MDEQ Marathon Petroleum Permit 63-08C

8/13/2019 MDEQ Marathon Petroleum Permit 63-08C

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MICHIGAN DEPARTMENT OF ENVIRONMENTAL QUALITYAIR QUALITY DIVISION

January 11, 2012

PERMIT TO INSTALL63-08C

ISSUED TOMarathon Petroleum Company LP

LOCATED AT

1300 South Fort StreetDetroit, Michigan

IN THE COUNTY OFWayne

STATE REGISTRATION NUMBERA9831

The Air Quality Division has approved this Permit to Install, pursuant to the delegation of authorityfrom the Michigan Department of Environmental Quality. This permit is hereby issued inaccordance with and subject to Section 5505(1) of Article II, Chapter I, Part 55, Air PollutionControl, of the Natural Resources and Environmental Protection Act, 1994 PA 451, as amended.Pursuant to Air Pollution Control Rule 336.1201(1), this permit constitutes the permitteesauthority to install the identified emission unit(s) in accordance with all administrative rules of theDepartment and the attached conditions. Operation of the emission unit(s) identified in this Permitto Install is allowed pursuant to Rule 336.1201(6).

DATE OF RECEIPT OF ALL INFORMATION REQUIRED BY RULE 203:

October 26, 2011

DATE PERMIT TO INSTALL APPROVED:

January 11, 2012SIGNATURE:

DATE PERMIT VOIDED: SIGNATURE:

DATE PERMIT REVOKED: SIGNATURE:


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Marathon Petroleum Company LP (A9831) January 11, 2012Permit No. 63-08C Page 1 of 103

PERMIT TO INSTALL

Table of Contents

Section Page

Alphabetical Listing of Common Abbreviations / Acronyms ................................................................................... 2

General Conditions ................................................................................................................................................. 3

Special Conditions .................................................................................................................................................. 5

Emission Unit Identification..................................................................................................................................... 5

Flexible Group Identification.................................................................................................................................. 12

Emission Unit Special Conditions ......................................................................................................................... 14EG11-FCCU...................................................................................................................................................... 14EG27-ZURNBOILER......................................................................................................................................... 19EU27-B&WBOILER1......................................................................................................................................... 22

EG42-43SULRECOV........................................................................................................................................ 25EG70-COKER................................................................................................................................................... 30

EG-COKERFLARE ........................................................................................................................................... 34EG72-SULRBLOCK2........................................................................................................................................ 37

Flexible Group Special Conditions........................................................................................................................ 41FG-HEATERS................................................................................................................................................... 41FGFLARES ....................................................................................................................................................... 53FG-PROCVENTS.............................................................................................................................................. 61FGGROUP2...................................................................................................................................................... 62FG-IFRTANKS .................................................................................................................................................. 64FG-EFRTANKS................................................................................................................................................. 70FG29-IGF.......................................................................................................................................................... 76

FG-PROCUNITS............................................................................................................................................... 78

FG-CRUDETANKS ........................................................................................................................................... 82

FG-NAPHTHATANKS....................................................................................................................................... 83FG-COOLTOWERS.......................................................................................................................................... 86FG-FirePumps................................................................................................................................................... 90FGDHOUPANNUAL.......................................................................................................................................... 92

Table B-1:Source-Wide Requirements ................................................................................................................. 95

Appendices ........................................................................................................................................................... 99Appendix A: Continuous Emission Monitoring System Requirements for NOX, SO2, O2, and CO................... 99Appendix B: Recordkeeping Provisions Actual to Projected-Actual Applicability Test................................ 100


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Common Abbreviations / Acronyms

Common Acronyms Pollutant/Measurement Abbreviations

AQD Air Quality Division BTU British Thermal Unit

ANSI American National Standards Institute C Degrees Celsius

BACT Best Available Control Technology CO Carbon Monoxide

CAA Clean Air Act dscf Dry standard cubic footCEM Continuous Emission Monitoring dscm Dry standard cubic meter

CFR Code of Federal Regulations F Degrees Fahrenheit

COM Continuous Opacity Monitoring gr Grains

EPA Environmental Protection Agency Hg Mercury

EU Emission Unit hr Hour

FG Flexible Group H2S Hydrogen Sulfide

GACS Gallon of Applied Coating Solids hp Horsepower

GC General Condition lb Pound

HAP Hazardous Air Pollutant m Meter

HVLP High Volume Low Pressure * mg Milligram

ID Identification mm Millimeter

LAER Lowest Achievable Emission Rate MM Million

MACT Maximum Achievable Control Technology MW Megawatts

MAERS Michigan Air Emissions Reporting System ng Nanogram

MAP Malfunction Abatement Plan NOx Oxides of Nitrogen

MDEQMichigan Department of EnvironmentalQuality

PM Particulate Matter

MIOSHAMichigan Occupational Safety & Health

AdministrationPM10 PM less than 10 microns diameter

MSDS Material Safety Data Sheet PM2.5 PM less than 2.5 microns diameter

NESHAPNational Emission Standard for Hazardous

Air Pollutantspph Pound per hour

NSPS New Source Performance Standards ppm Parts per million

NSR New Source Review ppmv Parts per million by volume

PS Performance Specification ppmw Parts per million by weight

PSD Prevention of Significant Deterioration psia Pounds per square inch absolute

PTE Permanent Total Enclosure psig Pounds per square inch gauge

PTI Permit to Install scf Standard cubic feet

RACT Reasonably Available Control Technology sec Seconds

ROP Renewable Operating Permit SO2 Sulfur Dioxide

SC Special Condition THC Total Hydrocarbons

SCR Selective Catalytic Reduction tpy Tons per year

SRN State Registration Number g MicrogramTAC Toxic Air Contaminant VOC Volatile Organic Compounds

TEQ Toxicity Equivalence Quotient yr Year

VE Visible Emissions

* For High Volume Low Pressure (HVLP) applicators, the pressure measured at the HVLP gun air cap shall notexceed ten (10) pounds per square inch gauge (psig).


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GENERAL CONDITIONS

1. The process or process equipment covered by this permit shall not be reconstructed, relocated, ormodified, unless a Permit to Install authorizing such action is issued by the Department, except to theextent such action is exempt from the Permit to Install requirements by any applicable rule.(R 336.1201(1))

2. If the installation, construction, reconstruction, relocation, or modification of the equipment for which thispermit has been approved has not commenced within 18 months, or has been interrupted for 18 months,this permit shall become void unless otherwise authorized by the Department. Furthermore, the permitteeor the designated authorized agent shall notify the Department via the Supervisor, Permit Section, AirQuality Division, Michigan Department of Environmental Quality, P.O. Box 30260, Lansing, Michigan48909, if it is decided not to pursue the installation, construction, reconstruction, relocation, or modificationof the equipment allowed by this Permit to Install. (R 336.1201(4))

3. If this Permit to Install is issued for a process or process equipment located at a stationary source that isnot subject to the Renewable Operating Permit program requirements pursuant to R 336.1210, operationof the process or process equipment is allowed by this permit if the equipment performs in accordancewith the terms and conditions of this Permit to Install. (R 336.1201(6)(b))

4. The Department may, after notice and opportunity for a hearing, revoke this Permit to Install if evidenceindicates the process or process equipment is not performing in accordance with the terms and conditionsof this permit or is violating the Departments rules or the Clean Air Act. (R 336.1201(8), Section 5510 of

Act 451, PA 1994)

5. The terms and conditions of this Permit to Install shall apply to any person or legal entity that now orhereafter owns or operates the process or process equipment at the location authorized by this Permit toInstall. If the new owner or operator submits a written request to the Department pursuant to R 336.1219and the Department approves the request, this permit will be amended to reflect the change of ownershipor operational control. The request must include all of the information required by subrules (1)(a), (b), and(c) of R 336.1219 and shall be sent to the District Supervisor, Air Quality Division, Michigan Department ofEnvironmental Quality. (R 336.1219)

6. Operation of this equipment shall not result in the emission of an air contaminant which causes injurious

effects to human health or safety, animal life, plant life of significant economic value, or property, or whichcauses unreasonable interference with the comfortable enjoyment of life and property. (R 336.1901)

7. The permittee shall provide notice of an abnormal condition, start-up, shutdown, or malfunction thatresults in emissions of a hazardous or toxic air pollutant which continue for more than one hour in excessof any applicable standard or limitation, or emissions of any air contaminant continuing for more than twohours in excess of an applicable standard or limitation, as required in Rule 912, to the Department. Thenotice shall be provided not later than two business days after start-up, shutdown, or discovery of theabnormal condition or malfunction. Written reports, if required, must be filed with the Department within10 days after the start-up or shutdown occurred, within 10 days after the abnormal conditions ormalfunction has been corrected, or within 30 days of discovery of the abnormal condition or malfunction,whichever is first. The written reports shall include all of the information required in Rule 912(5).(R 336.1912)

8. Approval of this permit does not exempt the permittee from complying with any future applicablerequirements which may be promulgated under Part 55 of 1994 PA 451, as amended or the FederalClean Air Act.

9. Approval of this permit does not obviate the necessity of obtaining such permits or approvals from otherunits of government as required by law.

10. Operation of this equipment may be subject to other requirements of Part 55 of 1994 PA 451, as amendedand the rules promulgated thereunder.


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11. Except as provided in subrules (2) and (3) or unless the special conditions of the Permit to Install includean alternate opacity limit established pursuant to subrule (4) of R 336.1301, the permittee shall not causeor permit to be discharged into the outer air from a process or process equipment a visible emission ofdensity greater than the most stringent of the following. The grading of visible emissions shall bedetermined in accordance with R 336.1303. (R 336.1301)

a) A six-minute average of 20 percent opacity, except for one six-minute average per hour of not more

than 27 percent opacity.b) A visible emission limit specified by an applicable federal new source performance standard.c) A visible emission limit specified as a condition of this Permit to Install.

