MICHIGAN DEPARTMENT OF ENVIRONMENTAL QUALITY 

AIR QUALITY DIVISION 

January 11, 2012 

PERMIT TO INSTALL 

63-08C 

ISSUED TO 

Marathon Petroleum Company LP 

LOCATED AT 

1300 South Fort Street 

Detroit, Michigan 

IN THE COUNTY OF 

Wayne 

STATE REGISTRATION NUMBER 

A9831 

The Air Quality Division has approved this Permit to Install, pursuant to the delegation of authority 

from the Michigan Department of Environmental Quality. This permit is hereby issued in 

accordance with and subject to Section 5505(1) of Article II, Chapter I, Part 55, Air Pollution 

Control, 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 permittee’s 

authority to install the identified emission unit(s) in accordance with all administrative rules of the 

Department and the attached conditions. Operation of the emission unit(s) identified in this Permit 

to 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, 2012 

SIGNATURE: 

 DATE PERMIT VOIDED: SIGNATURE: 

 DATE PERMIT REVOKED: SIGNATURE: 

 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit 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 ......................................................................................................................... 14

EG11-FCCU...................................................................................................................................................... 14

EG27-ZURNBOILER......................................................................................................................................... 19

EU27-B&WBOILER1......................................................................................................................................... 22

EG42-43SULRECOV........................................................................................................................................ 25

EG70-COKER ................................................................................................................................................... 30

EG-COKERFLARE ........................................................................................................................................... 34

EG72-SULRBLOCK2........................................................................................................................................ 37

Flexible Group Special Conditions........................................................................................................................ 41

FG-HEATERS ................................................................................................................................................... 41

FGFLARES ....................................................................................................................................................... 53

FG-PROCVENTS.............................................................................................................................................. 61

FGGROUP2 ...................................................................................................................................................... 62

FG-IFRTANKS .................................................................................................................................................. 64

FG-EFRTANKS................................................................................................................................................. 70

FG29-IGF .......................................................................................................................................................... 76

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

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

FG-NAPHTHATANKS....................................................................................................................................... 83

FG-COOLTOWERS.......................................................................................................................................... 86

FG-FirePumps................................................................................................................................................... 90

FGDHOUPANNUAL.......................................................................................................................................... 92

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

Appendices ........................................................................................................................................................... 99

Appendix A: Continuous Emission Monitoring System Requirements for NOX, SO2, O2, and CO................... 99

Appendix B: Recordkeeping Provisions – Actual to Projected-Actual Applicability Test................................ 100
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 2 of 103 

 

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 foot 

CEM 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 

MDEQ Michigan Department of Environmental 

Quality PM Particulate Matter 

MIOSHA Michigan Occupational Safety & Health 

Administration PM10 PM less than 10 microns diameter 

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

NESHAP National Emission Standard for Hazardous 

Air Pollutants pph 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 μg Microgram 

TAC 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 not 

exceed ten (10) pounds per square inch gauge (psig). 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 3 of 103 

GENERAL CONDITIONS 

1. The process or process equipment covered by this permit shall not be reconstructed, relocated, or 

modified, unless a Permit to Install authorizing such action is issued by the Department, except to the 

extent 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 this 

permit 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 permittee 

or the designated authorized agent shall notify the Department via the Supervisor, Permit Section, Air 

Quality Division, Michigan Department of Environmental Quality, P.O. Box 30260, Lansing, Michigan 

48909, if it is decided not to pursue the installation, construction, reconstruction, relocation, or modification 

of 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 is 

not subject to the Renewable Operating Permit program requirements pursuant to R 336.1210, operation 

of the process or process equipment is allowed by this permit if the equipment performs in accordance 

with 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 evidence 

indicates the process or process equipment is not performing in accordance with the terms and conditions 

of this permit or is violating the Department’s 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 or 

hereafter owns or operates the process or process equipment at the location authorized by this Permit to 

Install. If the new owner or operator submits a written request to the Department pursuant to R 336.1219 

and the Department approves the request, this permit will be amended to reflect the change of ownership 

or 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 of 

Environmental 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 which 

causes 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 that 

results in emissions of a hazardous or toxic air pollutant which continue for more than one hour in excess 

of any applicable standard or limitation, or emissions of any air contaminant continuing for more than two 

hours in excess of an applicable standard or limitation, as required in Rule 912, to the Department. The 

notice shall be provided not later than two business days after start-up, shutdown, or discovery of the 

abnormal condition or malfunction. Written reports, if required, must be filed with the Department within 

10 days after the start-up or shutdown occurred, within 10 days after the abnormal conditions or 

malfunction 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 applicable 

requirements which may be promulgated under Part 55 of 1994 PA 451, as amended or the Federal 

Clean Air Act. 

9. Approval of this permit does not obviate the necessity of obtaining such permits or approvals from other 

units 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 amended 

and the rules promulgated thereunder. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 4 of 103 

11. Except as provided in subrules (2) and (3) or unless the special conditions of the Permit to Install include 

an alternate opacity limit established pursuant to subrule (4) of R 336.1301, the permittee shall not cause 

or permit to be discharged into the outer air from a process or process equipment a visible emission of 

density greater than the most stringent of the following. The grading of visible emissions shall be 

determined 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 required 

operating efficiency. The collection and disposal of air contaminants shall be performed in a manner so 

as to minimize the introduction of contaminants to the outer air. Transport of collected air contaminants in 

Priority 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 permittee’s 

expense, in accordance with R 336.2001 and R 336.2003, under any of the conditions listed in 

R 336.2001. (R 336.2001) 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 5 of 103 

SPECIAL CONDITIONS 

Emission Unit Identification

Emission Unit ID Emission Unit Description * Stack Identification 

EG05-CRUDE Crude Unit. Area 5. The crude unit 

separates crude oil into various fractions 

through the use of distillation processes. 

These fractions are sent to other units in the 

refinery for further processing. The crude unit 

consists of process vessels (including heat 

exchangers and fractionation columns), the 

Alcorn heater, tanks, containers, 

compressors, pumps, piping, drains and 

various components (pump and compressors 

seals, process valves, pressure relief valves, 

flanges, connectors, etc.). Other EG’s have 

been created to address individual pieces of 

equipment within the crude unit which have 

specific applicable requirements. Permit: 

262-02 

None 

EG05-CRUDEHTR Crude Alcorn Heater, Area 5, Fuel: Refinery 

fuel gas, and Natural gas, Permit: 108-02, 

262-02, 175-06 

SV04-H1-05-H1 

EG04-VACUUM Vacuum Unit. Area 4. The vacuum unit 

separates the reduced crude from the crude 

unit through the use of a vacuum column. 

The reduced crude is separated into light 

vacuum gas oil, medium vacuum gas oil, 

heavy vacuum gas oil, and a bottoms product 

called flux. The various fractions are sent to 

other units in the refinery for further 

processing. The vacuum unit consists of 

process vessels (including heat exchangers 

and vacuum column), two process heaters, 

tanks, containers, 2 cooling towers, flare, 

compressors, pumps, piping drains, and 

various components (pumps and compressor 

seals, process valves, pressure relief valves, 

flanges, connectors, etc.). Other EG’s have 

been created to address individual pieces of 

equipment within the vacuum unit that have 

specific applicable requirements. Permit 

262-02 

None 

EG04-VACHTR Vacuum Heater. Area 4. Fuel: Refinery fuel 

gas and natural gas. Permit: 108-02, 262-02, 

175-06 

SV04-H1-05-H1 

EG04-VAC2HTR Vacuum Heater. Area 4. Fuel: Refinery fuel 

gas and natural gas. 

