in that compliance with the conditions of this permit shall be deemed in compliance with any applicable requirements as of the date of permit issuance. The permit shield is based on the accuracy of the information supplied in the application for this permit. Under this shield, it has been determined that requirements listed as non-applicable in the application are not applicable to this source.

Rule 335-3-16-.10

19

Summary Page for Utility Boilers

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

†Except during leap year 2020, Permitted Operating Schedule = 8,784 Hours/Year

Emission limitations:


EMISSION L IMIT †

REGULATIONS

EAL-6801

EAL-6802



PM

CO

NOX

SO2

Fuel H2S

17.3 Lbs/Hr

17.1 Lbs/Hr

16.7 Lbs/Hr

2.4 Lbs/Hr

10 grains/100 scf of gas

Or 160 ppmv

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

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

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

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

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

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)


20

Provisos for Utility Boilers


Applicability

1. Each boiler shall be subject to the requirements of Alabama Department of Environmental Management

(ADEM) Admin. Code R. 335-3-4-.01, “Visible Emissions” and the requirements specified in this subpart of this permit.

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

2. Each boiler shall be subject to the requirements of ADEM Admin. Code R. 335-3-4-.03, “Fuel Burning Equipment” for Control of Particulate Emissions and the requirements specified in this subpart of this permit.

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

3. Each boiler has best available control technology (BACT) limits in place to comply with the requirements specified in ADEM Admin. Code R. 335-3-14, “Prevention of

Significant Deterioration (PSD)” and the requirements specified in this subpart of this permit.

Rule 335-3-14-.04(8)(a) &

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

[PSD/BACT Limits] Rule 335-3-5-.01(1)(a)

4. Each boiler shall be subject to requirements specified in Rule 335-3-16 of the ADEM Admin. Code R. 335-3-16, “Major Source Operating Permits” and the requirements specified in this subpart of this permit.

Rule 335-3-16-.03

5. Each boiler shall be subject to the requirements specified in 40 CFR Part 60, Subpart A, “General Provisions”,40 CFR 60 Subpart Dc, “Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units” and the requirements specified in this subpart of this permit.

Rule 335-10-.02(2)(c)

§60.40c(a)

Emissions Standards

1. Visible emissions from each boiler shall meet the opacity standards specified in proviso 1(a) and (b) of this section of this subpart.

Rule 335-3-4-.01

(a) Except for one 6-minute period during any 60-minute period, each boiler shall not discharge into the atmosphere particulate that results in an opacity greater than 20%, as determined by a 6-minute average.

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

21



(b) At no time shall a boiler discharge into the atmosphere particulate that results in an opacity greater than 40%, as determined by a 6-minute average.

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

2. Each boiler shall comply with the requirements specified in proviso 2(a) through (e) of this section of this subpart.

(a) Carbon monoxide (CO) emissions shall not exceed 17.1 Lbs/Hour.

Rule 335-3-14-.04(9)(b) [PSD/BACT Limits]

(b) Nitrogen oxide (NOX) emissions shall not exceed 16.7 Lbs/Hour.


(c) Particulate Matter (PM) emissions shall not exceed 17.3 Lbs/Hour.

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

(d) Sulfur Dioxide (SO2) emissions shall not exceed

2.4 Lbs/Hour.

Rule 335-3-14-.04(9)(b) [PSD/BACT Limits] Rule 335-3-5-.01(1)(a)

(e) Hydrogen sulfide (H2S) content of the fuel gas shall not exceed 10 grain/100 Scf (i.e. 160 ppmv).


Compliance and Performance Test Methods and Procedures

1. Compliance with the opacity standards shall be determined using Method 9 or Method 22 of 40 CFR 60, Appendix A.

Rule 335-3-4-.01(2)

2. A performance test shall be conducted in accordance to the appropriate reference methods and procedures specified in proviso 2(a) and (b) of this section of this subpart.

Rule 335-3-16-.05(c)(1)(i)

(a) Each run shall be conducted in accordance to the following reference methods and procedures:

(1) 40 CFR Part 60 Appendix A, Method 1 or 1A to determine the sample site

(2) 40 CFR Part 60 Appendix A, Method 2 or 2A or 2B or 2C or 2D or 2E to determine the volumetric flow rate of the effluent gas

22



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

(4) 40 CFR Part 60 Appendix A, Method 4 to

determine the moisture in the stack gas

(5) 40 CFR Part 60 Appendix A, Method 7 or 7A or 7B or 7C or 7D or 7E to determine NOX emissions

(6) 40 CFR Part 60 Appendix A, Method 10 or 10A or 10B to determine CO emissions

(7) 40 CFR Part 60 Appendix A, Method 19 to determine SO2 and NOX emission rates

(b) The methods and procedures that are utilized may be modified upon receiving Departmental approval.

3. The fuel gas shall be tested for BTU heat content and hydrogen sulfide (H2S) content in accordance to the requirements specified in proviso 3(a) through (c) of this section of this subpart.

Rule 335-3-16-.05(c)(1)(i)

(a) The sample shall be analyzed for its BTU heat content by utilizing the ASTM Analysis Method D1826-77 or equivalent method.

[ Fuel Gas Heat Content (BTU/Scf) ]

(b) The sample shall be analyzed for its H2S content by utilizing the Tutwiler procedures found in §60.648 of 40 CFR Part 60 or the chromatographic analysis procedures found in ASTM E-260 or the stain tube procedures found in GPA 2377-86 or those provided by the stain tube manufacturer.

[ Fuel Gas H2S (ppmv) ]

(c) The methods and procedures that are utilized may be modified upon receiving Departmental approval.

23



Emission Monitoring

1. Periodic monitoring for the boilers shall be conducted as specified in Appendix A of this permit.

Rule 335-3-16-.05(c)(1)

2. Provided a performance test has not been conducted on the boiler in the last five (5) years, a performance test shall be conducted in accordance to the following requirements:

Rule 335-3-16-.05(c)(1)(i)

(a) A test shall consist of three runs of at least 1-

hour in duration.

(b) Each run shall test for the emissions of CO and NOX. The pollutants tested may be modified upon receiving Departmental approval.

(c) Test emission factors (EF) for each air pollutant shall be determined in pounds per million BTU.

[ Test EF (Lbs/MMBTU) ]

3. The fuel gas shall be tested for BTU and H2S content in accordance to the following requirements:

Rule 335-3-16-.05(c)(1)(i)

(a) Testing shall consist of capturing a representative sample of the fuel gas at a frequency of no less than once each six (6) months.

(b) The frequency of analysis may be modified upon receiving Departmental approval.

Record Keeping and Reporting Requirements

1. In order to demonstrate compliance with 40 CFR 60 Subpart Dc, a record of the amount of fuel burned during each calendar month shall be maintained for a

period of two years following the date of such record.

§60.48c(g)(2)and (i)

§60.7 §60.19

Boiler Fuel gas consumption of engine

[Gas Volume (MScf/Month) ]

2. A record of the information specified in provisos 2(a) through (h) of this section of this subpart shall be maintained for each boiler and made available for inspection.

Rule 335-3-16-.05(c)(2)

24



(a) The date, starting time and duration of each deviation from the requirements specified in this subpart along with the cause and corrective actions taken.

(b) The date, time and results of each performance test, along with any other tests conducted on the boilers that provides additional stack pollutant content data.

(c) Date and type of boiler maintenance that affects air emissions

(d) Fuel gas BTU Heat Content

[Heat Content (BTU/Scf) ]

(e) Fuel gas H2S Content

[H2S Content (Mole %)]

(f) Boiler fuel gas Heat Input

Fuel Gas Heat Input (MMBTU/Month) =

[Volume (MScf/Month)] X [Heat Content (BTU/Scf) ]

1000

where, the Fuel Gas heat content (BTU/Scf) shall equal to the most recent BTU content analysis required by proviso 3(a) of the Emissions Monitoring section of this subpart.

(g) Boiler Operating Hour

[ Operating Hours (Hours/Month) ]

(h) CO, NOX, and SO2 emissions shall be determined

as as follows:

(1) Boiler Emissions (Lbs/Month) =

[Fuel Gas Heat Input (MMBTU/Month)] X Test EF (Lbs/MMBTU) ]

where, the Test EF (Lbs/MMBTU) shall equal to the most recent performance results required by

proviso 2(c) of the Emission Monitoring section of this subpart.

25



(2) Boiler Emissions (Lbs/Hour) =

[ Boiler Emissions (Lbs/Month) ]

[ Operating Hours (Hours/Month) ]

3. Periodic Monitoring Reports (PMR) meeting the requirements specified in provisos 3(a) through (c) of this section of this subpart shall be submitted to the

Department.

Rule 335-3-16-.05(c)(2)

Rule 335-3-16-.05(c)(3)(i)

(a) Each report shall identify each incidence of deviation from a permit term or condition including those that occur during startups, shutdowns, and malfunctions.

(1) A deviation shall mean any instance in

which emission limits, emission standards, and/or work practices were not complied with, as indicated by observations, data collection, and monitoring specified in this permit.

(2) For each deviation event, the following information shall be submitted.

(i) Emission source description

(ii) Permit requirement

(iii) Date

(iv) Starting time

(v) Duration

(vi) Actual quantity of pollutant or parameter

(vii) Cause

(viii) Actions taken to return to normal operating conditions

(ix) Total operating hours of the affected source during the reporting period

26



(x) Total hours of deviation events during the reporting period

(xi) Total hours of deviation events that occurred during startups, shut downs, and malfunctions during the reporting period

(b) If no deviation event occurred during the reporting period, a statement that indicates there were no deviations from the permit requirements shall be included in the report.