12. Collected air contaminants shall be removed as necessary to maintain the equipment at the requiredoperating efficiency. The collection and disposal of air contaminants shall be performed in a manner soas to minimize the introduction of contaminants to the outer air. Transport of collected air contaminants inPriority I and II areas requires the use of material handling methods specified in R 336.1370(2).(R 336.1370)

13. The Department may require the permittee to conduct acceptable performance tests, at the permitteesexpense, in accordance with R 336.2001 and R 336.2003, under any of the conditions listed inR 336.2001. (R 336.2001)


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SPECIAL CONDITIONS

Emission Unit Identification

Emission Unit ID Emission Unit Description * Stack Identification

EG05-CRUDE Crude Unit. Area 5. The crude unitseparates crude oil into various fractionsthrough the use of distillation processes.These fractions are sent to other units in therefinery for further processing. The crude unitconsists of process vessels (including heatexchangers and fractionation columns), the

Alcorn heater, tanks, containers,compressors, pumps, piping, drains andvarious components (pump and compressorsseals, process valves, pressure relief valves,flanges, connectors, etc.). Other EGs have

been created to address individual pieces ofequipment within the crude unit which havespecific applicable requirements. Permit:262-02

None

EG05-CRUDEHTR Crude Alcorn Heater, Area 5, Fuel: Refineryfuel gas, and Natural gas, Permit: 108-02,262-02, 175-06

SV04-H1-05-H1

EG04-VACUUM Vacuum Unit. Area 4. The vacuum unitseparates the reduced crude from the crudeunit through the use of a vacuum column.The reduced crude is separated into lightvacuum gas oil, medium vacuum gas oil,

heavy vacuum gas oil, and a bottoms productcalled flux. The various fractions are sent toother units in the refinery for furtherprocessing. The vacuum unit consists ofprocess vessels (including heat exchangersand vacuum column), two process heaters,tanks, containers, 2 cooling towers, flare,compressors, pumps, piping drains, andvarious components (pumps and compressorseals, process valves, pressure relief valves,flanges, connectors, etc.). Other EGs havebeen created to address individual pieces of

equipment within the vacuum unit that havespecific applicable requirements. Permit262-02

None

EG04-VACHTR Vacuum Heater. Area 4. Fuel: Refinery fuelgas and natural gas. Permit: 108-02, 262-02,175-06

SV04-H1-05-H1

EG04-VAC2HTR Vacuum Heater. Area 4. Fuel: Refinery fuelgas and natural gas.

SV04-H2


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EG08-GOHT Gasoil Hydrotreater Unit: Area 8. Reactssour gasoil streams with hydrogen over acatalyst bed to remove sulfur. The GOHTunit consists of process vessels (reactors,distillation tower, absorbing towers, stripper

tower) and a charge heater, cooling tower,flare, compressors, pumps, piping, drains, &various components (pumps & compressorseals, process valves, pressure relief valves,flanges, connectors, etc.). Other EGs werecreated to address individual pieces ofequipment within this unit that have specificapplicable requirements.Permit: 262-02.

None

EG08-GOHTCHARHTR Gasoil Hydrotreater Charge Heater. Area 8.Fuel: Refinery fuel gas and natural gas.Permit: 262-02.

SV08-H1

EG09-ALKDIBREBHTR Alkylation deisobutanizer heater. Area 9:

Fuel: refinery fuel gas and natural gas.

SV09-H7

EG09-ALKYLATION Alkylation Unit: Area 9: The Alkylation unitreacts isobutane with olefins in the presenceof sulfuric acid to produce alkylate, a highoctane gasoline blending component.Reaction products are sent for furtherprocessing and separation in the fractionatingsection. Products from the unit include off-gas, alkylate, butane, isobutane, andpropane. Off-gas is routed to the refinery fuelgas system. Alkylate, butane, and propaneare directed to storage. Isobutane is recycled

through the system for further processing.Alkylation unit consists of process vessels(including fractionators, reactor and causticscrubber), heaters, tanks, containers, coolingtower, flare, compressors, pumps, piping,drains, and various components (pump andcompressor seals, process valves, pressurerelief valves, flanges, connectors, etc.) OtherEGs were created to address individualpieces of equipment within the Alkylation Unitwhich have specific applicable requirements.Permit 262-02.

None


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EG11-FCCU Fluid Catalytic Cracking Unit. Area 11. TheFCCU converts heavier hydrocarbons tolighter products in the presence of a catalyst.In the process coke is deposited on thecatalyst. The spent catalyst is moved to the

regenerator(11-V1) where the coke is burned off usingair. The regenerator is equipped withcyclones to capture catalyst (11-V1CYCLONES). The hot flue gas from theregenerator is directed to a flue gas coolerwhere heat is recovered as steam. TheFCCU consists of process vessels (reactors,regenerator, fractionators, knock-out pots,and strippers) heater, tanks, containers, 2cooling towers, compressors, pumps, piping,drains, and various components (pumps, and

compressor seals, process valves, pressurerelief valves, flanges, connectors, etc.).Other EGs have been created to addressequipment that has specific applicablerequirements. Permit 262-02, 28-02A, 175-06.

SVFCCU

EG12-GASCON Gas Concentration Unit. Area 12. The GasCon Unit processes liquids and off-gasesfrom the FCCU main column overhead andvarious other hydrocarbons (liquid and gas)and produces gasoline and liquid petroleumgas. The Gas Con Unit consists of process

vessels (including reboilers, condensers,exchangers, absorbers, and distillationcolumns) tanks, containers, compressors,pumps, piping, drains, and variouscomponents, (pump and compressor seals,process valves, pressure relief valves,flanges, connectors, etc.). Other EGs havebeen created to address individual pieces ofequipment with the Gas Concentration Unitthat have specific applicable requirements.Permit 262-02.

None


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EG16-NAPHHYTREAT Naphtha Hydrotreater Unit Area 16. TheNHT unit uses hydrogen to remove sulfur andnitrogen from straight-run and cokernaphthas. The process uses a catalyst topromote the desulfurization reaction. The

desulfurized or sweet naphtha is blended intogasoline or used for platformer feed. TheNHT unit consists of process vessels(including exchangers, reactors, receivers,separators, and a stripper column.) heaters,tanks, containers, pumps, piping, drains, andvarious components, (pump seals, processvalves, pressure relief valves, flanges,connectors, etc. Other EGs have beencreated to address individual pieces ofequipment which have specific applicablerequirements. Permit 262-02.

None

EG16-NHTSTRIPREBOIL Naphtha Hydrotreater Stripper Reboiler.Area 16. Fuel: Refinery fuel gas, and naturalgas. Permits: C-11495, 108-02, 262-02

SV16-H3

EG16-NHTCHARHTR Naphtha Hydrotreater Charge Heater. Area16. Fuel: refinery fuel gas and natural gas.Permit: C-11493, 108-02, 262-02

SV16-H4

EG19-KEROHYTREAT Kerosene Hydrotreater Unit. Area 19. TheKHT unit uses hydrogen to remove sulfur andnitrogen from kerosene (and occasionallyNaphtha). The process, called hydrotreating,uses a catalyst with hydrogen andtemperature to promote the desulfurization

reactor. The KHT unit consists of processvessels (including exchangers, a reactor, areceiver, separators, and a stripper column),a heater, tanks, containers, pumps,compressors, piping, drains, and variouscomponents (pump, and compressors, seals,process valves, pressure relief valves,flanges, connectors, etc.). Another EG havebeen created to address the charge heater,which has specific applicable requirements.Permit 262-02.

None

EG19-KHTCHARHTR Kerosene Hydrotreater Charge Heater. Area

19. Fuel: Refinery fuel gas, and natural gas.

Permits C-11494, 108-02, 262-02

SV19-H2

EG22-TANKFARMS Tank Farm, Area 22. This emission groupcovers the three tanks farm areas. Permit262-02

None

EG27-ZURNBOLER Gas-fired boiler, Area 27. Fuel: Refinery fuelgas and natural gas. Permit C-9022.

SV27-BR7

EU27-B&WBOILER1 Gas-fired boiler, Area 27. Fuel: Refinery fuelgas and natural gas. Permit 67-02.

SV-B&WBOILER1


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EG70-COKER Delayed Coker. Area 70. The Cokerconverts Vacuum Resid (Crude VacuumTower Bottoms), a product normally sold asasphalt or blended into residual fuel oil, intolighter, more valuable products. The Vacuum

Resid feedstock is heated before it enters themain fractionator, where lighter materialvaporizes. The fractionator bottoms arerouted through a fired heater and then into acoke drum. This emission unit consists ofprocess vessels (fractionators), coke drums,heater, cooling tower, compressors, pumps,piping, drains, & various components (pumps& compressor seals, process valves,pressure relief valves, flanges, connectors,etc.). This emission group includes the CokeHandling System, which will collect, size, and

transport the petroleum coke created duringthe coking process. This system consists ofa coke pit, storage pad, enclosed crusher,enclosed conveyors, and surge bins. OtherEGs were created to address individualpieces of equipment within this unit that havespecific applicable requirements.

SV70-V1

EG70-COKERHTR Coker Charge Heater. Area 70. Fuel:Refinery fuel gas and natural gas.

SV70-H1

EG71-H2HTR Hydrogen Plant Heater. Area 71. Fuel:Refinery fuel gas, pressure swing absorptiongas, Syngas, and natural gas.

SV71-H1

EG71-H2PLANT Hydrogen Plant. Area 71. The H2 Plant willprocess natural gas, refinery fuel gas and/ora high-pentane refinery stream to produce99.9% pure hydrogen and high-pressuresteam through the use of a steam/methanereforming technology. This emission unitconsists of process vessels, heater,compressors, pumps, piping, drains, &various components (pumps & compressorseals, process valves, pressure relief valves,flanges, connectors, etc.). Other EGs werecreated to address individual pieces of

equipment within this unit that have specificapplicable requirements.