SV04-H2 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 6 of 103 

Emission Unit ID Emission Unit Description * Stack Identification 

EG08-GOHT Gasoil Hydrotreater Unit: Area 8. Reacts 

sour gasoil streams with hydrogen over a 

catalyst bed to remove sulfur. The GOHT 

unit 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 & compressor 

seals, process valves, pressure relief valves, 

flanges, connectors, etc.). Other EG’s were 

created to address individual pieces of 

equipment within this unit that have specific 

applicable 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 unit 

reacts isobutane with olefins in the presence 

of sulfuric acid to produce alkylate, a high 

octane gasoline blending component. 

Reaction products are sent for further 

processing and separation in the fractionating 

section. Products from the unit include offgas, alkylate, butane, isobutane, and 

propane. Off-gas is routed to the refinery fuel 

gas system. Alkylate, butane, and propane 

are directed to storage. Isobutane is recycled 

through the system for further processing. 

Alkylation unit consists of process vessels 

(including fractionators, reactor and caustic 

scrubber), heaters, tanks, containers, cooling 

tower, flare, compressors, pumps, piping, 

drains, and various components (pump and 

compressor seals, process valves, pressure 

relief valves, flanges, connectors, etc.) Other 

EG’s were created to address individual 

pieces of equipment within the Alkylation Unit 

which have specific applicable requirements. 

Permit 262-02. 

None 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 7 of 103 

Emission Unit ID Emission Unit Description * Stack Identification 

EG11-FCCU Fluid Catalytic Cracking Unit. Area 11. The 

FCCU converts heavier hydrocarbons to 

lighter products in the presence of a catalyst. 

In the process coke is deposited on the 

catalyst. The spent catalyst is moved to the 

regenerator 

(11-V1) where the coke is burned off using 

air. The regenerator is equipped with 

cyclones to capture catalyst (11-

V1CYCLONES). The hot flue gas from the 

regenerator is directed to a flue gas cooler 

where heat is recovered as steam. The 

FCCU consists of process vessels (reactors, 

regenerator, fractionators, knock-out pots, 

and strippers) 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.). 

Other EGs have been created to address 

equipment that has specific applicable 

requirements. Permit 262-02, 28-02A, 175-

06.

SVFCCU 

EG12-GASCON Gas Concentration Unit. Area 12. The Gas 

Con Unit processes liquids and off-gases 

from the FCCU main column overhead and 

various other hydrocarbons (liquid and gas) 

and produces gasoline and liquid petroleum 

gas. The Gas Con Unit consists of process 

vessels (including reboilers, condensers, 

exchangers, absorbers, and distillation 

columns) tanks, containers, compressors, 

pumps, piping, drains, and various 

components, (pump and compressor seals, 

process valves, pressure relief valves, 

flanges, connectors, etc.). Other EG’s have 

been created to address individual pieces of 

equipment with the Gas Concentration Unit 

that have specific applicable requirements. 

Permit 262-02.

None 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 8 of 103 

Emission Unit ID Emission Unit Description * Stack Identification 

EG16-NAPHHYTREAT Naphtha Hydrotreater Unit – Area 16. The 

NHT unit uses hydrogen to remove sulfur and 

nitrogen from straight-run and coker 

naphthas. The process uses a catalyst to 

promote the desulfurization reaction. The 

desulfurized or sweet naphtha is blended into 

gasoline or used for platformer feed. The 

NHT unit consists of process vessels 

(including exchangers, reactors, receivers, 

separators, and a stripper column.) heaters, 

tanks, containers, pumps, piping, drains, and 

various components, (pump seals, process 

valves, pressure relief valves, flanges, 

connectors, etc. Other EG’s have been 

created to address individual pieces of 

equipment which have specific applicable 

requirements. Permit 262-02.

None 

EG16-NHTSTRIPREBOIL Naphtha Hydrotreater Stripper Reboiler. 

Area 16. Fuel: Refinery fuel gas, and natural 

gas. Permits: C-11495, 108-02, 262-02 

SV16-H3 

EG16-NHTCHARHTR Naphtha Hydrotreater Charge Heater. Area 

16. Fuel: refinery fuel gas and natural gas. 

Permit: C-11493, 108-02, 262-02 

SV16-H4 

EG19-KEROHYTREAT Kerosene Hydrotreater Unit. Area 19. The 

KHT unit uses hydrogen to remove sulfur and 

nitrogen from kerosene (and occasionally 

Naphtha). The process, called hydrotreating, 

uses a catalyst with hydrogen and 

temperature to promote the desulfurization 

reactor. The KHT unit consists of process 

vessels (including exchangers, a reactor, a 

receiver, separators, and a stripper column), 

a heater, tanks, containers, pumps, 

compressors, piping, drains, and various 

components (pump, and compressors, seals, 

process valves, pressure relief valves, 

flanges, connectors, etc.). Another EG have 

been 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 group 

covers the three tanks farm areas. Permit 

262-02 

None 

EG27-ZURNBOLER Gas-fired boiler, Area 27. Fuel: Refinery fuel 

gas and natural gas. Permit C-9022. 

SV27-BR7 

EU27-B&WBOILER1 Gas-fired boiler, Area 27. Fuel: Refinery fuel 

gas and natural gas. Permit 67-02. 

SV-B&WBOILER1 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 9 of 103 

Emission Unit ID Emission Unit Description * Stack Identification 

EG70-COKER Delayed Coker. Area 70. The Coker 

converts Vacuum Resid (Crude Vacuum 

Tower Bottoms), a product normally sold as 

asphalt or blended into residual fuel oil, into 

lighter, more valuable products. The Vacuum 

Resid feedstock is heated before it enters the 

main fractionator, where lighter material 

vaporizes. The fractionator bottoms are 

routed through 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 group includes the Coke 

Handling System, which will collect, size, and 

transport the petroleum coke created during 

the coking process. This system consists of 

a coke pit, storage pad, enclosed crusher, 

enclosed conveyors, and surge bins. Other 

EG’s were created to address individual 

pieces of equipment within this unit that have 

specific 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 absorption 

gas, Syngas, and natural gas. 

SV71-H1 

EG71-H2PLANT Hydrogen Plant. Area 71. The H2 Plant will 

process natural gas, refinery fuel gas and/or 

a high-pentane refinery stream to produce 

99.9% pure hydrogen and high-pressure 

steam through the use of a steam/methane 

reforming technology. This emission unit 

consists of process vessels, heater, 

compressors, pumps, piping, drains, & 

various components (pumps & compressor 

seals, process valves, pressure relief valves, 

flanges, connectors, etc.). Other EG’s were 

created to address individual pieces of 

equipment within this unit that have specific 

applicable requirements. 