(c) Each report shall cover a calendar semi-annual period and shall be submitted using the following reporting schedule:

Reporting Period Submittal Date

January 1-June 30 July 31

July 1-December 31 January 31

(d) The report content specified in proviso 3(a) of this section may be modified upon receipt of Departmental approval.

4. Each deviation from the requirements specified in this subpart, including those that occur during startups, shutdowns, and malfunctions, shall be reported to the Department in a manner that complies with proviso 15(b) and 21(b) of the general proviso subpart of this permit.

Rule 335-3-16-.05(c)(2)

Rule 335-3-16-.05(c)(3)(ii)

27

Summary Page for the Emergency Engines

Permitted Emergency Operating Schedule: Unlimited

Permitted Non-Emergency Operating Schedule: 100 Hours/Year or less for each engine (maintenance and testing, emergency demand response, and non-emergency situations)

50 Hours/Year or less for each engine for Non-emergency situations (counted as part of the 100 Hour/Year) [§63.6640(f), RICE MACT]



EMISSION L IMIT †

REGULATIONS

Fire Pump A &

Fire Pump B

Generator A

Generator B

(2) 287 BHP, Caterpillar 3306, Diesel Fire Pump Engines

390 BHP, Cummins NT-966-G5, Blackstart Gnerator, Diesel Engine

166 BHP, Cummins 6BT5.9-G2, Onan Generator [Communication Tower Backup], Diesel Engine

HAPs Management Practices

§63.6585(c) §63.6590(a)(1)(iii) §63.6603(a)

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)

28

Provisos for Emergency Engines


Applicability

1. Each emergency generator engine is subject to the applicable requirements of ADEM Admin. Code R. 335-3-4-.01, “Visible Emissions” and the requirements specified in this subpart of this permit.

Rule 335-3-4-.01

2. Each emergency generator engine is subject to the applicable requirements of ADEM Admin. Code R. 335-3-16-.03, Major Source Operating Permits and the requirements specified in this

subpart of this permit.

Rule 335-3-16-.03

3. Each emergency generator engine is subject to the applicable requirements of 40 CFR 63 Subpart A, “General Provisions” and the requirements specified in this subpart of this permit.

§63.6665, Table 8

4. Each emergency generator engine is subject to the area source requirements of 40 CFR 63 Subpart ZZZZ, “National Emission Standards for Hazardous Air Pollutants (HAPs) for Stationary Reciprocating Internal Combustion Engines (RICE)” [RICE MACT] and the requirements specified in this subpart of this permit.

§63.6585(c) §63.6590(a)(1)(iii)

Emissions Standards

1. Visible emissions from each emergency engine shall meet the opacity standards specified in proviso 1(a) and (b) of this section of this subpart.

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

(a) Except for one 6-minute period during any 60-minute period, the unit shall not discharge into the atmosphere particulate that results in an opacity greater than 20%, as determined by a 6-minute average.

(b) At no time shall the unit discharge into the atmosphere particulate that results in an opacity greater than 40%, as determined by a 6-minute average.

2. Each engine shall adhere to the following management practices:

§63.6603(a) §63.6605(a)

Table 2d, Item No. 4

(a) The oil and oil filter shall be changed according to the

schedule specified in provisos 2(a)(1) OR 2(a)(2):

(1) Every 500 hours of operation, or annually, whichever comes first,

Table 2d, Item No. 4(a)

29



OR

(2) According to the Oil Analysis Program outlined in

40 CFR 63.6625(i)

§63.6625(i)

(b) Inspect the Air Cleaner every 1000 hours of operation, or annually, whichever comes first.

Table 2d, Item No. 4(b)

(c) Inspect all hoses and belts every 500 hours of operation, or annually, whichever comes first. Hoses and belts shall be replaced as necessary.

Table 2d, Item No. 4 (c)

(d) The management practices specified in provisos 2(a) through (c), may be delayed if the unit is operating during an emergency situation, or if the required management practices would result in an unacceptable risk. In this case, the required management practice(s) shall be conducted as soon as possible.

Table 2d, Footnote 2

3. Each emergency generator engine must meet the following requirements:

(a) The requirements specified under §63.6640(f) shall be met.

§63.6640(f)

(b) Must be equipped with a non-resettable hour meter if

one is not already installed

§63.6625(f)

(c) During periods of startup, the facility must 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

§63.6625(h)

4. Each unit shall be operated and maintained in a manner consistent with safety and good air pollution control practices for minimizing emissions.

§63.6605(b)



Rule 335-3-4-.01(2)

30



Emission Monitoring

1. The facility shall comply with one of the following operation and maintenance plans:

Rule 335-3-16-.05(c)(1)

§63.6640(a) §63.6625(e)(3) Table 6, No. 9

(a) Operate and maintain the stationary engine according to the manufacturer’s emission-related operation and maintenance instructions

OR

(b) The facility may develop and follow its own maintenance plan, provided this plan ensures, to the extent practicable, the operation and maintenance of the unit in a manner consistent with good air pollution practices.


1. A record of the information specified in provisos 1(a) through (g) of this section of this subpart shall be maintained and made available in a form suitable for inspection for a period of five (5) years.

(a) The date, starting time and duration of each deviation from the requirements specified in this subpart along

with the cause and corrective actions taken.

Rule 335-3-16-.05(c)(2), §63.6655(a)(1) §63.6660(a) & (b)

(b) The date, starting time and, and duration of each malfunction, along with steps taken to minimize emissions, and corrective actions taken.

Rule 335-3-16-.05(c)(2), §63.6655(a)(2) & (5) §63.6660(a) & (b)

(c) Date and type of engine maintenance that affects air emissions

Rule 335-3-16-.05(c)(2) §63.6655(a)(4), (d), (e)(2) §63.6660(a) & (b)

(d) A copy of the fuel gas certification shall be maintained onsite.

Rule 335-3-16-.05(c)(2) §63.6660(a) & (b)

(e) Operating hours for each engine for each type of use: Rule 335-3-16-.05(c)(2)

§63.6655(f) §63.6660(a) & (b)

[ Hours (Hours/Month) ]

(f) Fuel Usage per engine Rule 335-3-16-.05(c)(2) §63.6660(a) & (b)

31



(g) These records may be kept in electronic form, provided that they are readily accessible. Alternatively, they may be kept in hardcopy form.

Rule 335-3-16-.05(c)(2) §63.6660(a), (b), & (c)

2. Each deviation from the requirements specified in this subpart,

including those that occur during startups, shutdowns, and malfunctions, shall be reported to the Department in a manner that complies with proviso 15(b) and 21(b) of the general proviso subpart of this permit.

Rule 335-3-16-.05(c)(2) Rule 335-3-16-.05(c)(3)(ii) §63.6640(b)

§63.6650(f)

32

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33

Summary Page for Simple Cycle Combustion Turbine Engines

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

†Except during leap year 2020, Permitted Operating Schedule: = 8,784 Hours/Year


EMISSION POINT DESCRIPTION POLLUTANT EMISSION LIMIT† REGULATIONS

INDIVIDUAL SOURCES

ZAN-8902A

ZAN-8902B

ZAN-8902C

Three (3) 5,000 BHP, US Turbine Corporation, UST-3800 (K01-KB5), simple cycle combustion turbines (SCCT)

CO 5.0 Lbs/Hour Rule 335-3-14-.04(9)(b) [PSD/BACT Limit]

NOx

27.9 Lbs/Hour

AND

<150 ppmv@15% O2, dry basis

OR as calculated using the equation in §60.332(a)(2)

Rule 335-3-14-.04(9)(b) [PSD/BACT Limit]

§60.332(a)(2) and (c), [NSPS GG]

SO2

S

1.4 Lbs/Hour AND

150 ppmv@15% O2, dry basis OR

Sulfur content in the fuel gas shall not exceed 0.8% by weight (8,000 ppmw)


§60.333(a), [NSPS GG]

§60.333(b), [NSPS GG]

H2S Fuel gas H2S content shall not exceed 10 grains/100

Scf

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

Opacity


AND No 6 min avg. > 40%

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

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


34

Provisos for SCCT Engines


Applicability

1. Each turbine engine shall be subject to the requirements of ADEM Admin. Code R. 335-3-4-.01, “Visible Emissions” and the

requirements specified in this subpart of this permit.

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

2. Each turbine engine has best available control technology (BACT) limits in place to comply with the requirements specified in ADEM Admin. R. 335-3-14, “Prevention of Significant Deterioration (PSD)” and the requirements specified in this


Rule 335-3-14-.04(8)(a) &

(b) Rule 335-3-14-.04(9)(a) & (b), [PSD/BACT Limit]

3. Each turbine engine shall be subject to requirements specified in ADEM Admin. Code R 335-3-16, “Major Source Operating Permits” and the requirements specified in this subpart of this permit.

Rule 335-3-16-.03

4. Each turbine engine shall be subject to the requirements of 40 CFR 60, Subpart GG, “Standards of Performance for Stationary Gas Turbines” [NSPS GG] and the requirements specified in this subpart of this permit.

§60.330

Emissions Standards

1. Visible emissions from each turbine engine shall meet the opacity standards specified in proviso 1(a) and (b) of this section of this subpart.

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

(a) Except for one 6-minute period during any 60-consecutive minute period, each turbine engine shall not discharge into the atmosphere particulate that results in an opacity greater than 20%, as determined by a 6-minute average.