None


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EG71-H2STEAMSYS Hydrogen Plant Deaerator, Blowdown Vent,and Steam Vent. Area 71. During normaloperation, small quantities of VOC may beemitted from the Hydrogen Plant Deaeratorand the Blowdown Vent. During periods of

startup, shutdown, and unanticipatedoutages, small quantities of VOC may beemitted from the Hydrogen Plant Deaerator,Blowdown Vent, and Steam Vent..

SV71-DEAERATORSV71-BLOWDOWNSV71-PRODSTEAM

EG-COKERFLARE Coker Plant Flare. Area 76. SV76-FS

EG77-DHTHYTREAT Distillate Hydrotreater Unit: Area 77. Reactssour distillate (and occasionally gas oil)streams with hydrogen over a catalyst bed toremove sulfur. The DHT unit consists ofprocess vessels (reactors, distillation tower,absorbing towers, stripper tower), heater,cooling tower, compressors, pumps, piping,

drains, & various components (pumps &compressor seals, process valves, pressurerelief valves, flanges, connectors, etc.).Other EGs were created to addressindividual pieces of equipment within this unitthat have specific applicable requirements.

None

EG77-DHTHTR Distillate Hydrotreater Heater. Area 77. Fuel:Refinery fuel gas and natural gas.

SV77-H1

EG72-SULRBLOCK2 Sulfur Block 2. Area 72. The Sulfur Blockremoves hydrogen sulfide from acid gas andconverts it to elemental sulfur using ClausProcess (Trains D and E), the SCOT Tail Gas

Treating Unit process (Trains No. 3 andNo. 4), and associated amine treatingequipment. The exhaust tail gas is routed toa thermal oxidizer. This emission groupconsists of process vessels (including thermalreactors, an absorbing tower, and a strippingtower), heaters, tanks, containers,compressors, seals, process valves, flanges,connectors, etc.). Other EGs have beencreated to address individual units whichhave specific applicable requirements.

SV72-V22

EG73-SOURWATER2 Sour Water Stripper. Area 73. The Sour

Water Stripper removes hydrogen sulfide(H2S) and ammonia from the sour waterstream in distillation towers heated by steam.The acid gases from the tower are routed tothe Sulfur Plant. The stripped sour water issent to the refinery sewer system. Thisemission group includes all equipment(pumps, tanks, vessels) in this area.

None


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EGTANK104 Tank 104, an internal floating roof tank for thestorage of petroleum liquids with a true V.P.of 11 psia or less. Capacity 4,673,000gallons.

None

EGTANK120 Tank 120, an internal floating roof tank for the

storage of petroleum liquids with a true V.P.of 11 psia or less. Capacity 4,744,000gallons.

None

EGTANK601 Tank 601, an external floating roof tank forthe storage of wastewater. Capacity =4,200,000 gallons.

None

EGTANK216 Tank 216, an internal floating roof tank forthe storage of sour water from EG72-SULRBLOCK2. Capacity = 1,500,000gallons.

None

EG24P1 Diesel-driven fire water booster pump SV-24P1

EG24P2 Diesel-driven fire water booster pump SV-24P2

EGCOOLTOWERA Cooling tower A NoneEGCOOLTOWERC Cooling tower C None

EGCOOLTOWERD Cooling tower D None

EGCOOLTOWERE Cooling tower E None

EGCOOLTOWERF Cooling tower F None

EGCOOLTOWERG Cooling tower G None

EGCOOLTOWERH Cooling tower H None

EGCOOLTOWERNEW New cooling tower installed as part of theheavy oil upgrade project.

None

EG76-UTILITIES Coker plant flare and flare gas recoverysystems. Area 76.

None

EG78-FUELGASRECOVERY Fuel gas recovery compressor. Area 78. NoneChanges to the equipment described in this table are subject to the requirements of R 336.1201, except asallowed by R 336.1278 to R 336.1290.* Emission units and emission groups that appear in this permit that are not listed in the emission unit

identification tables in this permit are described in the renewable operating permit for the facility.

These conditions include the following two existing Emission Groups for completeness. Someequipment covered by this Permit to Install (PTI) belongs in these groups, but was not modified by the

Detroit HOUP, nor were their conditions changed in this PTI.

Emission Unit ID Emission Unit Description Stack Identification

EG-NSPSQQQ All individual drain systems, oil-water separatorsand the aggregate facilities that are subject to40 CFR 60, Subpart QQQ. A current list ofsubject items is maintained by the refinery.

None

EG-BENZNESHAP All equipment at the facility subject to therequirements of the Benzene Waste NESHAP

None


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Flexible Group Identification

Flexible Group ID Emission Units Included in Flexible GroupStack

Identification

FG-HEATERS EG04-VACHTR, EG04-VAC2HTR, EG05-CRUDEHTR,EG08-GOHTCHARHTR, EG09-ALKDIBREBHTR,

EG11-FCCUCHARHTR, EG14-CCRPLCHARHTR,EG14-CCRPLINTHTR, EG16-NHTSTRIPREBOIL,EG16-NHTCHARHTR, EG19-KHTCHARHTR,EG22-FUELOILHTR, EG27-ZURNBOILER,EG27-B&WBOILER1, EG70-COKERHTR, EG71-H2HTR,EG77-DHTHTR

None

FG-CRUDE/VACHTRS EG04-VACHTR, EG05-CRUDEHTR None

FGFLARES EG-CRUDEFLARE, EG-UNIFFLARE, EG-ALKYFLARE,EG-CPFLARE, EG-COKERFLARE

None

FG-PROCVENTS EG06-VENTV34, EG09-VENTV5, EG11-VENT14SUMP,EG11-VENT21XF, EG11-VENT14XH,EG11-VENT21V47, EG21-S2OFFGAS

None

FG-PROCUNITS EG04-VACUUM, EG05-CRUDE, EG08-GOHT,EG09-ALKYLATION, EG11-FCCU, EG12-GASCON,EG13-PROPYLENE, EG14-CCRPLATFORMER,EG16-NAPHHYTREAT, EG19-KEROHYTREAT,EG21-CPTREATER, EG22-TANKFARMS,EG22-LPGRAILRACK, EG22-ASPHLOAD,EG29-WASTEWATER, EG38-ROUGETERMNL,EG42-43SULRECOV, EG99-LPGLOADRACK,EG41-SOURWATER, EG70-COKERPLANT,EG71-H2PLANT, EG72-SULRBLOCK2,EG73-SOURWATER2, EG77-DHTHYTREAT,EG76-UTILITIES, EG78-FUELGASRECOVERY

None

FG-EFRTANKS EGTANK32, EGTANK33, EGTANK108, EGTANK109,EGTANK110, EGTANK112, EGTANK113, EGTANK114,EGTANK115, EGTANK128, EGTANK129, EGTANK130,EGTANK601, EG29TANK40, EG29TANK41

None

FG29TANKS40-41 EG29TANK40, EG29TANK41 None

FG-GROUP2 EGTANK2, EGTANK9, EGTANK11, EGTANK16,EGTANK17, EGTANK18, EGTANK24, EGTANK27,EGTANK28, EGTANK30, EGTANK31, EGTANK42,EGTANK43, EGTANK50, EGTANK52, EGTANK54,EGTANK56, EGTANK59, EGTANK60, EGTANK62,EGTANK63, EGTANK64, EGTANK66, EGTANK70,EGTANK71, EGTANK100, EGTANK102, EGTANK103,

EGTANK104, EGTANK105, EGTANK106, EGTANK107,EGTANK120, EGTANK125, EGTANK126, EGTANK127,EGTANK128, EGTANK314, EGTANK315, EGTANK316,EGTANK317, EGTANK318, EGTANK319, EGTANK320,EGTANK324, EGTANK603, EGTANK608

None

FG29-IGF EG29-IGF1, EG29-IGF2 None

FG-TANKS133&134 EGTANK133, EGTANK134 None

FG-CRUDETANKS EGTANK112, EGTANK113, EGTANK114, EGTANK115,EGTANK129, EGTANK130

None


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Flexible Group ID Emission Units Included in Flexible GroupStack

Identification

FGNAPHTHATANKS EGTANK19, EGTANK40, EGTANK45, EGTANK46,EGTANK47, EGTANK48, EGTANK49, EGTANK53,EGTANK55, EGTANK57, EGTANK58, EGTANK61,EGTANK72, EGTANK79, EGTANK101, EGTANK104,

EGTANK108, EGTANK109, EGTANK110, EGTANK116,EGTANK120, EGTANK128, EGTANK135

None

FG-IFRTANKS EGTANK6, EGTANK8, EGTANK19, EGTANK23,EGTANK40, EGTANK45, EGTANK46, EGTANK47,EGTANK48, EGTANK49, EGTANK51, EGTANK53,EGTANK55, EGTANK57, EGTANK58, EGTANK61,EGTANK72, EGTANK79, EGTANK101, EGTANK104,EGTANK116, EGTANK120, EGTANK135, EGTANK507,EGTANK508, EGTANK216

None

FGCOOLTOWERS EGCOOLTOWERA, EGCOOLTOWERC,EGCOOLTOWERD, EGCOOLTOWERE,EGCOOLTOWERF, EGCOOLTOWERG,

EGCOOLTOWERH, and EGCOOLTOWERNEW

None

FGFirePumps EG24P1, EG24P2 NoneFGDHOUPANNUAL EG11-FCCU, EG14-CCRPLCATREG, EG21-S2OFFGAS,

FG29-IGF, EG42-SULRECOV, EG70-COKER,EG-COKERFLARE, EG72-SULRBLOCK2, FG-HEATERS,FG-PROCUNITS, FGCOOLTOWERS, FGFIREPUMPS,FGHOUPTANKS, EG71-H2STEAMSYS

None

FGREFINEFLARES EG-CRUDEFLARE, EG-UNIFFLARE, EG-ALKYFLARE,EG-CPFLARE

None

FGHOUPTANKS EGTANK16, EGTANK17, EGTANK19, EGTANK23,EGTANK24, EGTANK27, EGTANK28, EGTANK40,EGTANK45, EGTANK46, EGTANK47, EGTANK48,