None 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 10 of 103 

Emission Unit ID Emission Unit Description * Stack Identification 

EG71-H2STEAMSYS Hydrogen Plant Deaerator, Blowdown Vent, 

and Steam Vent. Area 71. During normal 

operation, small quantities of VOC may be 

emitted from the Hydrogen Plant Deaerator 

and the Blowdown Vent. During periods of 

startup, shutdown, and unanticipated 

outages, small quantities of VOC may be 

emitted from the Hydrogen Plant Deaerator, 

Blowdown Vent, and Steam Vent.. 

SV71-DEAERATOR 

SV71-BLOWDOWN 

SV71-PRODSTEAM 

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

EG77-DHTHYTREAT Distillate Hydrotreater Unit: Area 77. Reacts 

sour distillate (and occasionally gas oil) 

streams with hydrogen over a catalyst bed to 

remove sulfur. The DHT unit consists of 

process vessels (reactors, distillation tower, 

absorbing towers, stripper tower), heater, 

cooling tower, compressors, pumps, piping, 

drains, & various components (pumps & 

compressor seals, process valves, pressure 

relief valves, flanges, connectors, etc.). 

Other EG’s were created to address 

individual pieces of equipment within this unit 

that 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 Block 

removes hydrogen sulfide from acid gas and 

converts it to elemental sulfur using Claus 

Process (Trains D and E), the SCOT Tail Gas 

Treating Unit process (Trains No. 3 and 

No. 4), and associated amine treating 

equipment. The exhaust tail gas is routed to 

a thermal oxidizer. This emission group 

consists of process vessels (including thermal 

reactors, an absorbing tower, and a stripping 

tower), heaters, tanks, containers, 

compressors, seals, process valves, flanges, 

connectors, etc.). Other EG’s have been 

created to address individual units which 

have 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 water 

stream in distillation towers heated by steam. 

The acid gases from the tower are routed to 

the Sulfur Plant. The stripped sour water is 

sent to the refinery sewer system. This 

emission group includes all equipment 

(pumps, tanks, vessels) in this area.

None 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 11 of 103 

Emission Unit ID Emission Unit Description * Stack Identification 

EGTANK104 Tank 104, an internal floating roof tank for the 

storage of petroleum liquids with a true V.P. 

of 11 psia or less. Capacity 4,673,000 

gallons. 

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 4,744,000 

gallons. 

None 

EGTANK601 Tank 601, an external floating roof tank for 

the storage of wastewater. Capacity = 

4,200,000 gallons. 

None 

EGTANK216 Tank 216, an internal floating roof tank for 

the storage of sour water from EG72-

SULRBLOCK2. Capacity = 1,500,000 

gallons. 

None 

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

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

EGCOOLTOWERA Cooling tower A None 

EGCOOLTOWERC 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 the 

heavy oil upgrade project. 

None 

EG76-UTILITIES Coker plant flare and flare gas recovery 

systems. Area 76. 

None 

EG78-FUELGASRECOVERY Fuel gas recovery compressor. Area 78. None 

Changes to the equipment described in this table are subject to the requirements of R 336.1201, except as 

allowed 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. Some 

equipment 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 separators 

and the aggregate facilities that are subject to 

40 CFR 60, Subpart QQQ. A current list of 

subject items is maintained by the refinery. 

None 

EG-BENZNESHAP All equipment at the facility subject to the 

requirements of the Benzene Waste NESHAP 

None 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 12 of 103 

Flexible Group Identification

Flexible Group ID Emission Units Included in Flexible Group Stack 

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 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 13 of 103 

Flexible Group ID Emission Units Included in Flexible Group Stack 

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 None 

FGDHOUPANNUAL 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 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 14 of 103 

Emission Unit Special Conditions

TABLE E-1.3 {EG11-FCCU} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

EMISSION GROUP Fluid Catalytic Cracking Unit. Area 11. The FCCU converts heavier 

hydrocarbons to lighter products in the presence of a catalyst. In the 

process coke is deposited on the catalyst. The spent catalyst is moved to 

the regenerator (11-V1) where the coke is burned off using air. The 

regenerator is equipped with cyclones to capture catalyst 

(11-V1CYCLONES). The hot flue gas from the regenerator is directed to a 

flue gas cooler where heat is recovered as steam. The FCCU consists of 

process vessels (reactor, regenerator, fractionators, knock-out pots, and 

strippers) 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.). Other 

EGs have been created to address equipment that has specific applicable 

requirements. Permit 262-02, 28-02A, 175-06, 379-08. 

Flexible Grouping ID FG-PROCUNITS, FGDHOUPANNUAL 

I. DESIGN PARAMETERS

A. Pollution Control 

Equipment 

Cyclone, Electrostatic precipitator (ESP) with ammonia addition. 

B. Stack/Vent Parameters NA

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. Temp 

(°F) 

d. Air 

Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. SVFCCU 195 60 R 336.1225, 

R 336.1226(d), 

R 336.2804, 

40 CFR 52.21(d)

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material 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 matter 

from any fluid catalytic cracking unit catalyst regenerator in excess of 

0.8 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-hour 

block 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 from 

the FCCU regenerator in excess of the following: 

a. 70 ppmv (at 0% oxygen)-7 day rolling average‡ 

b. 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 approved 

Hydrotreater Outage Plan, the 7 day average limit does not apply during 

periods of hydrotreater outages nor to startup, shutdown, and 

malfunction events approved in the Hydrotreater Outage Plan. 

4. NOx 1. Permittee shall not cause or allow the emission of NOx from the FCCU 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 15 of 103 

TABLE E-1.3 {EG11-FCCU} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

regenerator in excess of the following: 

a. 123 ppmv (at 0% oxygen)-7 day rolling average‡ 

b. 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 approved 

Hydrotreater Outage Plan, the 7 day average limit does not apply during 

periods of hydrotreater outages nor to startup, shutdown, and 

malfunction events approved in the Hydrotreater Outage Plan. 

5. Volatile Organic Compounds 1. Permittee shall limit VOC emissions to 21 tons per year, based on a 

rolling 12-month time period as determined at the end of each calendar 

month. (R 336.1702(a))

6. PM-10 (particulate matter of 

10 microns diameter or less) 

1. Permittee shall not cause or allow the emission of PM-10 from the fluid 

catalytic cracking unit catalyst regenerator in excess of 1.1 pounds per 

1,000 pounds of coke burn off in the regenerator. (R 336.1205), 

(R 336.2802), (40 CFR 52.21)

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and 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 test 

of 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 §§5.1.1, 5.1.3, and 5.1.4, the permittee shall conduct either 

a Relative Accuracy Audit (RAA) or a Relative Accuracy Test Audit 

(RATA) once every twelve calendar quarters, provided that a Cylinder 

Gas Audit is conducted each calendar quarter. Within 30 days 

following the end of each calendar quarter, the permittee shall submit 

the results to the AQD in the format of the data assessment report.