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

(b) At no time shall the turbine engines discharge into the atmosphere particulate that results in an opacity greater than 40%, as determined by a 6-minute average.

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

2. Each turbine engine shall adhere to the following emission limits:

(a) Carbon monoxide (CO) emissions shall not exceed 5.0 Lbs/Hour.

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

[PSD/BACT Limit]

35



(b) Nitrogen oxide (NOX) emissions shall not exceed: Rule 335-3-14-.04(9)(b) [PSD/BACT Limit], Rule 335-3-16-.05(a) §60.10(a)

(1) 27.9 Lbs/Hour Rule 335-3-14-.04(9)(b) [PSD/BACT Limit]

AND

(2) NOX concentration in the exhaust shall not exceed 150 parts per million by volume (ppmv) corrected to 15% oxygen on a dry basis

OR

The allowable calculated using the equation found in §60.332(a)(2), for the purposes of indicating compliance with NSPS GG:

§60.332(c)

(i) STD (% by Volume) = §60.332(a)(2)

(I) Y = Manufacturer’s rated heat at manufacturer’s rated load (kJ/watt-hr), OR actual measured heat based on lower heating value of fuel as measured at actual peak load for the facility; Y < = 14.4.

§60.332(a)(2)

(II) F = Optional NOX emission allowance (% by volume) for fuel-bound nitrogen as determined by the table

in §60.332(a)(4).

§60.332(a)(2) & (3)

(ii) STD (ppmv) =

STD (% by volume) X {10,000}

(c) Sulfur emissions shall meet the standards specified in proviso 2(c)(1) AND 2(c)(2)(i) OR 2(c)(2)(ii) of this section of this subpart of this permit.

(1) Sulfur Dioxide (SO2) emissions shall not exceed 1.4 Lbs/Hour.

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

(2) The following additional requirements also apply:

36



(i) Each turbine engine shall not discharge any gases, which contain in excess of 150 ppmv of SO2 corrected to 15% oxygen on a dry basis.

§60.633(a)

OR

(ii) Each turbine engine shall not burn any fuel which contains in excess of 0.8 percent by weight of sulfur compounds as sulfur (8,000 ppmw)

§60.333(b)

(d) The hydrogen sulfide (H2S) content of the fuel gas burned in each of the turbine engines shall not exceed 10

grain/100 Scf (i.e. 160 ppmv).

Rule 335-3-14-.04(9)(b) §60.334(h)(3)(ii)



Rule 335-3-4-.01(2)

2. Periodic testing shall be conducted on each turbine engine in accordance with the following methods and procedures to determine CO and NOX emissions:

Rule 335-3-16-.05(c)(1)(i)

(a) EPA’s “Conditional Test Method (CTM-034)”

(b) 40 CFR Part 60 Appendix A, Method 19

3. Performance testing shall be conducted on each turbine in accordance with the following methods and procedures:

Rule 335-3-16-.05(c)(1)(i)

§60.8 §60.335(a), (b)

(a) To determine NOX emissions the following requirements shall be met:

(1) NOX emissions shall be determined using one of the following methods to demonstrate compliance with NSPS GG:

§60.335

(i) 40 CFR 60 Appendix A, Method 20 §60.335(a)(1), (5)

(ii) ASTM D6522-00 as incorporated in 40 CFR 60.17

§60.335(a)(2)

37



(iii) 40 CFR 60 Appendix A, Method 7E, and 40 CFR 60 Appendix A, Method 3 (or Method 3A) to determine NOX and diluent concentration

§60.335(a)(3)

(iv) Other acceptable alternative reference methods and procedures provided in §60.335(c).

§60.335(a)(6)

(2) Sampling points shall be determined per

§60.335(a)(4).

§60.335(a)(4)

(3) Modifications to the procedures in provisos

3(a)(1)(i) through (iii) of this section of this subpart of this permit shall be in accordance with §60.335(a)(5).

§60.335(a)(5)

(b) To determine CO emissions the following requirements shall be met.

(1) CO emissions shall be determined using one of the following methods to demonstrate compliance with PSD/BACT Limits:

Rule 335-3-16-.05(c)(1)(i)

(i) 40 CFR 60 Appendix A, Method 10

(ii) 40 CFR 60 Appendix A, Method 10A

(iii) 40 CFR 60 Appendix A, Method 10B

(iv) Other methodology approved by the Department.

OR

(v) The use of Method ASTM D6522-00, as incorporated in §60.17, shall also satisfy the CO testing requirement since this method is designed to measure CO and NOX pollutants.

§60.17(h)(184)

(2) The methods and procedures used to demonstrate compliance may be modified upon receiving Departmental approval.

38



4. To demonstrate compliance with NSPS GG, the fuel gas utilized in the turbine engines shall be tested for its BTU heat content and sulfur content in accordance with the following methods and procedures:

Rule 335-3-16-.05(c)(1)(i), Rule 335-3-1-.05, §60.334(h)(1) & (3)(ii)

(a) The sample shall be analyzed for its BTU content by utilizing the ASTM Analysis Method D1826-77 or an equivalent method.

[ Heat Content ( BTU/Scf) ]

(b) The sample shall be analyzed for its sulfur content by utilizing one of the following methods: ASTM Analysis Method D1072-80, ASTM Analysis Method D 3031-81, ASTM Analysis Method D 4084-82, ASTM Analysis

Method D 3246-81, chromatographic analysis or an equivalent method, or other methods approved by the Department.

[Sulfur Content (Sulfur Wt %)]

Emission Monitoring

1. Periodic monitoring for the turbines engines shall be conducted as specified in Appendix B of this permit.

§60.334

Rule 335-3-16-.05(c)(1)

2. Performance testing shall be conducted on each turbine engine in accordance to the following requirements:

§60.8 §60.335(b)

Rule 335-3-16-.05(c)(1)(i)

(a) Provided a performance test has not been conducted on a turbine engine in the last five (5) years, a performance

test shall be conducted in accordance to the following requirements:

(1) Each run shall test for the emissions of CO and NOX.

§60.335(b)

(2) Tests shall consist of three runs of at least 1-hour in duration.

§60.335(b)(2)

(3) Test emission factors for each air pollutant shall

be determined in units of pounds per million BTU (Lbs/MMBtu) and/or as required by the emission standard.

(b) When appropriate, a performance test shall be conducted on each turbine engine within six months of commencing

or re-commencing operation.

39



3. Except as provided for in proviso 3(a) of this section of this permit, a periodic test shall be conducted on each turbine engine in accordance with the requirements specified in proviso 3(b) and (c) of this section of this subpart.

Rule 335-3-16-.05(c)(1)(i)

(a) A periodic test is not required if one of the following conditions occurs during the period denoted in either proviso 3(a)(1) or (2) of this section of this subpart.

(1) Provided that a performance test has been undertaken on the unit during the last twelve (12) months.

(2) Provided that the engine’s accumulated operating time does not exceed 500 hours during the last twelve (12) months.

(b) The maximum interval in which to conduct a periodic test shall not exceed a six (6) month period in time.

(1) Provided at least four (4) consecutive periodic tests have been conducted, the maximum interval may be modified to not exceed a twelve (12) month period upon receipt of Departmental approval.

(2) Once a deviation from a NOX or CO emission limit has occurred, the maximum interval of periodic testing shall revert back to the requirements specified in proviso 3(b)(1) of this section of this subpart.

(c) Each periodic test shall consist of one run of one hour in duration and each run shall test for emissions of CO and

NOX.

(d) The pollutants tested for and the frequency of testing

may be modified upon receiving Departmental approval.

4. The fuel gas for the turbine engines shall be tested for BTU and sulfur content in accordance to the following requirements:

Rule 335-3-16-.05(c)(1)(i) Rule 335-3-1-.05 §60.334(h)(1) & (3)

(a) BTU and sulfur content testing shall consist of capturing a representative sample of the exhaust stack gases at a frequency of no less than once each six (6) months.

40



(b) The frequency of analysis may be modified upon receiving Departmental approval.

5. When possible and practicable, a continuous metering system shall be utilized that is capable of continuously monitoring and

recording the fuel gas flow rate to each turbine.

Rule 335-3-1-.05 §60.334(h)(4)

(a) The continuous measurement may be made with a single meter through which all of the fuel gas for identical make and model engine flows.

(1) Calibration, maintenance and operation of metering system shall be performed in accordance to manufacturer’s specification.

(b) The volumetric flow of fuel gas streams that are not continuously measured shall be accounted for by utilizing special estimating methods (i.e. engineer estimates, material balance, computer simulation, special testing etc.).


1. A record of the information specified in provisos 1(a) through (i) of this section of this subpart shall be maintained and made available for inspection for each turbine engine.

Rule 335-3-16-.05(c)(2) §60.633(h) & (i)


with the cause and corrective actions taken

(b) The date, time and results of each performance and periodic tests along with any other tests conducted on the engine that provides additional stack pollutant content data

(c) Date and type of engine maintenance that affects air emissions

(d) Fuel gas BTU content

[ Heat Content (BTU/Scf) ]

(e) Fuel gas Sulfur content

[ Sulfur Content (Sulfur Wt% ) ]

(f) Fuel gas consumption of engine

[Fuel Usage (MScf/Month) ]

41



(g) Heat Input of the fuel gas for each turbine engine

Fuel Heat Input (MMBTU/Month) =

[ Fuel Usage (MScf/Month)] X [ Heat Content (BTU/Scf) ]

{1,000}

where, the heat content (BTU/Scf) of the fuel gas shall equal to the most recent BTU content determined during testing required under proviso 4 of the Compliance and Performance Test Methods And Procedures section in this subpart of this permit.