EGTANK49, EGTANK50, EGTANK53, EGTANK54,EGTANK55, EGTANK56, EGTANK57, EGTANK58,EGTANK59, EGTANK60, EGTANK61, EGTANK62,EGTANK63, EGTANK64, EGTANK70, EGTANK71,EGTANK72, EGTANK100, EGTANK101, EGTANK102,EGTANK103, EGTANK104, EGTANK105, EGTANK106,EGTANK107, EGTANK108, EGTANK109, EGTANK110,EGTANK112, EGTANK113, EGTANK114, EGTANK115,EGTANK116, EGTANK120, EGTANK125, EGTANK126,EGTANK127, EGTANK128, EGTANK129, EGTANK130,EGTANK507, EGTANK508, EGTANK601, EGTANK216,EG29TANK40, EG29TANK41

None


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Emission Unit Special Conditions

TABLE E-1.3 {EG11-FCCU}

EMISSION UNIT/PROCESS GROUP REQUIREMENTSEMISSION GROUP Fluid Catalytic Cracking Unit. Area 11. The FCCU converts heavier

hydrocarbons to lighter products in the presence of a catalyst. In theprocess coke is deposited on the catalyst. The spent catalyst is moved tothe regenerator (11-V1) where the coke is burned off using air. Theregenerator is equipped with cyclones to capture catalyst(11-V1CYCLONES). The hot flue gas from the regenerator is directed to aflue gas cooler where heat is recovered as steam. The FCCU consists ofprocess vessels (reactor, regenerator, fractionators, knock-out pots, andstrippers) heater, tanks, containers, 2 cooling towers, compressors, pumps,piping, drains, and various components (pumps, and compressor seals,process valves, pressure relief valves, flanges, connectors, etc.). OtherEGs have been created to address equipment that has specific applicablerequirements. Permit 262-02, 28-02A, 175-06, 379-08.

Flexible Grouping ID FG-PROCUNITS, FGDHOUPANNUAL

I. DESIGN PARAMETERSA. Pol lution ControlEquipment

Cyclone, Electrostatic precipitator (ESP) with ammonia addition.

B. Stack/Vent Parameters NAStack/Vent ID a. Minimum

Height(feet)

b. MaximumExhaust

Dimension(inches)

c. Temp(F)

d. AirFlowRate

(acfm)

Appl icableRequirement

1. SVFCCU 195 60 R 336.1225,R 336.1226(d),R 336.2804,40 CFR 52.21(d)

C. Other Design Parameters

1. NAII. MATERIAL USAGE/EMISSION LIMITS

A. Mater ial Maximum Usage Rate

1. NA 1. NA

B. Pollutant Maximum Emission Limit

1. Particulate Matter 1. Permittee shall not cause or allow the emission of particulate matterfrom any fluid catalytic cracking unit catalyst regenerator in excess of0.8 pound per 1,000 pounds of coke burn off in the regenerator.(40 CFR 60.102(a)(1), 40 CFR 63.1564)

2. Carbon Monoxide 1. Permittee shall limit CO emissions, excluding periods of startup,shutdown, and malfunction, to 500 ppmv, dry basis, based on a 1-hourblock average. (R 336.2810(3)), (R 336.2804), (40 CFR 52.21(d)),

(40 CFR 60.103), (40 CFR 63.1565)3. Sulfur Dioxide 1. Permittee shall not cause or allow the emission of sulfur dioxide fromthe FCCU regenerator in excess of the following:

a. 70 ppmv (at 0% oxygen)-7 day rolling averageb. 35 ppmv (at 0% oxygen)-365 day rolling average

(R 336.2802), (40 CFR 52.21), (55 FR 11029, Consent Order No.01-40119)

Note that if Marathon is operating in accordance with an approvedHydrotreater Outage Plan, the 7 day average limit does not apply duringperiods of hydrotreater outages nor to startup, shutdown, andmalfunction events approved in the Hydrotreater Outage Plan.

4. NOx 1. Permittee shall not cause or allow the emission of NOx from the FCCU


16/104



EMISSION UNIT/PROCESS GROUP REQUIREMENTSregenerator in excess of the following:

a. 123 ppmv (at 0% oxygen)-7 day rolling averageb. 93 ppmv (at 0% oxygen)-365 day rolling average

(R 336.1801), (40 CFR 52.21), (55 FR 11029), (Consent Order No.01-40119)

Note that if Marathon is operating in accordance with an approvedHydrotreater Outage Plan, the 7 day average limit does not apply duringperiods of hydrotreater outages nor to startup, shutdown, andmalfunction events approved in the Hydrotreater Outage Plan.

5. Volatile Organic Compounds 1. Permittee shall limit VOC emissions to 21 tons per year, based on arolling 12-month time period as determined at the end of each calendarmonth. (R 336.1702(a))

6. PM-10 (particulate matter of10 microns diameter or less)

1. Permittee shall not cause or allow the emission of PM-10 from the fluidcatalytic cracking unit catalyst regenerator in excess of 1.1 pounds per1,000 pounds of coke burn off in the regenerator. (R 336.1205),

(R 336.2802), (40 CFR 52.21)III. COMPLIANCE EVALUATIONRecords of all of the following shall be maintained on file for a period o f five years. (R 336.1213(3)(b)(ii))

A. MONITORING/RECORDKEEPING (R 336.1213(3))

1. Continuous EmissionMonitoring (CEM) Systemand Recordkeeping

1. Opacity (R 336.1213(3)), (40 CFR Part 60 Subpart J)2. NOx (R 336.1213(3))3. CO concentration by volume (R 336.1213(3))4. SO2 (R 336.1213(3))5. Oxygen (R 336.1213(3))6. The permittee shall install, certify, calibrate, maintain, and operate the

CEMS in accordance with the requirements of 40 CFR 60.11, 60.13,and Part 60, Appendix A, the applicable performance specification testof 40 CFR Part 60 Appendices B and F. With respect to 40 CFR

Part 60 Appendix F, in lieu of the requirements of 40 CFR Part 60Appendix F 5.1.1, 5.1.3, and 5.1.4, the permittee shall conduct eithera Relative Accuracy Audit (RAA) or a Relative Accuracy Test Audit(RATA) once every twelve calendar quarters, provided that a CylinderGas Audit is conducted each calendar quarter. Within 30 daysfollowing the end of each calendar quarter, the permittee shall submitthe results to the AQD in the format of the data assessment report.(R 336.1213(3))

2. Process Monitoring Systemand Recordkeeping

1. Daily records of average coke burn-off rate, in 1,000 pounds per hour,and of hours of operation. (40 CFR Part 60 Subparts A & J), (40 CFRPart 63 Subparts A & UUU)

3. Other Monitoring and/orRecordkeeping

1. Process weight rate. (R 336.1213(3)), (R 336.1331(1)(e))2. Daily records of NOx emissions from the CEM. (R 336.1205),

(R 336.2802), (40 CFR 52.21), (55 FR 11029), (Consent Order No.01-40119)

3. Daily records of SO2 emissions from the CEM. (40 CFR Part 60Subparts A & J , 40 CFR Part 63 Subparts A and UUU)

4. Daily records of CO emissions from the CEM. (40 CFR Part 60Subparts A & J , 40 CFR Part 63 Subparts A and UUU)

5. The permittee shall calculate the VOC emission rates from EG11-FCCU monthly, for the preceding 12-month rolling time period, using amethod acceptable to the AQD District Supervisor. (R 336.1702(a))

6. The permittee shall calculate the PM and PM-10 emission rate fromEG11-FCCU per 1,000 lb of coke burn off using a method acceptable


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EMISSION UNIT/PROCESS GROUP REQUIREMENTSto the AQD District Supervisor. (R 336.1205), (R 336.2802),(40 CFR 52.21), (40 CFR Part 60 Subparts A & J), (40 CFR Part 63Subparts A and UUU)

7. The permittee shall keep, in a satisfactory manner, the followingmonthly records for bypass lines in EG11-FCCU:a. visually inspect the seal or closure mechanismb. is the bypass line maintained in the closed position?c. is flow present in the bypass line?

(40 CFR Part 63 Subparts A & UUU)

B. TESTING/RECORDKEEPING (R 336.1213(3))

1. Parameter to be Tested/Recorded

1. Particulate Matter. (40 CFR Part 60 Subparts A & J, 40 CFR Part 63Subparts A & UUU, R 336.1213(3))

2. Carbon Monoxide. (40 CFR Part 60 Subparts A & J, 40 CFR Part 63Subparts A & UUU, R 336.1213(3))

3. Within 180 days after commencement of trial operation of the Detroitheavy oil upgrade project, and thereafter annually, the permittee shallverify emission rates from EG11-FCCU of the pollutants listed below bytesting at owner's expense, in accordance with Departmentrequirements. No less than 60 days prior to testing, the permittee shallsubmit a complete test plan to the AQD. The AQD must approve the finalplan prior to testing. Verification of emission rates includes the submittalof a complete report of the test results to the AQD within 60 daysfollowing the last date of the test. For verification of PM-10 emissions,testing shall include both the filterable and condensable fractions. Forverification of PM emissions, USEPA Method 5B or 5F shall be used.(R 336.2001), (R 336.2003), (R 336.2004)

PM-10 SC II.B.6.1 (R 336.1205), (R 336.2802, 40 CFR 52.21)PM SC II.B.1.1 (R 336.1205), (40 CFR 60.102(a)(1), 40 CFR

63.1564)VOC

3 (R 336.1201(3))

Sulfuric acid mist (For verification of sulfuric acid mist emissions,testing shall use the controlled condensation method.)