(R 336.1213(3))

2. Process Monitoring System 

and 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 CFR 

Part 63 Subparts A & UUU) 

3. Other Monitoring and/or 

Recordkeeping 

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 60 

Subparts A & J, 40 CFR Part 63 Subparts A and UUU)

4. Daily records of CO emissions from the CEM. (40 CFR Part 60 

Subparts 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 a 

method acceptable to the AQD District Supervisor. (R 336.1702(a)) 

6. The permittee shall calculate the PM and PM-10 emission rate from 

EG11-FCCU per 1,000 lb of coke burn off using a method acceptable 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 16 of 103 

TABLE E-1.3 {EG11-FCCU} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

to the AQD District Supervisor. (R 336.1205), (R 336.2802), 

(40 CFR 52.21), (40 CFR Part 60 Subparts A & J), (40 CFR Part 63 

Subparts A and UUU) 

7. The permittee shall keep, in a satisfactory manner, the following 

monthly records for bypass lines in EG11-FCCU: 

a. visually inspect the seal or closure mechanism 

b. 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 63 

Subparts A & UUU, R 336.1213(3)) 

2. Carbon Monoxide. (40 CFR Part 60 Subparts A & J, 40 CFR Part 63 

Subparts A & UUU, R 336.1213(3)) 

3. Within 180 days after commencement of trial operation of the Detroit 

heavy oil upgrade project, and thereafter annually, the permittee shall 

verify emission rates from EG11-FCCU of the pollutants listed below by 

testing at owner's expense, in accordance with Department 

requirements. No less than 60 days prior to testing, the permittee shall 

submit a complete test plan to the AQD. The AQD must approve the final 

plan prior to testing. Verification of emission rates includes the submittal 

of a complete report of the test 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. For 

verification 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) 

VOC3 (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 Detroit 

heavy oil upgrade project, and at least once every five years thereafter, 

the permittee shall determine the VOC emission rates from EG11-FCCU 

by testing at owner's expense, in accordance with Department 

requirements. No less than 60 days prior to testing, the permittee shall 

submit a complete test plan to the AQD. The AQD must approve the 

final plan prior to testing. Determination of emission rates includes the 

submittal of a complete report of the test results to the AQD within 60 

days following the last date of the test. Test results shall be used to 

calculate 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 of 

Testing/Recordkeeping 

1. As required by the Division. (R 336.1213(3))
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 17 of 103 

TABLE E-1.3 {EG11-FCCU} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

IV. REPORTING 

Reports and Schedules See Appendix 1.8 of RO Permit 199700013c 

V. OPERATIONAL PARAMETERS 

1. 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 and 

Malfunction 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, General 

Subpart 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 the 

provisions 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 emissions 

and monitoring systems performance report and-or summary report form (see 40 CFR 60.7(d)) to the 

Department semi-annually, except when: more frequent reporting is specifically required by an applicable 

subpart; or the Department, on a case-by-case basis, determines that more frequent reporting is necessary 

to accurately assess the compliance status of the source. All reports shall be postmarked by the 30th day 

following the end of each six-month period. Written reports of excess emissions shall include the following 

information: 

(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 excess 

emissions. The process operating time during the reporting period. 

(2) Specific identification of each period of excess emissions that occurs during startups, shutdowns, and 

malfunctions of the affected facility. The nature and cause of any malfunction (if known), the corrective 

action taken or preventative measures adopted. 

(3) The date and time identifying each period during which the continuous monitoring system was 

inoperative 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 been 

inoperative, 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 data 

collected, either by continuous monitoring system or as necessary to convert monitoring data to the units of 

the applicable standard, for a minimum of five years from the date of collection of such data or submission 

of such reports. (R 336.1213(3)(b)(ii) 

10. Permittee shall comply with all applicable requirements of 40 CFR 63 as follows: Subpart A, General 

Subpart UUU, National Emission Standards for Hazardous Air Pollutants. (40 CFR Part 63, Subparts A 

and UUU) 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 18 of 103 

TABLE E-1.3 {EG11-FCCU} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

11. 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 the 

approved 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 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 or 

operator shall revise the malfunction abatement plan within 45 days after such an event occurs. (40 CFR 

Part 63, Subparts A and UUU)

12. Along with the Notification of Compliance Status report, the permittee shall submit to the AQD District 

Supervisor, an approvable Operation, Maintenance and Monitoring plan (OMMP). The permittee shall not 

operate EG11-FCCU unless the approved OMMP, or an alternate plan approved by the AQD District 

Supervisor, 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 matter 

and 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. 

3

This condition is included at the request of the permittee.
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 19 of 103 

EG27-ZURNBOILER

EMISSION UNIT CONDITIONS

DESCRIPTION

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

Flexible Group ID: FG-HEATERS, FGDHOUPANNUAL 

POLLUTION CONTROL EQUIPMENT

Multi-staged Low NOx Burner 

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ 

Operating Scenario Equipment 

Monitoring/ 

Testing 

Method 

Underlying 

Applicable 

Requirements

1. NOX

0.20 

lb/MMBTU 2 Annual rolling average* EG27-

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

2. CO 0.10 

lb/MMBTU 2 Annual rolling average* EG27-

ZURNBOILER SC II.2, VI.2 R 336.1201(3) 

3. PM 0.0019 

lb/MMBTU 2 Three-hour average EG27-

ZURNBOILER SC II.2, V.2 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

4. PM-10 0.0076 

lb/MMBTU 2 Three-hour average EG27-

ZURNBOILER SC II.2, V.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

5. VOC 0.0055 

lb/MMBTU 2 Three-hour average EG27-

ZURNBOILER SC II.2, V.4 R 336.1205, R 336.1702(a) 

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

II. MATERIAL LIMIT(S)

Material Limit Time Period/ Operating 

Scenario Equipment Monitoring/ 

Testing Method

Underlying 

Applicable 

Requirements

1. Natural gas or 

refinery fuel gas 

burned 

210,000 cubic 

feet per hour 

based on 1,000 

BTU/cubic foot2

According to Method EG27-ZURNBOILER SC VI.6 

R 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 Stationary 

Sources 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)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 20 of 103 

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/SAMPLING

Records 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 the 

heavy oil upgrade project and every five years thereafter, the permittee shall verify PM-10 emission rates 

from EG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No 

less than 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 shall 

demonstrate that test conditions will be representative of post-startup conditions. The AQD must approve 

the final plan prior to testing. Verification of emission rates includes the submittal of a complete report of the 

test 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 the 

heavy oil upgrade project and every five years thereafter, the permittee shall verify PM emission rates from 

EG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No less 

than 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 shall 

demonstrate that test conditions will be representative of post-startup conditions. The AQD must approve 

the final plan prior to testing. Verification of emission rates includes the submittal of a complete report of the 

test 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 the 

heavy oil upgrade project and annually thereafter, the permittee shall verify PM emission rates from 

EG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No less 

than 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 shall 

demonstrate that test conditions will be representative of post-startup conditions. The AQD must approve 

the final plan prior to testing. Verification of emission rates includes the submittal of a complete report of the 

test 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 the 

heavy oil upgrade project and every five years thereafter, the permittee shall verify VOC emission rates from 

EG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No less 

than 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 shall 

demonstrate that test conditions will be representative of post-startup conditions. The AQD must approve 

the final plan prior to testing. Verification of emission rates includes the submittal of a complete report of the 

test 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 the 

heavy oil upgrade project and annually thereafter, the permittee shall verify VOC emission rates from 

EG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No less 

than 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 shall 

demonstrate that test conditions will be representative of post-startup conditions. The AQD must approve 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 21 of 103 

the final plan prior to testing. Verification of emission rates includes the submittal of a complete report of the 

test 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 the 

heavy oil upgrade project and annually thereafter, the permittee shall verify sulfuric acid mist emission rates 

from EG27-ZURNBOILER by testing at owner's expense, in accordance with Department requirements. No 

less than 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 shall 

demonstrate that test conditions will be representative of post-startup conditions. The AQD must approve 

the final plan prior to testing. Verification of emission rates includes the submittal of a complete report of the 

test 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, conducted 

during 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 be 

conducted on either a three or five year cycle, the frequency of such tests shall be annual for two 

consecutive years. Following two consecutive years of compliance, the frequency of testing shall return 

to the original three or five year cycle. 