(h) Operating hours of each turbine engine

[ Hours (Hours/Month) ]

(i) CO, NOX, and SO2 emissions shall be determined as

specified in proviso 1(i)(1) and 1(i)(2) of this section of this subpart.

(1) Engine (Lbs/Month) =

where, Test Emission Factors (Lbs/MMBTU) shall equal to the most recent performance or periodic test results required by proviso 2 and 3 of the Compliance and Performance Test Methods and Procedures section in this subpart of this permit.

(2) Engine (Lbs/Hour) =

[ Engine (Lbs/Month) ]

[ Engine Operating Hours/Month ]

2. Periodic Monitoring Reports (PMR) and Excess Emissions

Reports, if applicable, meeting the requirements specified in proviso 2(a) through (c) of this section of this subpart shall be submitted to the Department.

Rule 335-3-16-.05(c)(2) Rule 335-3-16-.05(c)(3)(i)

§60.7(c) §60.634(j)

(a) Each report shall identify each incidence of deviation

from a permit term or condition including those that occur during startups, shutdowns, and malfunctions.

42



(1) A deviation shall mean any instance in which emission limits, emission standards, and/or work practices were not complied with, as indicated by observations, data collection, and monitoring specified in this permit.




(iii) Date

(iv) Starting time

(v) Duration


(vii) Cause


(ix) Total operating hours of the affected source

during the reporting period


(xi) Total hours of deviation events that occurred during start ups, shut downs, and malfunctions during the reporting period

(b) Except as provided for in proviso 2(e) of this section, each Excess Emissions Report, if required, shall meet the

requirements specified in §60.7(c) of 40 CFR Part 60, Subpart A.

(c) If no deviation event occurred during the reporting period, a statement that indicates there were no deviations from the permit requirements shall be included in the report.

43



(d) Each report shall cover a calendar semi-annual period and shall be submitted using the following reporting schedule:

§60.334(j)(5)




(e) The report content specified in proviso 2(a) of this section may be modified upon receipt of Departmental approval.

3. Each deviation from the requirements specified in this subpart, including those that occur during startups, shutdowns, and malfunctions, shall be reported to the Department in a manner that complies with proviso 15(b) and 21(b) of the general proviso


Rule 335-3-16-.05(c)(2)

Rule 335-3-16-.05(c)(3)(ii)

44

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45

Summary Page for the Sulfur Recovery System

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

†Except during leap year 2020, Permitted Operating Schedule: = 8,784 Hours/Year


EMISSION POINT #

DESCRIPTION POLLUTANT EMISSION LIMIT REGULATION

Sulfur Recovery System, w/:

Sweetening Unit CO 19.6 Lbs/Hour Rule 335-3-14-.04(9)(b) Acid Gas Enrichment Unit

S-108 Sulfur Recovery Train No. A NOX 18.8 Lbs/Hour Rule 335-3-14-.04(9)(b) S-109 Sulfur Recovery Train No. B

SO2 373.0 Lbs/Hour Rule 335-3-14-.04(9)(b)

% Sulfur Recovery

> = The allowable required by the sulfur recovery efficiency table provided

Rule 335-3-14-.04(9)(b) 40 CFR 60 Subpart LLL

(2) Sulfur Recovery Trains, Each w/: Sulfur Recovery Unit Opacity No more than one 6 min Rule 335-3-4-.01(1)(a) Tail Gas Clean-up Unit avg. > 20% Thermal Oxidizer Or

No 6 min avg. > 40% Rule 335-3-4-.01(1)(b)

H2S Gas stream must be Rule 335-3-5-.03(1)

Burned; 20 ppbv or less H2S offsite concentration

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

Oxidation Efficiency

98.0 % Rule 335-3-10.02(64) §60.646(b)(2)

46

Provisos for the Sulfur Recovery System


Applicability

1. Each thermal oxidizer shall be subject to the requirements of ADEM Admin. Code R. 335-3-4-.01, “Visible Emissions”

and the requirements specified in this subpart of this permit.

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

2. The facility shall be subject to the requirements specified in ADEM Admin. Code R. 335-3-5-.03, “Petroleum Production” and the requirements specified in this subpart of this

permit. The thermal oxidizers shall be used to comply with this regulation.

Rule 335-3-5-.03(1) & (2)

3. The sulfur recovery system shall be subject to requirements specified in ADEM Admin. Code R.. 335-3-16, “Major Source Operating Permits” and the requirements specified in this


Rule 335-3-16-.03

4. The sulfur recovery system has best available control technology (BACT) limits in place to comply with the requirements specified in ADEM Admin. R. 335-3-14, “Prevention of Significant Deterioration (PSD)” and the

requirements specified in this subpart of this permit.

Rule 335-3-14-.04(8)(a) &

(b) Rule 335-3-14-.04(9)(a) & (b) [PSD/BACT Limits]

5. The sulfur recovery system shall be subject to the requirements of 40 CFR 60 Subpart LLL, “Standards of Performance for SO2 Emissions from Onshore Natural Gas Processing” [NSPS LLL] and to this subpart of this permit. All definitions laid out in §60.641 shall apply. Compliance with PSD/BACT Limits shall demonstrate compliance with NSPS LLL.

Rule 335-3-10-.02(64)

§60.10(a) §60.640(a), (c), & (d), §60.641

6. The sulfur recovery system shall be subject to the requirements specified in 40 CFR Part 64, “Compliance Assurance Monitoring (CAM)” as indicated in proviso 33 of the General Permit Provisos subpart and in this subpart of this permit.

40 CFR Part 64

Emissions Standards

1. Visible emissions from each sulfur recovery train thermal oxidizer shall meet the opacity standards specified in proviso 1(a) and (b) of this section of this subpart.

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

47



(a) Except for one 6-minute period during any 60-

consecutive minute period, the sulfur recovery train thermal oxidizer shall not discharge into the atmosphere particulate that results in an opacity greater than 20%, as determined by a 6-minute

average.

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

(b) At no time shall the sulfur recovery train thermal oxidizer discharge into the atmosphere particulate that results in an opacity greater than 40%, as determined by a 6-minute average.

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

2. Except as is provided for in proviso 2(b) of this section of

this subpart, each process gas streams containing 0.10 of a grain of hydrogen sulfide per standard cubic feet (Scf) shall meet the requirement specified in proviso 2(a) of this section of this subpart:

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

(a) Each stream shall be burned to the extent that the

ground level concentrations of hydrogen sulfide (H2S) shall be less than twenty (20) parts per billion beyond plant property limits, averaged over a thirty (30) minute period.

(b) Provided vessels or equipment are being de-pressured

and/or emptied and the reduced pressure will not allow flow of the process gas stream to the combustion device, the venting to the atmosphere of any gas stream shall be allowed, but the duration of the venting shall not exceed 15 continuous minutes.

3. The sulfur recovery efficiency from the sulfur recovery system shall meet, or exceed, the requirements specified in the following table, as appropriate.

Rule 335-3-14-.04(9)(b) §60.642(a)

§60.643(a)(1)

Acid Gas H2S Content (Mole %) [Y]

Sulfur Feed Rate (LTons/Day) [X]

X < 2.0 2.0 ≤ X ≤ 15.0 15.0 < X

Y ≥ 1 0.0% 100-(15.0)(Y)-0.37 Lesser of 100-(9.7)(Y)-0.99

--OR— 99.8%

Y < 1 0.0% 79.0% 79.0%

4. At least 98% of the sulfur compounds leaving each sulfur recovery train thermal oxidizer shall be emitted as sulfur dioxide (SO2).

§60.646(b)(2) §60.643 Rule 335-3-14-.04(9)(b)

[PSD/BACT Limit]

48



5. Total pollutant emission rates from the sulfur recovery

system shall not exceed the requirements specified in proviso 5(a) through (c) of this section of this subpart. Emission rates shall be rounded to one decimal place.


(a) 373.0 pounds per hour (Lbs/Hour) SO2 emissions

(b) 19.6 Lbs/Hour of carbon monoxide (CO) emissions

(c) 18.8 Lbs/Hour of nitrogen oxide (NOX) emissions



Rule 335-3-4-.01(2)

2. Each process gas stream that has to be vented to atmosphere shall meet the following requirements:

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

(a) Each stream shall be captured so that it can be burned, or recycled to the process.

(b) Compliance shall be demonstrated by conducting a process flow design evaluation of the production facility in conjunction with a visual inspection of the

facility.

3. Compliance with proviso 3 and 4 of the Emission Standards section of this subpart of this permit shall be demonstrated through the use of the following equations to determine the sulfur recovery reduction efficiency and oxidation efficiency:

Rule 335-3-16-.05(c)(1)(i)

Rule 335-3-1-.05 §60.643(b) §60.644(c)(1)

(a) Sulfur recovery reduction efficiency [R] (%) = §60.643(b) §60.644(c)(1) §60.646(a)(5)

(b) Average Sulfur Feed Rate [X] (LTons/Day) =

§60.644(b)(1)

§60.646(a)(4)

49



where,

(1) Average sulfur feed rate, [X], is the rate that

sulfur compound enter the sulfur recovery system

§60.641

(2) K = 3.707 x 10-5 long tons per dry standard cubic feet (LTons/dScf)

§ 60.644(b)(1)

(3) Qa = average acid gas volumetric flowrate from the sweetening unit (dScf/day)

§60.646(a)(3) § 60.644(b)(2)

(4) Y = average acid gas H2S concentration (percent by volume) in the flow from the

sweetening unit analyzed using the Tutwiler method, chromatographic procedures, or other methods allowed by EPA.