3

(R 336.1201(3))

4. Within 180 days after commencement of trial operation of the Detroitheavy oil upgrade project, and at least once every five years thereafter,the permittee shall determine the VOC emission rates from EG11-FCCUby testing at owner's expense, in accordance with Departmentrequirements. No less than 60 days prior to testing, the permittee shall

submit a complete test plan to the AQD. The AQD must approve thefinal plan prior to testing. Determination of emission rates includes thesubmittal of a complete report of the test results to the AQD within 60days following the last date of the test. Test results shall be used tocalculate emissions for compliance with SC II.B.5.1. (R 336.1702,R 336.2001, R 336.2003, R 336.2004)

2. Method/Analysis 1. Reference test method deemed appropriate by the Division.(R 336.1213(3)), (R 336.1331(2))

3. Frequency and Schedule ofTesting/Recordkeeping

1. As required by the Division. (R 336.1213(3))


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EMISSION UNIT/PROCESS GROUP REQUIREMENTSIV. REPORTING

Reports and Schedules See Appendix 1.8 of RO Permit 199700013c

V. OPERATIONAL PARAMETERS1. The permittee shall not operate EG11-FCCU unless the electrostatic precipitator is installed, maintained,and operated in a satisfactory manner. Satisfactory operation is described in the Startup, Shutdown andMalfunction Plan. (40 CFR Part 63 Subparts A & UUU, R 336.1910)

VI. OTHER REQUIREMENTS

1. Permittee shall comply with all applicable requirements of 40 CFR 60 as follows: Subpart A, GeneralSubpart J, Standard of Performance for Petroleum Refineries. (40 CFR Part 60 Subparts A and J)

2. Permittee shall install, calibrate, maintain and operate continuous monitoring systems subject to theprovisions of 40 CFR 60.105. (40CFR 60.105)(a))

3. An instrument for the continuous monitoring and recording of opacity. (40 CFR 60.105(a)(1))

4. An instrument for the continuous monitoring and recording of carbon monoxide. (40 CFR 60.105(a)(2))

5. An instrument for the continuous monitoring and recording of sulfur dioxide. (40 CFR 60.104),(40 CFR 60.105(a)(3))

6. An instrument for the continuous monitoring and recording of nitrogen oxides. (40 CFR 60.104),(40 CFR 60.105(a)(3))

7. Each owner or operator required to install a continuous monitoring device shall submit excess emissionsand monitoring systems performance report and-or summary report form (see 40 CFR 60.7(d)) to theDepartment semi-annually, except when: more frequent reporting is specifically required by an applicablesubpart; or the Department, on a case-by-case basis, determines that more frequent reporting is necessaryto accurately assess the compliance status of the source. All reports shall be postmarked by the 30th dayfollowing the end of each six-month period. Written reports of excess emissions shall include the followinginformation:(1) The magnitude of excess emissions computed in accordance with Sec. 60.13(h), any conversion

factor(s) used, and the date and time of commencement and completion of each time period of excessemissions. The process operating time during the reporting period.

(2) Specific identification of each period of excess emissions that occurs during startups, shutdowns, andmalfunctions of the affected facility. The nature and cause of any malfunction (if known), the correctiveaction taken or preventative measures adopted.

(3) The date and time identifying each period during which the continuous monitoring system wasinoperative except for zero and span checks and the nature of the system repairs or adjustments.

(4) When no excess emissions have occurred or the continuous monitoring system(s) have not beeninoperative, repaired, or adjusted, such information shall be stated in the report. (40 CFR 60.7(c))

8. Permittee shall comply with all applicable reporting requirements in 40 CFR 60.7. (40 CFR 60.7)

9. Permittee shall maintain a file of all information reported in the semi-annual reports and all other datacollected, either by continuous monitoring system or as necessary to convert monitoring data to the units ofthe applicable standard, for a minimum of five years from the date of collection of such data or submissionof such reports. (R 336.1213(3)(b)(ii)

10. Permittee shall comply with all applicable requirements of 40 CFR 63 as follows: Subpart A, GeneralSubpart UUU, National Emission Standards for Hazardous Air Pollutants. (40 CFR Part 63, Subparts Aand UUU)


19/104



EMISSION UNIT/PROCESS GROUP REQUIREMENTS11. The permittee shall submit to the AQD District Supervisor, for review and approval, a Startup, Shutdown and

Malfunction Plan (SSMP) for EG11-FCCU. The permittee shall not operate EG11-FCCU unless theapproved SSMP, or an alternate plan approved by the AQD District Supervisor, is implemented and

maintained. The plan shall include procedures for maintaining and operating in a satisfactory manner,EG11-FCCU, add-on air pollution control device, or monitoring equipment during malfunction events, and aprogram for corrective action for such events. If the SSMP fails to address or inadequately addresses anevent that meets the characteristics of a malfunction at the time the plan is initially developed, the owner oroperator shall revise the malfunction abatement plan within 45 days after such an event occurs. (40 CFRPart 63, Subparts A and UUU)

12. Along with the Notification of Compliance Status report, the permittee shall submit to the AQD DistrictSupervisor, an approvable Operation, Maintenance and Monitoring plan (OMMP). The permittee shall notoperate EG11-FCCU unless the approved OMMP, or an alternate plan approved by the AQD DistrictSupervisor, is implemented. The plan shall contain all information required by 40 CFR 63.1564(a)(3).(40 CFR Part 63 Subparts A & UUU)

13. The permittee shall install a permanent ammonia injection system to reduce emissions of particulate matterand oxides of nitrogen from the FCCU. Following installation and optimization of the installed system,permittee shall submit to the AQD District Supervisor a request to establish limitations for particulate matter,oxides of nitrogen and ammonia slip.

3(R 336.1201(3), R 336.1910)

* This requirement is state enforceable only.3This condition is included at the request of the permittee.


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EG27-ZURNBOILEREMISSION UNIT CONDITIONS

DESCRIPTIONZurn Boiler. Area 27. Capacity: 210 MMBTU/hr. Fuel: Refinery fuel gas and natural gas.

Flexible Group ID: FG-HEATERS, FGDHOUPANNUAL

POLLUTION CONTROL EQUIPMENTMulti-staged Low NOx Burner

I. EMISSION LIMIT(S)

Pollutant LimitTime Period/

Operating ScenarioEquipment

Monitoring/TestingMethod

UnderlyingAppl icable

Requirements

1. NOX 0.20lb/MMBTU2

Annual rolling average* EG27-ZURNBOILER

SC II.2, VI.1 40 CFR 60.44b

2. CO0.10

lb/MMBTU2

Annual rolling average*EG27-

ZURNBOILERSC II.2, VI.2 R 336.1201(3)

3. PM0.0019

lb/MMBTU2

Three-hour averageEG27-

ZURNBOILERSC II.2, V.2

R 336.1205,R 336.2802,40 CFR 52.21

4. PM-100.0076

lb/MMBTU2



R 336.1205,R 336.2802,40 CFR 52.21

5. VOC0.0055

lb/MMBTU2



R 336.1205,R 336.1702(a)

* Annual average as determined at the end of each calendar month.

II. MATERIAL LIMIT(S)

Material LimitTime Period/ Operating

ScenarioEquipment

Monitoring/Testing Method


Requirements

1. Natural gas orrefinery fuel gasburned

210,000 cubicfeet per hour

based on 1,000BTU/cubic foot

2

According to Method EG27-ZURNBOILER SC VI.6R 336.1205,R 336.2802,

40 CFR 52.21

2. The permittee shall burn only refinery fuel gas or sweet natural gas in EG27-ZURNBOILER. 2(R 336.1205,R 336.1224, R 336.1225, R 336.2802, 40 CFR 52.21, 40 CFR Part 60 Subparts A & Db)

III. PROCESS/OPERATIONAL RESTRICTION(S)

1. The permittee shall comply with all provisions of the federal Standards of Performance for New StationarySources as specified in 40 CFR Part 60 Subparts A, Db, and J, as they apply to EG27-ZURNBOILER.

2

(40 CFR Part 60 Subparts A, Db, & J)


21/104


IV. DESIGN/EQUIPMENT PARAMETER(S)

1. The heat input for EG27-ZURNBOILER shall not exceed 210 MMBTU/hr on a daily average.2 (R 336.1205,

R 336.1225, R 336.1702(a), R 336.2802, 40 CFR 52.21)

2. The permittee shall equip and maintain EG27-ZURNBOILER with multi-staged low-NOX burners.2

(R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR 60.44b)

V. TESTING/SAMPLINGRecords shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. Following issuance of this permit, but not later than 180 days after commencement of trial operation of theheavy oil upgrade project and every five years thereafter, the permittee shall verify PM-10 emission ratesfrom EG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. Noless than 60 days prior to testing, the permittee shall submit a complete test plan to the AQD. For a testconducted prior to commencement of trial operation of the heavy oil upgrade project, the test plan shalldemonstrate that test conditions will be representative of post-startup conditions. The AQD must approvethe final plan prior to testing. Verification of emission rates includes the submittal of a complete report of thetest results to the AQD within 60 days following the last date of the test. For verification of PM-10

emissions, testing shall include both the filterable and condensable fractions. 2(R 336.2001, R 336.2003,R 336.2004, R 336.2803, R 336.2804, 40 CFR 52.21(c)&(d))

2. Following issuance of this permit, but not later than 180 days after commencement of trial operation of theheavy oil upgrade project and every five years thereafter, the permittee shall verify PM emission rates fromEG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No lessthan 60 days prior to testing, the permittee shall submit a complete test plan to the AQD. For a testconducted prior to commencement of trial operation of the heavy oil upgrade project, the test plan shalldemonstrate that test conditions will be representative of post-startup conditions. The AQD must approvethe final plan prior to testing. Verification of emission rates includes the submittal of a complete report of thetest results to the AQD within 60 days following the last date of the test.

2 (R 336.1205, R 336.2001,

R 336.2003, R 336.2004)

3. Following issuance of this permit, but not later than 180 days after commencement of trial operation of theheavy oil upgrade project and annually thereafter, the permittee shall verify PM emission rates fromEG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No lessthan 60 days prior to testing, the permittee shall submit a complete test plan to the AQD. For a testconducted prior to commencement of trial operation of the heavy oil upgrade project, the test plan shalldemonstrate that test conditions will be representative of post-startup conditions. The AQD must approvethe final plan prior to testing. Verification of emission rates includes the submittal of a complete report of thetest results to the AQD within 60 days following the last date of the test.