VI. MONITORING/RECORDKEEPING

Records 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 and 

record the NOX and oxygen emissions from EG27-ZURNBOILER on a continuous basis. The permittee 

shall install and operate the Continuous Emission Monitoring System (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. With respect 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 Accuracy Test Audit (RATA) once every twelve (12) calendar 

quarters, provided that a Cylinder Gas Audit is conducted each calendar quarter. Within 30 days following 

the end of each calendar quarter, the permittee shall 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, 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 and 

record the CO and oxygen emissions from EG27-ZURNBOILER on a continuous basis. The permittee shall 

install 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. With 

respect 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 Accuracy 

Test Audit (RATA) once every twelve (12) calendar quarters, provided that a Cylinder Gas Audit is 

conducted each calendar quarter. Within 30 days following the end of each calendar quarter, the permittee 

shall 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 gas 

burned in EU27-ZURNBOILER in accordance with the Federal Standards of Performance as specified in 40 

CFR 60, Subpart J, in a manner and with instrumentation acceptable to the Division. Fuel gas combustion 

devices having a common source of fuel gas may be monitored at only one location, if monitoring at this 

location 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 accordance 

with the federal Standards of Performance for New Stationary Sources as specified in 40 CFR Part 60 

Subparts A, Db, and J. 2

 (R 336.1205, 40 CFR Part 60 Subparts A, Db, & J)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 22 of 103 

5. The permittee shall keep records of emissions and operating information to comply with the federal 

Standards of Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A, Db, and 

J. The permittee shall keep all source emissions data and operating information on file at the facility and 

make 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 and 

record the natural gas and refinery fuel gas usage rate in EU27-ZURNBOILER on an hourly basis. The 

permittee shall determine the heat value of the gas burned in Btu per cubic foot on a monthly basis from 

samples 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 shall 

determine 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 upwards 

to the ambient air unless otherwise noted: 

Stack & Vent ID 

Maximum Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above 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 of 

Performance for Industrial-Commercial-Institutional Steam Generating Units, and Subpart J-Standards of 

Performance for Petroleum Refineries, as they apply to EG27-ZURNBOILER. 2 (40 CFR Part 60 Subparts 

A, Db, and J)

Footnotes:

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 3

This condition is included at the request of the permittee. 

TABLE E-1.15 {EU27-B&WBOILER1} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

EMISSION 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 and 

natural gas. 

Flexible Grouping ID FG-HEATERS, FGDHOUPANNUAL 

I. DESIGN PARAMETERS

A. Pollution Control 

Equipment 

Low NOx Burner, Flue Gas Recirculation system. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 23 of 103 

TABLE E-1.15 {EU27-B&WBOILER1} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

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

otherwise noted.

Stack/Vent ID 

a. 

Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. 

Temp 

(°F) 

d. 

Air Flow 

Rate 

(acfm) 

Applicable 

Requirement 

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

C. Other Design Parameters 

1. The maximum heat input in the boiler shall not exceed 300 million BTUs per hour. (R 336.1801, 40 CFR 

Part 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-hour 

average. (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 rolling 

average, 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-hour 

average. (R 336.1205)

4. PM 1. 0.0019 pounds per million BTUs heat input, based upon a three-hour 

average. (R 336.1205)

5. VOC 1. 0.0055 pounds per million BTUs heat input, based on a three-hour 

rolling 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 a 

3 hour rolling average basis. (40 CFR 60.104(a)(1))

(1) @ 3 % excess oxygen 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and 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 60 

Subpart Db)

4. 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 test 

of 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 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 24 of 103 

TABLE E-1.15 {EU27-B&WBOILER1} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

§§5.1.1, 5.1.3, and 5.1.4, the permittee shall conduct either a Relative 

Accuracy Audit (RAA) or a Relative Accuracy Test Audit (RATA) once 

every twelve (12) calendar quarters, provided that a Cylinder Gas Audit 

is conducted each calendar quarter. Within 30 days following the end of 

each calendar quarter, the permittee shall submit the results to the AQD 

in the format of the data assessment report. 

2. Process Monitoring System 

and Recordkeeping 

1. Records of emissions and operating information is required to comply 

with the federal Standards of Performance for New Stationary Sources 

as specified in 40 CFR Part 60, Subparts A, Db, and J. All source 

emissions data and operating data shall be kept on file for a period of at 

least 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 be 

kept 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 

Recordkeeping 

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

40 CFR Part 60 Subpart Db)

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

1. Parameter to be Tested/ 

Recorded 

1. NA 

2. Method/Analysis 1. NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

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 unless 

the 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) 

VI. OTHER REQUIREMENTS 

1. Permittee shall comply with all applicable requirements of 40 CFR Part 60-Standards of Performance for 

New Stationary Sources, Subpart A-General Provisions, Subpart Db-Standards of Performance for 

Industrial-Commercial-Institutional Steam Generating Units, and Subpart J-Standards of Performance for 

Petroleum Refineries. (40 CFR Part 60 Subpart A, Db, J) 

* This requirement is state enforceable only. 

3

This condition is included at the request of the permittee.
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 25 of 103 

TABLE E-1.23 {EG42-43SULRECOV} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

EMISSION 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 unless 

otherwise noted.

Stack/Vent ID a. 

 Minimum 

Height 

(feet) 

b. 

Maximum 

Exhaust 

Dimension 

(inches) 

c. 

Temp 

(°F) 

d. 

Air Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. SV43-H2 199.5 42.5 NA NA R 336.1225 

R 336.1226(d) 

C. Other Design Parameters 

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. Material 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 the 

thermal oxidizer that controls the 

tail gas treatment units, No. 1 and 

No. 2. 

1. 250 Parts per million by volume at zero percent oxygen on a dry 

basis. (40 CFR 60.104(a)(2)) 

2. 175 Parts per million by volume at zero percent oxygen on a dry 

basis on an annual rolling average, as determined at the end of each 

calendar month.3

 (R 336.1201(3))

2. Nitrogen oxide emission rate from 

the thermal oxidizer 

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

3. Carbon monoxide emission rate 

from 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 rate 

from the thermal oxidizer 

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

5. PM10 emission rate from the 

thermal oxidizer 

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

6. Volatile organic compound 

emission rate from the thermal 

oxidizer 

1. 0.0055 lb/MMBTU. (R 336.1205, R 336.1702, R 336.2802, 

40 CFR 52.21)

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System and 

Recordkeeping 

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 A 

and J)

3. 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 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) 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 26 of 103 

TABLE E-1.23 {EG42-43SULRECOV} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

2. Process Monitoring System 

and Recordkeeping 

1. NA 

3. Other Monitoring and/or 

Recordkeeping 

1. Daily combined amount of sulfur produced in the sulfur recovery units 

A, 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 with 

instrumentation 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 in 

40 CFR Part 60, Subparts A and J. (40 CFR 60.105, 40 CFR Part 60 

Subparts A and J)