§ 60.646(a)(2)

§ 60.644(b)(3) § 60.648

§ 60.17

(c) Sulfur compound emissions rate, [E], is the rate at which sulfur compounds are emitted from the thermal oxidizer, which shall be determined during performance testing.

§60.644(c)(3)

(d) Sulfur production rate (produced elemental sulfur), [S], in Lbs/hour shall be determined utilizing methods and procedures specified in §60.646(a)(1).

§60.646(a)(1)

§60.644(c)(2)

(e) The oxidation efficiency shall be determined using one of the following methods:

§60.646(b)(2) Rule 335-3-14-.04(9)(b)

[PSD/BACT Limit]

(1) Provided the combined TRS concentration in the thermal oxidizer stack gases is greater than 5 ppmv, the oxidation efficiency shall be calculated using the following equation:

Oxidation efficiency % =

where,

(i) Total SO2 [Lbs/Hour] = Thermal Oxidizer stack SO2 emissions, which shall be determined during each performance test

50



(ii) TRS [Lbs/Hour] = Thermal Oxidizer stack Total Reduced Sulfur emissions, which shall be determined during each performance test

(2) Provided the combined TRS concentration in the thermal oxidizer stack gases is less than, or equal to, 5 ppmv, then the oxidation efficiency shall be 98%.

4. A performance test shall be conducted in accordance to the requirements specified in provisions 4(a) and (b) of this section of this subpart to demonstrate compliance with

proviso 5 of the Emission Standards section of this subpart:

Rule 335-3-16-.05(c)(1)(i)

§60.644(a)

(a) Each run shall be conducted in accordance to the following reference methods and procedures:

(1) 40 CFR Part 60 Appendix A, Method 1 or 1A to

determine the sampling site

§60.644(c)(4)

(2) 40 CFR Part 60 Appendix A, Method 2 or 2A or 2B or 2C or 2D or 2E to determine the volumetric flow rate of the effluent gas

§60.644(c)(4)(iv)

(3) 40 CFR Part 60 Appendix A, Method 3 or 3A or

3B or 3C to determine the gas analysis

Rule 335-3-16-.05(c)(1)(i)

Rule 335-3-1-.05

(4) 40 CFR Part 60 Appendix A, Method 4 to determine the moisture in the stack gas

Rule 335-3-16-.05(c)(1)(i) Rule 335-3-1-.05

(5) 40 CFR Part 60 Appendix A, Method 6 or 6A or 6B or 6C to determine SO2 emissions

§60.644(c)(4)(i)

(6) 40 CFR Part 60 Appendix A, Method 7 or 7A or

7B or 7C or 7D or 7E to determine NOX

emissions

Rule 335-3-16-.05(c)(1)(i) Rule 335-3-1-.05

(7) 40 CFR Part 60 Appendix A, Method 10 or 10A or 10B to determine CO emissions

Rule 335-3-16-.05(c)(1)(i)

Rule 335-3-1-.05

(8) 40 CFR Part 60 Appendix A, Method 15 to

determine the TRS concentration

§60.644(c)(4)(ii)

(9) 40 CFR Part 60 Appendix A, Method 16A or 15 to determine the reduced sulfur concentration

§60.644(c)(4)(iii)

51



(b) The methods and procedures utilized to demonstrate compliance with the emissions standards may be modified upon receiving Departmental approval.

Rule 335-3-16-.05(c)(1)(i)

Rule 335-3-1-.05

Emission Monitoring

1. Periodic opacity monitoring and Compliance Assurance Monitoring (CAM) for the sulfur recovery system shall be conducted as specified in Appendix C of this permit.

§60.646

§64.6(b) & (c) Rule 335-3-16-.05(c)(1)

2. In order to determine the sulfur recovery reduction efficiency the following requirements shall be met:

(a) The sulfur feed rate, [X], (expressed in Lbs/hour) shall be determined once every 24 hours and rounded off to one decimal place

§60.646(a)(4)

(b) The average acid gas volumetric flow rate from the sweetening unit, [Qa], shall be continuously measured using the process flowmeter, averaged and recorded at least once per hour during each 24-hour period

§60.646(a)(3) §60.644(b)(2)

(c) The average acid gas H2S concentration, [Y], in the flow from the sweetening unit shall be sampled once every 24-hours at equal intervals

§60.17

§60.646(a)(2) §60.644(b)(3) §60.648

(d) The calculated average sulfur recovery reduction efficiency, [R], shall be rounded off to one decimal place and calculated once every 24 hours

§60.641

§60.646(d)

(e) The Sulfur emission rate [E] (expressed in Lbs/hour) shall be rounded off to one decimal place

§60.644(c)(3)

3. A performance test shall be conducted in accordance to the following requirements:

Rule 335-3-16-.05(c)(1)(i) §60.644(a)

(a) At least once every twelve (12) months §60.643(a)(2)

(b) Consist of three runs of at least 1-hour in duration

each.

§60.8

(c) Each run shall test for the emissions of CO, NOX, SO2, and TRS.

§60.644(c)(3)

Rule 335-3-16-.05(c)(1)(i)

52



(1) The pollutants tested for may be modified

upon receiving Departmental approval.

(d) During each run, the Thermal Oxidizer Firebox temperature shall be recorded.

§60.646(b)(2)

(e) The emissions from each thermal oxidizer shall be measured and recorded simultaneously.

Rule 335-3-16-.05(c)(1)

(f) The minimum sulfur dioxide emission reduction efficiency [Zi] and the actual emission reduction efficiency [Ri] shall be determined for each run, and for each test.

§60.644(b) & (c)

Recordkeeping and Reporting Requirements

1. A record of the information specified in provisos 1(a) through (f) of this section of this subpart shall be maintained and made available for inspection.

Rule 335-3-16-.05(c)(2) §64.9

§60.7 §60.646(f) & (g) §60.647(a)

(a) The date, starting time and duration of each deviation from the requirements specified in this subpart along with the cause and corrective actions taken.

(b) The date, time and results of each performance test along with any other tests conducted on the sulfur

recovery system that provides additional stack pollutant content data.

(c) The date and time of each shut down and startup of the gas sweetening unit, acid gas enrichment unit, each of the sulfur recovery units, each of the tail gas treating units and/or each of the thermal oxidizers.

(d) Date and type of maintenance that affects air emissions

(e) Results of each visual emission observation

(f) The three hour rolling average CMS calculations and analysis of the sulfur recovery efficiency, the sulfur dioxide emissions and the thermal oxidizer firebox

temperature.

53



2. Periodic Monitoring Reports (PMR) and Excess Emissions

Reports meeting the requirements specified in proviso 2(a) through (d) of this section of this subpart shall be submitted to the Department.

Rule 335-3-16-.05(c)(2) Rule 335-3-16-.05(c)(3)(i) §64.9

(a) Each Periodic Monitoring Report shall identify each incidence of deviation from a permit term or condition including those that occur during startups, shutdowns, and malfunctions.

(1) A deviation shall mean any instance in which emission limits, emission standards, and/or work practices were not complied with, as

indicated by observations, data collection, and monitoring specified in this permit.

(2) Each report shall cover no more that a calendar semi-annual period and shall be submitted within thirty days of the end reporting period. Each report shall contain the

information specified in proviso 2(c) of this section for each deviation.

(b) Each Excessive Emission and CMS Performance Report and Summary Report shall meet the following requirements:

§60.647(a) and (b)

(1) Each report shall cover a calendar semi-

annual period and shall be submitted using the following reporting schedule:




(2) Excess emissions that are indicated by the continuous emission monitoring system (CEMS) shall be considered violations of the applicable required minimum sulfur recovery

level for the purposes of this permit except as listed below.

§60.644(d) §60.646(b)(2)

§60.646(f) & (g) §60.643(a)(1)(i)

54



(i) Data recorded from the continuous monitors during periods of startup or shutdown of the sulfur recovery system shall be excluded from the compliance averaging period for sulfur recovery efficiency. The sulfur recovery system shall be operated in a manner so that sulfur dioxide emissions are minimized during startup or shutdown periods. Excess emissions which are caused entirely or in part by poor maintenance, poor operation, or any other equipment or process failure which may reasonably be prevented during startup or shutdown constitute violations.

(ii) Data recorded from the continuous monitors during periods of malfunctions shall be excluded from compliance averaging periods for sulfur recovery efficiency. A malfunction is defined as any sudden and unavoidable failure of the air pollution control equipment or process equipment or of a process to operate in a normal or usual manner. Failures that are caused entirely or in part by poor maintenance, careless operation, or any other preventable condition or preventable equipment breakdown shall not be considered malfunctions.

(iii) Data records from the continuous monitors during periods when the data does not represent accurate sulfur recovery efficiency or during periods when the CEM’s exceeds the calibration drift (as specified in the respective performance specification tests) shall be excluded from the compliance averaging

periods. The burden of proof to demonstrate that the data does not reflect accurate sulfur recovery efficiency and sulfur dioxide emissions reading shall be the responsibility of the permittee.

55



(c) Except as provided for in proviso 2(d) of this section,

the following information shall be included with each deviation and/or excess emissions event:

§ 60.7

(1) Emission source description

(2) Permit requirement

(3) Date

(4) Starting time

(5) Duration

(6) Actual quantity of pollutant or parameter

(7) Cause

(8) Actions taken to return to normal operating conditions

(9) Total operating hours of the affected source during the reporting period

(10) Total hours of deviation events during the reporting period

(11) Total hours of deviation events that occurred

during startups, shut downs, and malfunctions during the reporting period

(d) The report content and format in proviso 2(c) of this section may be modified upon receipt of Departmental approval.