2,3(R 336.1201(3))

4. Following issuance of this permit, but not later than 180 days after commencement of trial operation of theheavy oil upgrade project and every five years thereafter, the permittee shall verify VOC emission rates fromEG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No lessthan 60 days prior to testing, the permittee shall submit a complete test plan to the AQD. For a test

conducted prior to commencement of trial operation of the heavy oil upgrade project, the test plan shalldemonstrate that test conditions will be representative of post-startup conditions. The AQD must approvethe final plan prior to testing. Verification of emission rates includes the submittal of a complete report of thetest results to the AQD within 60 days following the last date of the test.

2 (R 336.1205, R 336.1702,

R 336.2001, R 336.2003, R 336.2004)

5. Following issuance of this permit, but not later than 180 days after commencement of trial operation of theheavy oil upgrade project and annually thereafter, the permittee shall verify VOC emission rates fromEG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No lessthan 60 days prior to testing, the permittee shall submit a complete test plan to the AQD. For a testconducted prior to commencement of trial operation of the heavy oil upgrade project, the test plan shalldemonstrate that test conditions will be representative of post-startup conditions. The AQD must approve


22/104


the final plan prior to testing. Verification of emission rates includes the submittal of a complete report of thetest results to the AQD within 60 days following the last date of the test.

2,3(R 336.1201(3))

6. Following issuance of this permit, but not later than 180 days after commencement of trial operation of theheavy oil upgrade project and annually thereafter, the permittee shall verify sulfuric acid mist emission ratesfrom EG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. Noless than 60 days prior to testing, the permittee shall submit a complete test plan to the AQD. For a testconducted prior to commencement of trial operation of the heavy oil upgrade project, the test plan shalldemonstrate that test conditions will be representative of post-startup conditions. The AQD must approvethe final plan prior to testing. Verification of emission rates includes the submittal of a complete report of thetest results to the AQD within 60 days following the last date of the test.

2,3(R 336.1201(3))

7. For tests required by SC V.1 through 6, the following applies for valid, regularly scheduled tests, conductedduring normal operations:

2,3(R 336.1201(3)

a. If a test indicates non-compliance with a permitted emission rate, and the test is required to beconducted on either a three or five year cycle, the frequency of such tests shall be annual for twoconsecutive years. Following two consecutive years of compliance, the frequency of testing shall returnto the original three or five year cycle.

VI. MONITORING/RECORDKEEPINGRecords shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall install, calibrate, maintain and operate in a satisfactory manner a device to monitor andrecord the NOX and oxygen emissions from EG27-ZURNBOILER on a continuous basis. The permitteeshall install and operate the Continuous Emission Monitoring System (CEMS) in accordance with therequirements of 40 CFR 60.11, 60.13, and Part 60, Appendix A, the applicable performance specificationtest of 40 CFR Part 60 Appendices B and F. With respect to 40 CFR Part 60 Appendix F, in lieu of therequirements of 40 CFR Part 60 Appendix F 5.1.1, 5.1.3, and 5.1.4, the permittee shall conduct either aRelative Accuracy Audit (RAA) or a Relative Accuracy Test Audit (RATA) once every twelve (12) calendarquarters, provided that a Cylinder Gas Audit is conducted each calendar quarter. Within 30 days followingthe end of each calendar quarter, the permittee shall submit the results to the AQD in the format of the dataassessment report.

2 (R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR Part 60 Subparts A and Db,

40 CFR 60.48b)

2. The permittee shall install, calibrate, maintain and operate in a satisfactory manner a device to monitor andrecord the CO and oxygen emissions from EG27-ZURNBOILER on a continuous basis. The permittee shallinstall and operate the CEMS in accordance with the requirements of 40 CFR 60.11, 60.13, and Part 60,

Appendix A, the applicable performance specification test of 40 CFR Part 60 Appendices B and F. Withrespect to 40 CFR Part 60 Appendix F, in lieu of the requirements of 40 CFR Part 60 Appendix F 5.1.1,5.1.3, and 5.1.4, the permittee shall conduct either a Relative Accuracy Audit (RAA) or a Relative AccuracyTest Audit (RATA) once every twelve (12) calendar quarters, provided that a Cylinder Gas Audit isconducted each calendar quarter. Within 30 days following the end of each calendar quarter, the permitteeshall submit the results to the AQD in the format of the data assessment report.

2(R 336.1205, R 336.2802,

40 CFR 52.21)

3. Permittee shall monitor and keep records of the concentration of hydrogen sulfide in the refinery fuel gasburned in EU27-ZURNBOILER in accordance with the Federal Standards of Performance as specified in 40CFR 60, Subpart J, in a manner and with instrumentation acceptable to the Division. Fuel gas combustiondevices having a common source of fuel gas may be monitored at only one location, if monitoring at thislocation accurately represents the concentration of H2S in the fuel gas being burned.

2

(40 CFR 60.105(a)(4))

4. The permittee shall monitor emissions and operating information for EU27-ZURNBOILER in accordancewith the federal Standards of Performance for New Stationary Sources as specified in 40 CFR Part 60Subparts A, Db, and J.

2(R 336.1205, 40 CFR Part 60 Subparts A, Db, & J)


23/104


5. The permittee shall keep records of emissions and operating information to comply with the federalStandards of Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A, Db, andJ. The permittee shall keep all source emissions data and operating information on file at the facility andmake them available to the Department upon request.

2(R 3361205, 40 CFR Part 60 Subparts A, Db, & J)

6. The permittee shall install, calibrate, maintain and operate in a satisfactory manner a device to monitor andrecord the natural gas and refinery fuel gas usage rate in EU27-ZURNBOILER on an hourly basis. Thepermittee shall determine the heat value of the gas burned in Btu per cubic foot on a monthly basis fromsamples taken at a point in the pipeline to EU27-ZURNBOILER on the permittee's property. Upon request,the AQD District Supervisor may authorize a different sampling schedule. Each day, the permittee shalldetermine the heat input rate to EU27-ZURNBOILER for the previous operating day.

2 (R 336.1205,

R 336.2802, 40 CFR 52.21)

VII. REPORTING

NA

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwardsto the ambient air unless otherwise noted:

Stack & Vent IDMaximum Exhaust

Dimensions(inches)

Minimum HeightAbove Ground

(feet)

Underlying Applicable Requirements

1.SV27-BR7 72 150 R 336.1225

IX. OTHER REQUIREMENT(S)

1. The permittee shall comply with all applicable provisions of the federal Standards of Performance for New

Stationary Sources as specified in 40 CFR Part 60 Subpart A-General Provisions, Subpart Db-Standards ofPerformance for Industrial-Commercial-Institutional Steam Generating Units, and Subpart J-Standards ofPerformance for Petroleum Refineries, as they apply to EG27-ZURNBOILER.

2(40 CFR Part 60 Subparts

A, Db, and J)

Footnotes:1This condition is state only enforceable and was established pursuant to Rule 201(1)(b).

2This condition is federally enforceable and was established pursuant to Rule 201(1)(a).

3This condition is included at the request of the permittee.

TABLE E-1.15 {EU27-B&WBOILER1}

EMISSION UNIT/PROCESS GROUP REQUIREMENTSEMISSION GROUP Gas-fired boiler, capacity: 200,000 pounds steam per hour at 600 psig;

design heat input not to exceed 300 MMBtu/hr. Fuel: Refinery fuel gas andnatural gas.

Flexible Grouping ID FG-HEATERS, FGDHOUPANNUAL

I. DESIGN PARAMETERS

A. Pol lution ControlEquipment

Low NOx Burner, Flue Gas Recirculation system.


24/104



EMISSION UNIT/PROCESS GROUP REQUIREMENTSB. Stack/Vent Parameters Exhaust gases shall be discharged unobstructed vertically upwards unless

otherwise noted.

Stack/Vent ID

a.

MinimumHeight(feet)

b. Maximum

ExhaustDimension

(inches)

c.

Temp(F)

d.

Air FlowRate

(acfm)


1. SV-B&WBOILER1 150 63 NA NA R 336.1225


1. The maximum heat input in the boiler shall not exceed 300 million BTUs per hour. (R 336.1801, 40 CFRPart 60 Subpart Db)

2. Permittee shall only burn sweet natural gas or refinery fuel gas as fuel for the boiler. (R 336.1201(3),R 336.2802, 40 CFR Part 60 Subpart Db, 40 CFR 52.21)

II. MATERIAL USAGE/EMISSION LIMITS

A. Material Maximum Usage Rate

1. Natural Gas or refinery fuel

gas

1. 300,000 cubic feet per hour based on 1,000 BTU/ft3 (R 336.1801,

40 CFR Part 60 Subpart Db)B. Pollutant Maximum Emission Limit

1. Nitrogen Oxide (NOx)emissions

1. 0.20 pounds per million BTUs heat input, based upon a 24-houraverage. (R 336.2802, 40 CFR 52.21, 40 CFR Part 60 Subpart Db)

2. 0.05 pounds per million BTUs heat input, based on an annual rollingaverage, as determined at the end of each calendar month.