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

1. Parameter to be Tested/ 

Recorded 

1. Sulfur dioxide concentration. (R 336.1205, R 336.2802, 40 CFR 

52.21, 40 CFR Part 60 Subparts A and J)

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

years thereafter, the permittee shall verify NOX emission rates from 

EG42-43SULRECOV by testing at owner's expense, in accordance 

with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. The AQD 

must approve the final plan prior to testing. Verification of emission 

rates 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)

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

years thereafter, the permittee shall verify CO emission rates from 

EG42-43SULRECOV by testing at owner's expense, in accordance 

with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. The AQD 

must approve the final plan prior to testing. Verification of emission 

rates 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 336.2001, R 336.2003, R 336.2004, R 336.2802, 40 CFR 52.21)

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

years thereafter, the permittee shall verify PM-10 emission rates from 

EG42-43SULRECOV by testing at owner's expense, in accordance 

with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. The AQD 

must approve the final plan prior to testing. Verification of emission 

rates includes the submittal of a complete report of the test 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. (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 five 

years thereafter, the permittee shall verify PM emission rates from 

EG42-43SULRECOV by testing at owner's expense, in accordance 

with Department requirements. No less than 60 days prior to testing, 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 27 of 103 

TABLE E-1.23 {EG42-43SULRECOV} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

the permittee shall submit a complete test plan to the AQD. The AQD 

must approve the final plan prior to testing. Verification of emission 

rates 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 five 

years thereafter, the permittee shall verify VOC emission rates from 

EG42-43SULRECOV by testing at owner's expense, in accordance 

with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. The AQD 

must approve the final plan prior to testing. Verification of emission 

rates 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 336.1702, 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 every 

three years thereafter, the permittee shall verify sulfuric acid mist 

emission rates from EG42-43SULRECOV by testing at owner's 

expense, in accordance with Department requirements. No less than 

60 days prior to testing, the permittee shall submit a complete test 

plan to the AQD. The AQD must approve the final plan prior to 

testing. Verification of emission rates includes the submittal of a 

complete report of the test results to the AQD within 60 days following 

the 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 for 

valid, 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 five 

year cycle, the frequency of such tests shall be annual for two 

consecutive years. Following two consecutive years of 

compliance, the frequency of testing shall return to the original 

three 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)

3. Frequency and Schedule of 

Testing/Recordkeeping 

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)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 28 of 103 

TABLE E-1.23 {EG42-43SULRECOV} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

4. 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 the 

approved Operation, Maintenance and Monitoring Plan, or an 

alternate plan approved by the AQD District Supervisor, is 

implemented. The plan shall contain all information required by 

40 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 100 

long 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. 1 

and 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 and 

No. 2, unless a minimum temperature of 1,200 degrees Fahrenheit and a minimum retention time of 2.0 

seconds in the thermal oxidizer is maintained. Following both the promulgation of Subpart Ja in 40 CFR 

Part 60 and the successful completion of a stack test pursuant to that Subpart, and upon written approval by 

the AQD District Supervisor, the temperature and retention time requirements of this condition will be 

superseded by the temperature and retention time demonstrated during the stack test and stated in the written 

approval. (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 and 

No. 2, unless provisions of the Federal Standards of Performance for New Source Stationary Sources, 40 CFR 

Part 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 and 

Malfunction Plan (SSMP) for EG42-43SULRECOV. The permittee shall not operate EG42-43SULRECOV 

unless the approved 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, 

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 or 

operator shall revise the malfunction abatement plan within 45 days after such an event occurs. (40 CFR 

Part 63, Subparts A and UUU)

VI. OTHER REQUIREMENTS 

1. Monitoring and recording of sulfur dioxide concentration and operating information is required to comply with 

the 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 acceptable 

format 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))
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 29 of 103 

TABLE E-1.23 {EG42-43SULRECOV} 

EMISSION UNIT/PROCESS GROUP REQUIREMENTS

2. 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. Permittee shall comply with all applicable requirements of 40 CFR Part 63, Subpart UUU-National Emission 

Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming 

Units, and Sulfur Recovery Units. (R 336.1213(3)), (40 CFR 63, Subpart UUU)

* This requirement is state enforceable only. 

3

This condition is included at the request of the permittee.
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 30 of 103 

EG70-COKER 

EMISSION UNIT CONDITIONS

DESCRIPTION

The Coker converts Vacuum Resid (Crude Vacuum Tower Bottoms), a product normally sold as asphalt or 

blended into residual fuel oil, into lighter, more valuable products. The Vacuum Resid feedstock is heated 

before it enters the main fractionator, where lighter material vaporizes. The fractionator bottoms are routed 

through 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 group 

includes the Coke Handling System, which will collect, size, and transport the petroleum coke created during the 

coking process. This system consists of a coke pit, storage pad, enclosed crusher, enclosed conveyors, and 

surge bins. Other EG’s were created to address individual pieces of equipment within this unit that have specific 

applicable requirements. 

Flexible Group ID: FGDHOUPANNUAL 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ 

Operating Scenario Equipment Monitoring/ Testing Method

Underlying 

Applicable 

Requirements

1. Visible 

emissions 

No visible 

emissions 2 According to method

Truck loading; weigh 

bins; and the coke 

handling system 

beginning with the 

enclosed conveyor 

leading to the crusher. 

SC VI.2 R 336.1301 

2. VOC 20 tpy 2 According to method Exhaust from coke 

drum steam vent. SC VI.8 R 336.1702 

3. PM 1.0 tpy 2 According to method Exhaust from coke 

drum steam vent. SC VI.8 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

4. H2S 0.7 tpy 1 According to method Exhaust from coke 

drum steam vent. SC VI.8 R 336.1224, 

R 336.1226(d) 

II. MATERIAL LIMIT(S)

Material Limit Time Period/ Operating 

Scenario Equipment Monitoring/ 

Testing Method

Underlying 

Applicable 

Requirements

1. Moisture 

content of coke 

Minimum 6% by 

weight 2 According to method 

Coke handling 

operations after the 

coke has been 

removed from the 

coke drum. 

SC VI.3 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

2. Coke 

production 

500 tons per 

hour 2 Daily average Equipment subject to 

SC I.1. SC VI.4 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 31 of 103 

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, when 

the 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 drum 

unless a program for continuous fugitive emissions control has been submitted to the AQD District 

Supervisor as a proposed revision to the Fugitive Dust Control Program required in Table B-1 of RO Permit 

199700013c. The proposed revision shall address the following aspects of the coke handling system: all 

plant roadways, the plant yard, all material storage piles, and all material handling operations. The 

submitted 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 storage 

pad. 

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

c. Monitoring and correction of coke moisture to comply with SC II.1. 

d. Use of bridge cranes to transfer coke from the pit to a stockpile and from a stockpile to the crusher 

receiving hopper, except as allowed in SC III.1.e. 

e. Limited use of front-end loaders or other vehicles on the coke storage pad: only during bridge crane 

maintenance or breakdown. 

f. Inspection, maintenance, and monitoring of a “totally enclosed gallery” for transporting crushed coke 

from the crusher to the surge/weigh bin system. 