Rule 335-3-16-.05(c)(2) Rule 335-3-16-.05(c)(3)(ii)

4. The recordkeeping and reporting requirements specified in §60.647 of 40 CFR Part 60, Subpart LLL and in §60.7 and

§60.19 of 40 CFR Part 60, Subpart A shall be maintained and made available for inspection and submitted to the Department when required.

Rule 335-3-10-.02(64)

§60.647 §60.7

§60.19

56


57

Summary Page for Emergency Facility Flares

Permitted Operating Schedule: 24 Hours/Day x 365 Days/Year = 8,760 Hours/Year† †Except during leap year 2020, Permitted Operating Schedule: = 8,784 Hours/Year




F101 F102

High Pressure Emergency Flare Low Pressure Emergency Flare

H2S

Burn gas with 0.10 grains or more of H2S/Scf of gas


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

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

SO2

No Limit provided that the Available Sulfur is less than or equal to 5 LTD

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

Opacity


AND

No 6 min avg. > 40%

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

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

Individual Process Units:

Inlet gathering & separation unit Gas sweetening unit Glycol dehydration unit Condensate stabilization unit Acid gas enhancement unit Sulfur recovery unit Tailgas cleanup unit with closed vent systems and flare

58

Provisos for Emergency Facility Flares


Applicability

1. Each emergency flare shall be subject to the applicable requirements of ADEM Admin. Code R. 335-3-4-.01, “Visible Emissions” for Control of Particulate Emissions and the applicable requirements specified in this subpart of this permit.

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

2. This facility is subject to the requirements of ADEM Admin. Code R. 335-3-5-.03, “Petroleum Production” for control of sulfur dioxide (SO2) emissions and the applicable requirements specified in this subpart of this permit.

Rule 335-3-5-.03

3. Each emergency flare shall be subject to the applicable

requirements of ADEM Admin. Code R. 335-3-16-.03, “Major Source Operating Permits” and the applicable requirements specified in this subpart of this permit.

Rule 335-3-16-.03

4. Each flare shall be subject to the requirements specified in 40 CFR Part 64, “Compliance Assurance Monitoring” as indicated in proviso 33 of the General Permit Provisos subpart and to this subpart of this permit.

40 CFR Part 64

Emission Standards

1. Visible emissions from each flare shall meet the requirements specified in proviso 1(a) and (b) of this section of this subpart.

(a) Except for one 6-minute period during any 60-

consecutive minute period, each flare shall not discharge into the atmosphere particulate that results in an opacity greater than 20%, as determined by a 6-minute average.

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

(b) At no time shall the flares discharge into the atmosphere particulate that results in an opacity greater than 40%, as determined by a 6-minute average.

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

2. Except as is provided for in proviso 2(b) of this section of

this subpart, each process gas streams containing 0.10 of a grain of hydrogen sulfide per standard cubic feet (Scf) shall meet the requirement specified in proviso 2(a) of this section of this subpart:

Rule 335-3-5-.03(1) & (2)

59



(a) Each stream shall be burned to the extent that the ground level concentrations of hydrogen sulfide (H2S) shall be less than twenty (20) parts per billion beyond plant property limits, averaged over a thirty (30) minute period.

(b) Provided vessels or equipment are being de-pressured and/or emptied and the reduced pressure will not allow flow of the process gas stream to the combustion device, the venting to the atmosphere of any gas stream shall be allowed, but the duration of

the venting shall not exceed 15 continuous minutes.

3. Provided available sulfur is equal to or less than 5 long tons per day, there is no limit on sulfur dioxide emissions. A record of SO2 emissions shall be kept for reporting purposes.

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



Rule 335-3-4-.01(2)

2. Each process gas stream that can be sent to the flare shall be tested in accordance to the following methods and

procedures:

Rule 335-3-16-.05(c)(1)(i)

(a) The sample shall be analyzed for its BTU heat content by utilizing the ASTM Analysis Method D1826-77 or equivalent method.

[ Fuel Gas (BTU/Scf) ]

(b) The sample shall be analyzed for its hydrogen sulfide (H2S) content by utilizing the Tutwiler procedures found in 40 CFR §60.648 or the chromatographic

analysis procedures found in ASTM E-260 or the stain tube procedures found in GPA 2377-86 or those provided by the stain tube manufacture.

[ Stream H2S (Mole %) ]

(c) The methods and procedures that are used may be modified upon receiving Departmental approval.

3. Each process gas stream that has to be vented to atmosphere shall meet the following requirements:

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

60



(a) Each stream shall be captured so that it can be burned, or recycled to the process.

(b) Compliance shall be demonstrated by conducting a process flow design evaluation of the production facility in conjunction with a visual inspection of the facility.

Emission Monitoring

1. Periodic monitoring, opacity monitoring and Compliance Assurance Monitoring (CAM) for flares shall be conducted as specified in Appendix D of this permit.

§64.6(b) & (c) Rule 335-3-16-.05(c)(1)

2. Each process gas stream that can be sent to the flare shall be tested in accordance to the requirements specified in proviso 2(a) through (c) of this section of this subpart.

Rule 335-3-16-.05(c)(1)(i)

(a) BTU heat content and H2S content testing shall consist of capturing a representative sample of the exhaust stack gases at a frequency of no less than once each twelve (12) months.

(b) Provided multiple process streams can be sent to the flare and it is possible to capture a common stream

whose contents would be representative of all the streams, that common stream may be used instead of the individual process streams.

(c) The frequency of testing may be modified upon receipt of Departmental approval.


1. A record of the information specified in provisos 1(a) through (l) of this section of this subpart shall be maintained and made available for inspection.

Rule 335-3-16-.05(c)(2)


with the cause and corrective actions taken.

(b) Results of each visual emission observation

(c) Stream H2S Content

[Stream H2S (Mole %)]

61



(d) Name of stream that was flared

(e) Stream volume that was flared

[ Stream Volume Burned (MScf/Day) ]

(f) Assist gas volume that was flared

[Assist Gas Volume Burned (MScf/Day)]

(g) Stream H2S Feed Rate (Lbs/Day) =

[ Stream Volume Burned (MScf/Day) ] X {1000 Scf/MScf} X

{1 Lb Mole/380 SCF } X [ {Stream H2S (Mole %)}/{100} ] X

[ 34 Lbs. H2S/1 Lb Mole H2S ]

(h) Flare H2S Feed Rate (Lbs/Day) =

∑ of Stream H2S (Lbs/Day)

(i) Flare SO2 (Lbs/Day) =

[ Flare H2S Feed Rate (Lbs/Day) ] X [ 64 Lbs of SO2/ Lb Mole ] X [ 0.98 ] [ 34 Lbs H2S/Lb Mole ]

(j) Number of hours that each flare was operated during the month =

[ Flare Hours (Hours/Day) ] (k) H2S feed (Lbs/Hour) =

Flare H2S Feed Rate (Lbs/Day) Flare Hours (Hours/Day)

(l) Assist gas to acid gas volume ratio

2. Periodic and Excess Emissions Monitoring Reports meeting the requirements specified in proviso 2(a) through (d) of this

section of this subpart shall be submitted to the Department.

Rule 335-3-16-.05(c)(2) Rule 335-3-16-.05(c)(3)(i)

(a) Each report shall identify each incidence of deviation from a permit term or condition including those that occur during startups, shutdowns, and malfunctions.

(1) A deviation shall mean any instance in which emission limits, emission standards, and/or work practices were not complied with, as indicated by observations, data collection, and monitoring specified in this permit.

62






(iii) Date

(iv) Starting time of pollutant or parameter

(v) Duration


(vii) Cause


(ix) Total operating hours of the affected source during the reporting period


(xi) Total hours of deviation events that occurred during startups, shut downs, and malfunctions during the reporting period

(b) If no deviation event occurred during the reporting

period, a statement that indicates there were no deviations from the permit requirements shall be included in the report.

(c) Except as provided for in proviso 2(e) of this section, each Excess Emissions report shall meet the requirements specified in either §60.7(c) of 40 CFR Part 60, Subpart A.

(d) Each report shall cover a calendar semi-annual period and shall be submitted using the following reporting schedule:

63






(e) The report content and format in proviso 2(a) through (d) of this section may be modified upon receipt of Departmental approval.


Rule 335-3-16-.05(c)(2) Rule 335-3-16-.05(c)(3)(ii)

64


65

Summary Page for Tri-Ethylene Glycol [TEG] Dehydrator Emissions

Permitted Operating Schedule: 24 Hours/Day x 365 Days/Year = 8,760 Hours/Year† †Except during leap year 2020, Permitted Operating Schedule: = 8,784 Hours/Year Emission limitations:

EMISSION POINT # DESCRIPTION POLLUTANT EMISSION

LIMIT REGULATIONS

TEG-A

TEG-B

Tri-Ethylene Glycol (TEG) Dehydrator Unit [In Urban-1 Co., but NOT in UA or UC]

HAPs [Primarily

BTEX]

4,674 gallons per hour

Max Glycol Circulation

Rate

§63.764(d)(2)(ii) 40 CFR 63 Subpart HH

66

Provisos for TEG Dehydrator Unit Emissions


Applicability

1. Each tri-ethylene glycol dehydration (TEG) unit is subject to the applicable requirements of ADEM Admin. R. 335-3-16-.03, “Major Source Operating Permits” and the requirements specified in this subpart of this permit.