3

(R 336.1201(3))

2. Carbon monoxide (CO)emissions

1. 400 ppmv(1)

, based upon a 24-hour average(R 336.1201(3))2. 0.028 pounds per million BTUs heat input, based on an annual rolling

average, as determined at the end of each calendar month.3

(R 336.1201(3))

3. PM-10 1. 0.0076 pounds per million BTUs heat input, based upon a three-houraverage. (R 336.1205)

4. PM 1. 0.0019 pounds per million BTUs heat input, based upon a three-houraverage. (R 336.1205)

5. VOC 1. 0.0055 pounds per million BTUs heat input, based on a three-hourrolling average. (R 336.1205, R 336.1702(a))

6. Sulfur dioxide (SO2)emissions

1. The H2S content of the refinery fuel gas shall not exceed 160 ppmv on a3 hour rolling average basis. (40 CFR 60.104(a)(1))

(1) @ 3 % excess oxygen

III. COMPLIANCE EVALUATIONRecords of all of the fol lowing shall be maintained on file for a period o f five years. (R 336.1213(3)(b)(ii))


1. Continuous EmissionMonitoring (CEM) Systemand Recordkeeping

1. Nitrogen Oxide emissions. (R 336.1205, R 336.2802, 40 CFR 52.21,40 CFR Part 60 Subpart Db)

2. CO (R 336.1205, R 336.2802, 40 CFR 52.21)

3. Oxygen. (R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR Part 60Subpart Db)

4. The permittee shall install, certify, calibrate, maintain, and operate theCEMS in accordance with the requirements of 40 CFR 60.11, 60.13,and Part 60, Appendix A, the applicable performance specification testof 40 CFR Part 60 Appendices B and F. With respect to 40 CFR Part 60

Appendix F, in lieu of the requirements of 40 CFR Part 60 Appendix F


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EMISSION UNIT/PROCESS GROUP REQUIREMENTS5.1.1, 5.1.3, and 5.1.4, the permittee shall conduct either a Relative

Accuracy Audit (RAA) or a Relative Accuracy Test Audit (RATA) onceevery twelve (12) calendar quarters, provided that a Cylinder Gas Audit

is conducted each calendar quarter. Within 30 days following the end ofeach calendar quarter, the permittee shall submit the results to the AQDin the format of the data assessment report.

2. Process Monitoring Systemand Recordkeeping

1. Records of emissions and operating information is required to complywith the federal Standards of Performance for New Stationary Sourcesas specified in 40 CFR Part 60, Subparts A, Db, and J. All sourceemissions data and operating data shall be kept on file for a period of atleast five years and made available to the Department upon request.(R 336.1205, 40 CFR Part 60 Subpart A, Db and J)

2. Records of emissions are required. All source emissions data shall bekept on file for a period of at least five years and made available to the

Department upon request. (R 336.1205, R 336.2802, 40 CFR 52.21)3. Other Monitoring and/or

Recordkeeping1. Hourly records of fuel consumption and firing rate. (R 336.1205,

40 CFR Part 60 Subpart Db)



1. NA

2. Method/Analysis 1. NA


1. NA

IV. REPORTING

Reports and Schedules

V. OPERATIONAL PARAMETERS

1. Permittee shall not operate the boiler unless the low NOx burners are installed and operating properly.(R 336.1205, R 336.1901, 40 CFR 52.21(c) and (d), 40 CFR Part 60)

3. Permittee shall not operate EU27-B&WBOILER1 at firing rates of 50 to 300 MMBtu/hr heat input unlessthe Flue Gas Recirculation system is installed, maintained, and operated in a satisfactory manner.(R 336.1205, R 336.1224, R 336.1225, R 336.1901, R 336.2802, 40 CFR 52.21, 40 CFR Part 60)


1. Permittee shall comply with all applicable requirements of 40 CFR Part 60-Standards of Performance forNew Stationary Sources, Subpart A-General Provisions, Subpart Db-Standards of Performance forIndustrial-Commercial-Institutional Steam Generating Units, and Subpart J-Standards of Performance forPetroleum Refineries. (40 CFR Part 60 Subpart A, Db, J)



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TABLE E-1.23 {EG42-43SULRECOV}

EMISSION UNIT/PROCESS GROUP REQUIREMENTSEMISSION GROUP Three Claus Sulfur Recovery Trains, two SCOT Tailgas Treating Units

and one Thermal Oxidizer (subject to 40 CFR 60, Subpart J)

Flexible Grouping ID FG-PROCUNITS, FGDHOUPANNUAL

I. DESIGN PARAMETERS

A. Pollution Control Equipment Thermal Oxidizer (Incinerator)

B. Stack/Vent Parameters Exhaust gases shall be discharged unobstructed vertically upwards unlessotherwise noted.

Stack/Vent ID a.MinimumHeight(feet)

b.MaximumExhaust

Dimension(inches)

c.Temp(F)

d.Air Flow

Rate(acfm)


1. SV43-H2 199.5 42.5 NA NA R 336.1225R 336.1226(d)


1. The maximum heat input in the thermal oxidizer shall not exceed 25 million BTUs per hour or 219,000 million

BTUs per year. (R 336.1205, R 336.1702, R 336.2802, 40 CFR 52.21)

II. MATERIAL USAGE/EMISSION LIMITS

A. Mater ial Maximum Usage Rate

1. Natural gas in the thermal oxidizer 1. 25,000 cubic feet per hour based on 1,000 Btu/scf. (R 336.1225,40 CFR 52.21)

1. NA 1. NA

B. Pollutants Maximum Emission Limit

1. Sulfur dioxide emissions from thethermal oxidizer that controls thetail gas treatment units, No. 1 andNo. 2.

1. 250 Parts per million by volume at zero percent oxygen on a drybasis. (40 CFR 60.104(a)(2))

2. 175 Parts per million by volume at zero percent oxygen on a drybasis on an annual rolling average, as determined at the end of eachcalendar month.

3(R 336.1201(3))

2. Nitrogen oxide emission rate fromthe thermal oxidizer

1. 7.5 pounds per hour (R 336.1205, R 336.2802, 40 CFR 52.21)

3. Carbon monoxide emission ratefrom the thermal oxidizer

1. 0.04 lb/MMBTU, based on a three-hour average. (R 336.2802,40 CFR 52.21)

4. Particulate matter emission ratefrom the thermal oxidizer

1. 0.08 lb/MMBTU. (R 336.1205, R 336.2802, 40 CFR 52.21)

5. PM10 emission rate from thethermal oxidizer

1. 0.08 lb/MMBTU. (R 336.2802, 40 CFR 52.21)

6. Volatile organic compoundemission rate from the thermaloxidizer

1. 0.0055 lb/MMBTU. (R 336.1205, R 336.1702, R 336.2802,40 CFR 52.21)

III. COMPLIANCE EVALUATIONRecords of all of the follow ing shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))


1. Continuous EmissionMonitoring (CEM) System andRecordkeeping

1. SO2 continuous emissions (CEMS). (R 336.2802, 40 CFR 52.21,40 CFR Part 60 Subparts A and J)

2. Oxygen. (R 336.2802, 40 CFR 52.21, 40 CFR Part 60 Subparts Aand J)

3. The permittee shall install, certify, calibrate, maintain, and operate theCEMS in accordance with the requirements of 40 CFR 60.11,60.13, and Part 60, Appendix A, the applicable performancespecification test of 40 CFR Part 60 Appendices B and F.(R 336.2802, 40 CFR 52.21, 40 CFR Part 60 Subparts A and J)


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EMISSION UNIT/PROCESS GROUP REQUIREMENTS2. Process Monitoring System

and Recordkeeping1. NA

3. Other Monitoring and/orRecordkeeping

1. Daily combined amount of sulfur produced in the sulfur recovery unitsA, B and C, in long tons. (R 336.1201(3))

2. Long tons of sulfur produced per day, on a 12-month rolling average,in sulfur recovery units A, B and C combined. (R 336.1201(3))

3. Temperature from the thermal oxidizer in a continuous manner withinstrumentation acceptable to the division. (R 336.1201(3)

4. Amount of natural gas usage in the thermal oxidizer. (R 336.1225)5. Emissions and operating information in accordance with the federal

Standards of Performance for New Stationary Sources as specified in40 CFR Part 60, Subparts A and J. (40 CFR 60.105, 40 CFR Part 60Subparts A and J)



1. Sulfur dioxide concentration. (R 336.1205, R 336.2802, 40 CFR52.21, 40 CFR Part 60 Subparts A and J)

2. Within 180 days after commencement of trial operation and every fiveyears thereafter, the permittee shall verify NOX emission rates fromEG42-43SULRECOV by testing at owner's expense, in accordancewith Department requirements. No less than 60 days prior to testing,the permittee shall submit a complete test plan to the AQD. The AQDmust approve the final plan prior to testing. Verification of emissionrates includes the submittal of a complete report of the test results tothe AQD within 60 days following the last date of the test.(R 336.1205, R 336.2001, R 336.2003, R 336.2004, R 336.2802,40 CFR 52.21)

3. Within 180 days after commencement of trial operation and every five

years thereafter, the permittee shall verify CO emission rates fromEG42-43SULRECOV by testing at owner's expense, in accordancewith Department requirements. No less than 60 days prior to testing,the permittee shall submit a complete test plan to the AQD. The AQDmust approve the final plan prior to testing. Verification of emissionrates includes the submittal of a complete report of the test results tothe AQD within 60 days following the last date of the test.(R 336.2001, R 336.2003, R 336.2004, R 336.2802, 40 CFR 52.21)

4. Within 180 days after commencement of trial operation and every fiveyears thereafter, the permittee shall verify PM-10 emission rates fromEG42-43SULRECOV by testing at owner's expense, in accordancewith Department requirements. No less than 60 days prior to testing,

the permittee shall submit a complete test plan to the AQD. The AQDmust approve the final plan prior to testing. Verification of emissionrates includes the submittal of a complete report of the test results tothe AQD within 60 days following the last date of the test. Forverification of PM-10 emissions, testing shall include both thefilterable and condensable fractions. (R 336.2001, R 336.2003,R 336.2004, R 336.2802, 40 CFR 52.21)

5. Within 180 days after commencement of trial operation and every fiveyears thereafter, the permittee shall verify PM emission rates fromEG42-43SULRECOV by testing at owner's expense, in accordancewith Department requirements. No less than 60 days prior to testing,


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EMISSION UNIT/PROCESS GROUP REQUIREMENTSthe permittee shall submit a complete test plan to the AQD. The AQDmust approve the final plan prior to testing. Verification of emissionrates includes the submittal of a complete report of the test results to

the AQD within 60 days following the last date of the test.(R 336.1205, R 336.2001, R 336.2003, R 336.2004, R 336.2802,40 CFR 52.21)

6. Within 180 days after commencement of trial operation and every fiveyears thereafter, the permittee shall verify VOC emission rates fromEG42-43SULRECOV by testing at owner's expense, in accordancewith Department requirements. No less than 60 days prior to testing,the permittee shall submit a complete test plan to the AQD. The AQDmust approve the final plan prior to testing. Verification of emissionrates includes the submittal of a complete report of the test results tothe AQD within 60 days following the last date of the test.(R 336.1205, R 336.1702, R 336.2001, R 336.2003, R 336.2004,

R 336.2802, 40 CFR 52.21)

7. Within 180 days after commencement of trial operation and everythree years thereafter, the permittee shall verify sulfuric acid mistemission rates from EG42-43SULRECOV by testing at owner'sexpense, in accordance with Department requirements. No less than60 days prior to testing, the permittee shall submit a complete testplan to the AQD. The AQD must approve the final plan prior totesting. Verification of emission rates includes the submittal of acomplete report of the test results to the AQD within 60 days followingthe last date of the test.