The permittee shall comply with the submitted program until the AQD District Supervisor approves the 

program or approves an amended program. Thereafter, the permittee shall comply with the approved 

program. At any time, the permittee may submit a modified program to the AQD District Supervisor for 

review and approval. 2

 (R 336.1371, R 336.1372, Act 451 324.5524)

3. The height of any coke pile on the storage pad shall not exceed the height of the perimeter wall at any 

time. 2

 (R 336.1301)

4. The permittee shall not operate any equipment in the coke handling system unless a malfunction abatement 

plan (MAP) as described in Rule 911(2), for the coke handling system, has been submitted no less than 120 

days before commencing operation of the coke handling system, and is implemented and maintained. If at 

any time the MAP fails to address or inadequately addresses an event that meets the characteristics of a 

malfunction, the permittee shall amend the MAP within 45 days after such an event occurs. The permittee 

shall also amend the MAP within 45 days, if new equipment is installed or upon request from the District 

Supervisor. The permittee shall submit the MAP and any amendments to the MAP to the AQD District 

Supervisor for review and approval. If the AQD does not notify the permittee within 90 days of submittal, the 

MAP or amended MAP shall be considered approved. Until an amended plan is approved, the permittee 

shall implement corrective procedures or operational changes to achieve compliance with all applicable 

emission limits. 2

 (R 336.1205, R 336.1301, R 336.1331, R 336.1910, R 336.1911, R 336.2802, 

40 CFR 52.21)

 As a minimum, the MAP shall address the following: 

a. Maintaining required coke moisture content. 

b. Maintaining the integrity of all enclosures: integral crusher enclosure, conveyor enclosures and the 

shed for truck loading. 

c. Surge bin dust collector. 

5. The permittee shall not cycle the coke drums more than 487 times per 12-month rolling time period, as 

determined at the end of each calendar month. (R 336.1205, R 336.2802, 40 CFR 52.21)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 32 of 103 

IV. DESIGN/EQUIPMENT PARAMETER(S)

1. The permittee shall equip and maintain the coker with a gas recovery system to recover the coke drum 

vapors and route them to the fuel gas treatment system. 2

 (R 336.1205, R 336.1702)

2. The permittee shall equip and maintain the coker with instrumentation to monitor the pressure in the coke 

drum during coking cycles. 2

 (R 336.1205, R 336.1702)

3. The permittee shall equip and maintain the coke storage area with a pit below the grade of the coke storage 

pad and with perimeter walls no less than 30 feet above the level of the coke storage pad. 2

 (R 336.1301) 

4. The permittee shall not convey crushed coke to the surge bins unless the totally enclosed conveyors and 

surge bin dust collector are installed, maintained, and operated in a satisfactory manner. 2

 (R 336.1910)

5. The permittee shall not load trucks with crushed coke unless the surge bin dust collector is installed, 

maintained, and operated in a satisfactory manner. 2

 (R 336.1910)

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

1. Within 180 days after commencement of trial operation of EG70-COKER, and annually thereafter, the 

permittee shall determine VOC, PM, and H2S emission rates from the coke drum steam vent by testing at 

owner's expense, in accordance with Department requirements. No less than 60 days prior to testing, the 

permittee shall submit a complete test plan to the AQD. The AQD must approve the final plan prior to 

testing. Determination of emission rates includes the submittal of a complete report of the test results to the 

AQD within 60 days following the last date of the test. At any time after completing five tests acceptable to 

the AQD District Supervisor, the permittee may request that the testing frequency be reduced. If the testing 

frequency is reduced, testing shall be conducted no less often than once every five years. Test results shall 

be used to calculate emissions as required by SC VI.8, and to determine compliance with the requirements 

for FGDHOUPANNUAL. 2

 (R 336.1205, R 336.1224, R 336.1702, R 336.2001, R 336.2003, R 336.2004, 

R 336.2802, 40 CFR 52.21)

2. For tests required by SC V.1, the following applies for valid, 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 five year cycle, the frequency of such tests shall be annual for two 

consecutive years. Following two consecutive years of compliance, the frequency of testing shall return 

to the original three or five year cycle. 

See Appendix 1.5 of RO Permit 199700013c 

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall keep, in a satisfactory manner, a record of the coke drum pressure at which the active 

drum is vented to the atmosphere. 2

 (R 336.1205, R 336.1702)

2. The permittee shall verify the absence of visible emissions by taking six-minute visible emission readings for 

the equipment listed in SC I.1 a minimum of once per calendar day. The reader shall take each visible 

emission reading during routine operating conditions. For purposes of this condition, the opacity reading is 

not required to use Method 9. If the permittee observes any visible emissions, the permittee shall 

immediately initiate corrective actions. 2

 (R 336.1301)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 33 of 103 

3. The permittee shall monitor, in a satisfactory manner, the moisture of the coke on the coke storage pad and 

other non-enclosed areas on a daily basis, as provided in the approved fugitive dust control program for 

EG70-COKER. 2

 (R 336.1205, Act 451 324.5524)

4. The permittee shall keep, in a satisfactory manner, a daily record of the amount of coke loaded onto trucks 

for shipping. 2

 (R 336.1205)

5. The permittee shall keep, in a satisfactory manner, daily records of coke moisture, as required by SC VI.2. 2

(R 336.1205, Act 451 324.5524)

6. The permittee shall keep, in a satisfactory manner, records of all visible emission readings required by SC 

VI.2. At a minimum, records shall include the date, time, name of observer/reader, and status of visible 

emissions. 2

 (R 336.1301)

7. Within 30 days after completion of the installation of EG70-COKER, the permittee or the authorized agent 

pursuant to Rule 204 shall notify the AQD District Supervisor, in writing, of the completion of the activity. 

Completion of the installation, construction, reconstruction, relocation, or modification is considered to occur 

not later than commencement of trial operation of EG70-COKER. 2

 (R 336.1216(1), R 336.1201(7)(a))

8. The permittee shall calculate the VOC, PM, and H2S emission rates from the coke drum steam vent 

monthly, for the preceding 12-month rolling time period, using a method acceptable to the AQD District 

Supervisor. As soon as test results acceptable to the AQD District Supervisor are available from the testing 

required by SC V.1, the permittee shall use emission factors derived from testing to calculate emission 

rates. 2

 (R 336.1205, R 336.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

9. The permittee shall keep, in a satisfactory manner, records of the number of times the coke drums are 

cycled for each month and for each 12-month rolling time period as determined at the end of each calendar 

month. (R 336.1205, R 336.2802, 40 CFR 52.21)

VII. REPORTING

1. NA 

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards 

to the ambient air unless otherwise noted: 

Stack & Vent ID 

Maximum 

Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above Ground 

(feet) 

Underlying Applicable 

Requirements 

1. Coke Drum Vent (unobstructed 

vertical discharge not required) not restricted 222 1

 R 336.1225, R 336.1226(d) 

IX. OTHER REQUIREMENT(S)

1. NA 

Footnotes:

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 3

This condition is included at the request of the permittee. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 34 of 103 

EG-COKERFLARE 

EMISSION GROUP CONDITIONS

DESCRIPTION

Coker Plant Flare. Area 76 

Flexible Group ID: FGDHOUPANNUAL 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ Operating 

Scenario Equipment Monitoring/ Testing Method

Underlying 

Applicable 

Requirements

1. NA NA NA NA NA NA 

II. MATERIAL LIMIT(S)

Material Limit Time Period/ Operating 

Scenario Equipment Monitoring/ 

Testing Method

Underlying 

Applicable 

Requirements

1. NA NA NA NA NA NA 

III. PROCESS/OPERATIONAL RESTRICTION(S)

1. The permittee shall install a coker blowdown gas recovery system upstream of EG-COKERFLARE to 

recover and route coke drum vent gas to the fuel gas treatment system. (R 336.1205, R 335.1224, 

R 336.1702, R 336.2802, 40 CFR 52.21) 

2. The permittee shall equip and maintain the coker blowdown gas recovery system with redundant recovery 

compressors, each designed with the capacity to individually recover all coke drum vent gases. 