Rule 335-3-16-.03

2. Each TEG dehydration unit located at this facility is

an affected area source under the requirements of 40 CFR 63 Subpart HH, “National Emission Standards for Hazardous Air Pollutants form Oil and Natural Gas Production Facilities” and the requirements specified in this subpart of this permit.

§63.760(a) §63.760(b)(2)

(a) The General Provisions of 40 CFR 63 Subpart A shall be complied with as specified in §63.764(a) and Table 2 of Subpart HH.

§63.764(a)

Emissions Standards

1. Hazardous Air Pollutant (HAPs) emissions from the TEG dehydration unit shall be minimized by operating the unit such that the glycol circulation rate does not exceed:

(a) The alternate glycol circulation rate of 4,674 gallons per hour as determined using GRI-GLYCalcTM, Version 3.0 or higher.

§63.764(d)(2)(ii)

OR

(b) The optimum glycol circulation rate set by the equation found in §63.764(d)(2)(i).

§63.764(d)(2)(i) and (ii)

(c) If operating conditions change and a modification to the glycol circulation rate is required, a new determination shall be prepared and submitted to the Department

§63.764(d)(2)(iii)


1. There are no performance test requirements for an area source TEG unit not located within an UA plus offset and UC boundary as defined in §63.760.

§63.760

§63.772

67

Provisos for TEG Dehydrator Unit Emissions


Emission Monitoring

1. At all times the owner or operator must 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

§63.774(j)

Recordkeeping and Reporting Requirements

1. A record of the calculation used to determine the optimum glycol circulation rate must be maintained.

§63.764(d)(2)(iii) §63.774(f)

2. Maintain a record of the operating hours for each glycol dehydrator on a monthly basis.

§63.772(b)(2)

3. There are no reporting requirement for an affected area source not located inside a UA plus offset and UC boundary.

§63.775(e)

4. If a notification of process change is required as a result of changes being made to the process or changes to the information submitted in the original Notification of Compliance Status Report, a report

including the information in §63.775(f) should be submitted within 180 days after the change is made.

§63.775(f)

5. A copy of benzene emissions from each TEG dehydration units shall be submitted to the Department annually as part of the Title V emission estimates.

Rule 335-3-16

68


69

Appendix A: Utility Boiler Monitoring

70

Utility Boiler Monitoring Monitoring approach: Periodic Monitoring

I. Indicator Calculate NOX, CO, & SO2 Emissions A. Measurement approach Fuel gas volume to each unit shall be monitored with a system capable of measuring and recording the flow rate and/or the parameters utilized for flow rate calculation. BTU & H2S content of fuel gas stream shall be determined semi-annually, or at a frequency determined by the Department. Pollutant emission factors shall be determined during performance tests. II. Indicator range CO emissions shall be maintained at < = 17.1 lb/hr

NOX emissions shall be maintained at < = 16.7 lb/hr SO2 emissions shall be maintained at < = 2.4 lb/hr A deviation is defined as anytime the calculated emission rate exceeds the respective allowed emission rates. A deviation triggers an immediate inspection, corrective action, and reporting within 48 hours or two work days. A QIP threshold Not applicable III. Performance criteria A. Data representiveness Fuel gas volume monitor shall be located immediately upstream of each boiler, or at a common point upstream of both boilers. Fuel gas BTU & H2S content shall be determined from samples that are representative of the fuel gas being consumed. Performance tests shall be undertaken while each boiler is being operated at normal loads. B. Verification of Not applicable

operational status C. QA/QC practices & The fuel gas volume monitor shall be calibrated at a frequency in accordance with the manufacturer’s specifications, other criteria written procedures that provide adequate assurance that the device is calibrated accurately, or at least annually whichever is more frequent. If the fuel gas monitor fails its calibration tests, the fuel gas monitor shall be taken out of service until repairs and/or replacements are made and a new calibration test is undertaken and passed. D. Monitoring frequency Fuel gas volume measured continuously. Fuel gas BTU & H2S content shall be determined semi-annually, or at a frequency set by the Department. Performance tests shall be undertaken every 5 years.

71

Utility Boiler Monitoring Monitoring approach: Periodic Monitoring

Data collection Calculate: Monthly, or as set by the Department, procedure Pollutant emissions while utilizing the fuel volume, BTU content, emission factor and operating hours Fuel gas volume consumed Record: Monthly, or as set by the Department Fuel gas volume consumed

Hours of operation. Pollutant emissions Record: Each occurrence Each fuel gas BTU & H2S content determination Time, date and results of each inspection and corrective actions taken Averaging period Monthly, or as set by the Department

72


73

Appendix B: SCCT Engine Monitoring

74

SCCT Engine Monitoring

Monitoring approach: Periodic monitoring

I. Indicator Calculated CO, NOX, & SO2 emissions A. Measurement approach Fuel gas volume shall be monitored with a system capable of measuring and recording the flow rate and/or the parameters utilized for flow rate calculation. Btu and sulfur content of fuel gas stream shall be determined semi-annually. Pollutant emission factors shall be determined during performance and periodic tests. II. Indicator range CO emissions shall be equal to or less than 5.0 Lbs/Hr

NOX emissions shall be equal to or less than 27.9 Lbs/Hr SO2 emissions shall be equal to or less than 1.4 Lbs/Hr A deviation is defined as anytime the performance test, periodic test or the calculated emission rate exceeds the respective allowed emission rates. A deviation triggers an immediate inspection, corrective action, and reporting within 48 hours or two work days. A QIP threshold Not applicable III. Performance criteria A. Data representiveness Fuel gas volume monitor shall be located immediately upstream of the engine. Fuel gas Btu and sulfur content shall be determined from samples that are representative of the fuel gas being consumed. Performance tests shall be undertaken once every 5 years while the engine is being operated at normal loads. B. Verification of operational Not applicable status

C. QA/QC practices & criteria Not applicable

75

SCCT Engine Monitoring

Monitoring approach: Periodic monitoring

I. Indicator Calculated CO, NOX, & SO2 emissions D. Monitoring frequency Fuel gas volume measured continuously. Fuel gas Btu content shall be determined once each six months Performance tests shall be undertaken once every five years. Periodic tests shall be undertaken once every year.

Data collection procedure

Calculate: Monthly Pollutant emissions while utilizing the fuel volume, Btu and sulfur content, emission factor and operating hours. Fuel gas volume consumed

Record: Monthly Fuel gas volume consumed

Hours of operation. Pollutant emissions

Record: Each occurrence Fuel gas Btu and sulfur determination Time, date and results of each inspection and corrective actions taken Averaging period Monthly, or as set by the Department

76


77

Appendix C: Sulfur Recovery System Monitoring

78

Sulfur Recovery System

Monitoring approach: Compliance Assurance Monitoring [CAM] Compliance Assurance Monitoring [CAM]

I. Indicator Sulfur recovery efficiency & Sulfur dioxide emission rate Thermal oxidizer firebox temperature A. Measurement approach The inlet feed volume and sulfur content shall be monitored Firebox temperature shall be monitored with a with a system capable of continuously measuring and recording thermocouple or equivalent device. the flow rate and/or the parameters utilized for flow rate calculations along with its sulfur content. The effluent volume and sulfur content for each thermal oxidizer shall be monitored with a system capable of continuously measuring and recording the flow rate and/or the parameters utilized for flow rate calculations along with its sulfur content. A continuous emissions monitoring system that is capable of A continuous parameter monitoring system that is assimilating the above information, analyzing that information capable of assimilating the above information, analyzing and making appropriate calculations for each monitoring cycle that information and making appropriate calculations and each rolling three hour period while recording relevant for each monitoring cycle and each rolling three hour information and calculation results shall be utilized. period while recording relevant information and calculation results shall be utilized. II. Indicator range The sulfur recovery efficiency shall meet or exceed the The S-108 firebox temperature

efficiencies set forth in the following table, where [X] and shall be maintained at ≥ 1,210 °F [Y] are the same as the variables defined in §60.641: The S-109 firebox temperature

Acid Gas H2S Content (Mole %) [Y]

Sulfur Feedrate (LTon/Day) [X] shall be maintained at ≥ 1,090 °F

X < 2.0 2.0 ≤ X ≤ 15.0 15 < X

Y ≥ 1 0.0 100-(15.0)(Y)-0.37

100-(9.7)(Y)-0.99 -OR- 99.8, whichever is less

Y<1 0.0 79.0 79.0

The SO2 emissions from the Sulfur Recovery System shall be less than or equal to 373 Lbs/Hour An exceedance is defined as anytime the three hour rolling An excursion is defined as anytime the three hour rolling average SO2 rate is greater than 373 Lbs/Hour or the three hour average firebox temperature is less than the respective rolling average sulfur recovery efficiency is less than the value required temperature. calculated while utilizing the above equations.

79



I. Indicator Sulfur recovery efficiency & Sulfur dioxide emission rate Thermal oxidizer firebox temperature An exceedance triggers an immediate inspection and corrective An excursion triggers an immediate inspection and actions that meets the requirements of §64.7(d) 40 CFR Part 64 corrective actions that meets the requirements of and reporting within 48 days or two work days. §64.7(d) 40 CFR Part 64 and reporting within 48 days or two work days. The minimum firebox temperature may be modified upon receipt of Departmental approval. A QIP threshold If the accumulated hours of exceedance events occurring If the accumulated hours of excursion events occurring exceeds 5% of the sulfur recovery system operating time exceeds 5% of the sulfur recovery system operating time during any quarterly reporting period, a Quality Improvement during any quarterly reporting period, a Quality Plan shall be developed and implemented. Improvement Plan shall be developed and implemented. III. Performance criteria A. Data representiveness Each inlet sensor shall be located upstream of the sulfur Each temperature sensor shall be located within the recovery system at such a location that will allow the monitoring thermal oxidizer combustion chamber or immediately of all acid gas streams that enter the sulfur recovery system. downstream of the combustion chamber.