3 (R 336.1201(3))

8. For tests required by SC III.B.1.2 through 7, the following applies forvalid, regularly scheduled tests, conducted during normal operations:

3

(R 336.1201(3))a. If a test indicates non-compliance with a permitted emission rate,

and the test is required to be conducted on either a three or fiveyear cycle, the frequency of such tests shall be annual for twoconsecutive years. Following two consecutive years ofcompliance, the frequency of testing shall return to the originalthree or five year cycle.

2. Method/Analysis 1. Methods acceptable to division. (40 CFR Part 60 Subparts A and J)2. Methods acceptable to division. (R 336.1205, R 336.2001,

R 336.2003, R 336.2004, R 336.2803, R 336.2804)3. Methods acceptable to division. (R 336.2001, R 336.2003,

R 336.2004, R 336.2804)4. Methods acceptable to division. (R 336.2001, R 336.2003,

R 336.2004, R 336.2803, R 336.2804)5. Methods acceptable to division (R 336.1205, R 336.2001, R 336.2003,

R 336.2004)6. Methods acceptable to division. (R 336.1205, R 336.1702,

R 336.2001, R 336.2003, R 336.2004)


1. As required by the division. (40 CFR Part 60 Subparts A and J)2. As required by the division. (R 336.1205, R 336.2001, R 336.2003,

R 336.2004)3. As required by the division. (R 336.2001, R 336.2003, R 336.2004)


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EMISSION UNIT/PROCESS GROUP REQUIREMENTS4. As required by the division. (R 336.2001, R 336.2003, R 336.2004)5. As required by the division. (R 336.1205, R 336.2001, R 336.2003,

R 336.2004)

6. As required by the division. (R 336.1205, R 336.1702, R 336.2001,R 336.2003, R 336.2004)

IV. REPORTING

Reports and Schedules 1. The permittee shall not operate EG42-43SULRECOV unless theapproved Operation, Maintenance and Monitoring Plan, or analternate plan approved by the AQD District Supervisor, isimplemented. The plan shall contain all information required by40 CFR 63.1564(a)(3). (40 CFR 63.1564(a)(3)

V. OPERATIONAL PARAMETERS

1. Permittee shall not produce more than a monthly average 145 long tons of sulfur per day, nor more than 100long tons of sulfur per day on a rolling 12-month average, in the sulfur recovery units A, B and C combined.(R 336.1201(3))

2. Permittee shall not operate the sulfur recovery units A, B, and C and the tail gas treatment units No. 1and No. 2, unless the thermal oxidizer and oxygen analyzer are installed and operating properly.(R 336.1205, R 336.1224, R 336.1225, R 336.1702, R 336.2802, 40 CFR 52.21, R 336.1901, R 336.1910,40 CFR 60.104(a)(2)(i))

3. Permittee shall not operate the sulfur recovery units A, B, and C and the tail gas treatment units No. 1 andNo. 2, unless a minimum temperature of 1,200 degrees Fahrenheit and a minimum retention time of 2.0seconds in the thermal oxidizer is maintained. Following both the promulgation of Subpart Ja in 40 CFRPart 60 and the successful completion of a stack test pursuant to that Subpart, and upon written approval bythe AQD District Supervisor, the temperature and retention time requirements of this condition will besuperseded by the temperature and retention time demonstrated during the stack test and stated in the writtenapproval. (R 336.1205, R 336.1224, R 336.1225, R 336.1702, R 336.2802, 40 CFR 52.21, R 336.1901,

R 336.1910, 40 CFR 60.104(a)(2)(i))

4. Permittee shall not operate the sulfur recovery units A, B, and C and the tail gas treatment units No. 1 andNo. 2, unless provisions of the Federal Standards of Performance for New Source Stationary Sources, 40 CFRPart 60, Subpart J-Standards of Performance for Petroleum Refineries, are met. (40 CFR Part 60 Subparts A& J)

5. The permittee shall submit to the AQD District Supervisor, for review and approval, a Startup, Shutdown andMalfunction Plan (SSMP) for EG42-43SULRECOV. The permittee shall not operate EG42-43SULRECOVunless the approved SSMP, or an alternate plan approved by the AQD District Supervisor, is implemented andmaintained. The plan shall include procedures for maintaining and operating in a satisfactory manner,FG42-43SULRECOV, add-on air pollution control device, or monitoring equipment during malfunction events,and a program for corrective action for such events. If the SSMP fails to address or inadequately addresses

an event that meets the characteristics of a malfunction at the time the plan is initially developed, the owner oroperator shall revise the malfunction abatement plan within 45 days after such an event occurs. (40 CFRPart 63, Subparts A and UUU)


1. Monitoring and recording of sulfur dioxide concentration and operating information is required to comply withthe Federal Standards of Performance for New Stationary Sources as specified in 40 CFR, Part 60, Subparts

A and J. All source emissions data and operating data shall be submitted to the Division in an acceptableformat within 30 days following the end of the quarter in which data were collected. (R 336.1205, R 336.2802,40 CFR 52.21, 40 CFR Part 60 Subparts A and J, 40 CFR 60.105(a)(5))


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EMISSION UNIT/PROCESS GROUP REQUIREMENTS2. Permittee shall comply with all the applicable requirements of 40 CFR Part 60: Standards of Performance for

New Sources, Subpart A-General Provisions. (R 336.1213(3), (40 CFR Part 60, Subpart A)

3. Permitteeshall comply with all applicable requirements of 40 CFR Part 63, Subpart UUU-National EmissionStandards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic ReformingUnits, and Sulfur Recovery Units. (R 336.1213(3)), (40 CFR 63, Subpart UUU)



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EG70-COKER

EMISSION UNIT CONDITIONS

DESCRIPTION

The Coker converts Vacuum Resid (Crude Vacuum Tower Bottoms), a product normally sold as asphalt orblended into residual fuel oil, into lighter, more valuable products. The Vacuum Resid feedstock is heatedbefore it enters the main fractionator, where lighter material vaporizes. The fractionator bottoms are routedthrough a fired heater and then into a coke drum. This emission unit consists of process vessels (fractionators),coke drums, heater, cooling tower, compressors, pumps, piping, drains, & various components (pumps &compressor seals, process valves, pressure relief valves, flanges, connectors, etc.). This emission groupincludes the Coke Handling System, which will collect, size, and transport the petroleum coke created during thecoking process. This system consists of a coke pit, storage pad, enclosed crusher, enclosed conveyors, andsurge bins. Other EGs were created to address individual pieces of equipment within this unit that have specificapplicable requirements.

Flexible Group ID: FGDHOUPANNUAL

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant LimitTime Period/

Operating ScenarioEquipment



Requirements

1. Visibleemissions

No visibleemissions

2

According to method

Truck loading; weighbins; and the cokehandling system

beginning with theenclosed conveyorleading to the crusher.

SC VI.2 R 336.1301

2. VOC 20 tpy2 According to method

Exhaust from cokedrum steam vent.

SC VI.8 R 336.1702

3. PM 1.0 tpy2 According to method


SC VI.8R 336.1205,R 336.2802,40 CFR 52.21

4. H2S 0.7 tpy1 According to method


SC VI.8R 336.1224,R 336.1226(d)

II. MATERIAL LIMIT(S)

Material LimitTime Period/ Operating

ScenarioEquipment



Requirements

1. Moisturecontent of coke

Minimum 6% byweight

2

According to method

Coke handlingoperations after the

coke has beenremoved from the

coke drum.

SC VI.3R 336.1205,R 336.2802,40 CFR 52.21

2. Cokeproduction

500 tons perhour

2

Daily averageEquipment subject to

SC I.1.SC VI.4

R 336.1205,R 336.2802,40 CFR 52.21


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3. The permittee shall not recycle coker blowdown water as quench water in the coke drums. (R 336.1205,R 336.2802, 40 CFR 52.21)

III. PROCESS/OPERATIONAL RESTRICTION(S)

1. The permittee shall not vent the active coke drum to the atmosphere until the end of the coking cycle, whenthe drum pressure is 2 psig or less. 2(R 336.1205, R 336.1702, R 336.2802, 40 CFR 52.21)

2. The permittee shall not remove coke from a coke drum or handle coke after removal from a coke drumunless a program for continuous fugitive emissions control has been submitted to the AQD DistrictSupervisor as a proposed revision to the Fugitive Dust Control Program required in Table B-1 of RO Permit199700013c. The proposed revision shall address the following aspects of the coke handling system: allplant roadways, the plant yard, all material storage piles, and all material handling operations. Thesubmitted program shall include, as a minimum, all of the following:

a. Use of jet water sprays to empty the coke drum into a coke pit below the grade of the coke storagepad.

b. Use of water sprays on any coke stockpile and during coke crushing to maintain coke moisture

MDEQ Marathon Petroleum Permit 63-08C

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