Each effluent sensor shall be located at a point within the thermal oxidizer stack that would result in the monitoring of all of the gases exiting the sulfur recovery system through the thermal oxidizer stack. Each volume sensor shall be accurate to within ±2.0%. Each temperature sensor shall be accurate to within 1.0%. Each content sensor shall be accurate to within ±5.0%. B. Verification of operational Not applicable Not applicable status C. QA/QC practices & criteria A program for the inlet and effluent continuous emission Each temperature sensor shall be calibrated at a monitoring system shall be developed and implemented that frequency in accordance with the manufacturer’s meets the requirements specified in the following regulations: specifications or other written procedures that provide adequate assurance that the device is calibrated §60.13 of 40 CFR Part 60, Sub. A accurately or by methods and procedures approved by 40 CFR Part 60, App F the Department. 40 CFR Part 60, App B, PS 2 40 CFR Part 60, App B, PS 6

80



I. Indicator Sulfur recovery efficiency & Sulfur dioxide emission rate Thermal oxidizer firebox temperature If the sensor fails its calibration test, the sensor shall be taken If the sensor fails its calibration test, the sensor shall be out of service until repairs and/or replacements are made and a taken out of service until repairs and/or replacements new calibration test is undertaken and passed. are made and a new calibration test is undertaken and passed. D. Monitoring frequency Inlet volume or inlet volume parameters and inlet content shall Temperature shall be measured continuously. be measured continuously. Effluent volume or effluent volume parameters and effluent content shall be measured continuously.

Data collection Calculate and record hourly and rolling three hour averages of procedure the following items:

Volumes & sulfur mass rates of: Inlet stream(s)

Thermal oxidizer effluent Actual sulfur dioxide emission rate Allowed sulfur recovery efficiency Record each H2S concentration analysis. Record hourly and rolling three hour average firebox temperature. Record calibration results. Record calibration results. Record inspection results and corrective actions taken. Record inspection results and corrective actions taken.

Averaging period Rolling three hours Rolling three hours

NOTE: Monitoring outlined in this table was derived from the requirements of 40 CFR 60 Subpart LLL. Therefore, compliance with the

requirements in this table satisfies the requirements of 40 CFR 60 Subpart LLL.

81

Sulfur Recovery System Thermal Oxidizer - Opacity

Monitoring approach: Periodic Monitoring

I. Indicator Opacity A. Measurement approach Provided the Sulfur Plant is being operated and facility operating personnel notice visible emissions being emitted from the Sulfur Plant Thermal Oxidizer, a daily visual emission observation shall be undertaken. Duration of each observation shall be >= 15 minutes and<= 60 minutes Each observation shall be conducted with either: Test Method 9 of 40 CFR Part 60 – OR – Test Method 22 of 40 CFR Part 60 II. Indicator range (1) No more than one 6-min. average opacity reading shall exceed 20%; OR, (2) No 6-min. average opacity reading shall exceed 40%; OR, (3) The accumulated time of observed visible emissions shall not exceed 12 minutes. A deviation is defined as anytime the observed 6-minute average opacity exceeds 20% for the 2nd time, or 40% for the 1st time, when utilizing Method 9. A deviation is defined as anytime the accumulated time in which visible emissions were observed exceeds 12 minutes per observation when utilizing Method 22. A deviation triggers continued visible emissions observations at a frequency suitable to defining the duration of the visible emission deviation event. One observation shall be undertaken to establish the end of the visible emission deviation event. A deviation triggers an immediate inspection, corrective action, and reporting within 48 hours or two work days. III. Performance criteria A. Monitoring frequency When visible emissions are noticed

Data collection Record: Daily procedure

Each 15 second observation reading Record: Each occurrence – Time, date and results of corrective actions taken Averaging period Six minutes

82


83

Appendix D: Emergency Flares Monitoring

84

Each Emergency Flare

Monitoring approach:

Periodic Monitoring Compliance Assurance Monitoring [CAM]

I. Indicator Assist gas to acid gas volume ratio Operate flare with a flame or spark present at all times when a process gas stream may be sent to it. A. Measurement approach

Inlet assist gas and acid gas feed volume shall be monitored with a system capable of measuring and recording the flow rate and/or the parameters utilized for flow rate calculation or estimated utilizing material balances, computer simulations, special testing, or other approved methods

The flare tip shall be equipped with one of the following:

• A continuous sparking flame igniter that is monitored by an amp meter or an equivalent device OR monitored by visual observation

• A continuously burning pilot light that is monitored with either a thermocouple or an equivalent device OR monitored by visual observation

II. Indicator range Assist gas to acid gas volume ratio shall be equal or

greater than 2.25 to 1.0. Presence of a flame or spark at flare tip

A deviation is defined as anytime the actual ratio is less

than 2.25 to 1.0. A deviation is defined as when there was no spark or flame present at the flare tip when a process gas stream could be vented to it.

If the accumulated hours of deviation events occurring

exceeds 5% of the emergency flare’s operating time during a quarterly reporting period an immediate running of an air quality modeling study that utilizes the maximum inlet mass and flow rates that occurred during this period.

A deviation triggers an immediate inspection and corrective actions that meet the requirements of 40 CFR Part 64.7(d) and reporting within 48 hours or two work days.

The minimum ratio may be modified upon receipt of Departmental approval. A QIP threshold Not applicable If the accumulated hours of deviation events occurring

exceeds 5% of the flare’s operating time during any quarterly reporting period, a Quality Improvement Plan shall be developed and implemented.

III. Performance criteria

A. Data representiveness Each volume monitor shall be located upstream of the flare

and shall consist of a single device that monitors all streams or multiple devices that monitor individual or multiple streams.

Each flame igniter or flame monitor shall be located at the flare tip and focused on the area where gas exits the flare tip.

85




I. Indicator Assist gas to acid gas volume ratio Operate flare with a flame or spark present at all times when a process gas stream may be sent to it. Visual observations shall be made from the location that

provides the best view of the flare tip and/or flare pilot lights or flare igniter.

B. Verification of operational status

Not applicable Not applicable

C. QA/QC practices & criteria

Each volume monitor shall be maintained and calibrated in accordance with the manufacturer’s specifications.

Each flame igniter or flame monitor shall be maintained and calibrated in accordance with the manufacturer’s specifications, other written procedures that provide adequate assurance that the device is properly maintained and calibrated accurately, –OR– at least annually, whichever is more frequent.

Repairs and/or replacements shall be made immediately

when non- functioning or damaged parts are found. Flame igniter arc length shall not exceed 10% of arc interval

and shall have an arcing frequency of no greater than once every 3 seconds.

D. Monitoring frequency Inlet acid gas and assist volume shall be measured

continuously. Pilot flame shall be monitored either continuously with a thermocouple or daily with visual inspections if operating staff is on site.

Flame igniter - arcing frequency shall be monitored either continuous with an amp meter or daily with visual inspections if operating staff is on site.

Data collection procedure

Calculate &/or record an inlet volume that is representative of the volume entering flare.

Record time, date and duration of each incident of when no spark or flame was present at the flare tip when a process gas stream could have been sent to it.

Record daily hours of operation. Record time, date and results of each visual observation. Calculate & record H2S feed rate. Calculate & record SO2 Effluent rate.

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I. Indicator Assist gas to acid gas volume ratio Operate flare with a flame or spark present at all times when a process gas stream may be sent to it. Record time, date and results of each calibration. Record time, date and results of each calibration. Record time, date and results of each inspection and

corrective actions taken. Record time, date and results of each inspection and corrective actions taken.

Submit air quality modeling results to the Department

within 60 days of the end of the quarterly period when deviations in excess of 5% occur during a calendar quarter.

Averaging period Hourly Instantaneous

87

Each Emergency Flare - Opacity

Monitoring approach: Periodic Monitoring

I. Indicator Opacity A. Measurement approach Provided the flare is being utilized to burn a gas stream other than the pilot light fuel gas stream, a visual emission observation on the flare shall be undertaken. Duration of each observation shall be >= 15 minutes and<= 60 minutes Each observation shall be conducted with either: Test Method 9 of 40 CFR Part 60 – OR – Test Method 22 of 40 CFR Part 60 II. Indicator range (1) No more than one 6-min. average opacity reading shall exceed 20%; OR, (2) No 6-min. average opacity reading shall exceed 40%; OR, (3) The accumulated time of observed visible emissions shall not exceed 12 minutes. A deviation is defined as anytime the observed 6-minute average opacity exceeds 20% for the 2nd time, or 40% for the 1st time, when utilizing Method 9.

A deviation is defined as anytime the accumulated time in which visible emissions were observed exceeds 12 minutes per observation when utilizing Method 22. A deviation triggers continued visible emissions observations at a frequency suitable to defining the duration of the visible emission deviation event. One observation shall be undertaken to establish the end of the visible emission deviation event. A deviation triggers an immediate inspection, corrective action, and reporting within 48 hours or two work days. III. Performance criteria A. Monitoring frequency Daily

Data collection Record: Daily procedure

Each 15 second observation reading Record: Each occurrence – Time, date and results of corrective actions taken Averaging period Six minutes

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