(R 336.1205, R 335.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

3. At least 60 days prior to initial startup of the Detroit heavy oil upgrade project, the permittee shall submit to 

MDEQ a demonstration showing that the coker blowdown gas recovery system is sized appropriately for the 

coke drums. The demonstration shall include the following elements: 

a. The design capacity of the coker blowdown gas recovery system and design specifications of 

components, such as the compressors. 

b. Description of extra capacity and redundancies designed into the coker blowdown gas recovery system. 

c. An explanation of the assumptions made in determining the appropriate design capacity of the coker 

blowdown gas recovery system. 

d. Confirmation that no cross-over points exist between the coker blowdown gas recovery system and any 

fuel gas systems outside of it. 

(R 336.1205, R 335.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

IV. DESIGN/EQUIPMENT PARAMETER(S)

1. NA 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 35 of 103 

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

1. NA 

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall install, maintain, and continuously operate a continuous flow measuring device to 

continuously monitor and record the flow of gas to the flare. The flow measuring device shall be sensitive to 

rapid flow changes, and have the capability of reporting both instantaneous velocity and totalized flow. 

Materials exposed to the flare gas shall be corrosion resistant. The flow measuring device shall (i) feature 

automated daily calibrations at low and high ranges, and (ii) shall signal alarms if the calibration error or drift 

is exceeded, provided that the monitor is equipped with such capability. The volumetric flow measuring 

device may consist of one or more flow meters, and, as combined, shall meet the following specifications. 

(R 336.1205, R 335.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

a. Velocity Range: 0.1-250 ft/sec 

b. Repeatability: ± 1% of reading over the velocity range 

c. Accuracy: ± 20% of reading over the velocity range of 0.1-1 ft/s and ± 5% of reading over the velocity 

range of 1-250 ft/s 

d. Installation: Applicable AGA, ANSI, API, or equivalent standard. 

e. Flow Rate Determination: Must be corrected to one atmosphere pressure and 68 °F and recorded as 

one-minute averages. 

f. Data Records: Measured continuously and recorded over one minute averages. The instrument shall 

be capable of storing or transferring all data for later retrieval. 

g. QA/QC: An annual verification of accuracy is required, and shall be specified by the manufacturer. 

2. All data as generated by the flow measuring device shall be continuously recorded. The recording system 

must have the capability to generate one-minute average data from that which is continuously generated by 

the flow measuring device. (R 336.1205, R 335.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

3. The permittee shall maintain the flow measuring device in good operating condition at all times when the 

flare that it serves is operational, except when out of service due to: 

a. Breakdowns and unplanned system maintenance, which shall not exceed 96 hours, cumulatively, per 

quarter for each reporting period; or, 

b. Planned maintenance, which shall not exceed 14 days per 18 month period, provided that a written 

notification detailing the reason for maintenance and methods that will be used during the maintenance 

period to determine emissions associated with flare events is provided to the AQD District Supervisor 

prior to, or within 24 hours of, removal of the monitoring system from service. 

(R 336.1205, R 335.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

VII. REPORTING

1. At least 60 days prior to initial startup of the DHOUP, the Permittee shall submit to Michigan DEQ drawings 

identifying the location of the flow measuring device required by SC VI.1. (R 336.1205, R 335.1224, 

R 336.1702, R 336.2802, 40 CFR 52.21)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 36 of 103 

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards 

to the ambient air unless otherwise noted: 

Stack & Vent ID 

Maximum 

Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above Ground 

(feet) 

Underlying Applicable 

Requirements 

1. NA NA NA NA 

IX. OTHER REQUIREMENT(S)

1. NA 

Footnotes:

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 37 of 103 

EG72-SULRBLOCK2

EMISSION UNIT CONDITIONS

DESCRIPTION

Sulfur Block 2. Area 72. The Sulfur Block removes hydrogen sulfide from acid gas and converts it to elemental 

sulfur using Claus Process (Trains D and E), the SCOT Tail Gas Treating Unit process (Trains No. 3 and No. 4), 

and associated amine treating equipment. The exhaust tail gas is routed to a thermal oxidizer. This emission 

group consists of process vessels (including thermal reactors, an absorbing tower, and a stripping tower), 

heaters, tanks, containers, compressors, seals, process valves, flanges, connectors, etc.). Other EG’s have 

been created to address individual units which have specific applicable requirements. 

Flexible Group ID: FGDHOUPANNUAL 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ Operating 

Scenario Equipment 

Monitoring/ 

Testing 

Method 

Underlying 

Applicable 

Requirements

1. NOX

0.2 

lb/MMBTU 2 According to method EG72-

SULRBLOCK2 SC V.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

2. SO2 250 ppmv 2 According to method EG72-

SULRBLOCK2 SC VI.1 40 CFR 60.104(a)(2)(i) 

3. SO2

100 ppmv at 

0% oxygen 3 Annual rolling average EG72-

SULRBLOCK2 SC VI.1 R 336.1201(3) 

4. CO 0.04 

lb/MMBTU 2 According to method EG72-

SULRBLOCK2 SC V.2 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

5. PM 0.08 

lb/MMBTU 2 According to method EG72-

SULRBLOCK2 SC V.4 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

6. PM-10 0.08 

lb/MMBTU 2 According to method EG72-

SULRBLOCK2 SC V.3 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

7. VOC 0.0055 

lb/MMBTU 2 According to method EG72-

SULRBLOCK2 SC V.5 

R 336.1205, 

R 336.1702(a), 

R 336.2802, 40 

CFR 52.21 

II. MATERIAL LIMIT(S)

Material Limit Time Period/ Operating 

Scenario Equipment Monitoring/ Testing Method

Underlying 

Applicable 

Requirements

1. Elemental 

sulfur produced 

225 long tons 

per day 12-month rolling average EG72-SULRBLOCK2 SC VI.8 

R 336.1205, 

R 336.2802, 40 

CFR 52.21 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 38 of 103 

III. PROCESS/OPERATIONAL RESTRICTION(S)

1. The heat input capacity of auxiliary fuel in the thermal oxidizer of EG72-SULRBLOCK2 shall not exceed a 

maximum of 30 MM Btu per hour, on a daily average. 2

 (R 336.1205, R 336.1702, R 336.2802, 

40 CFR 52.21) 

2. The heat input capacity of auxiliary fuel in the thermal oxidizer of EG72-SULRBLOCK2 shall not exceed a 

maximum of 25 MM BTU per hour on an annual rolling average, as determined at the end of each calendar 

month. 2,3 (R 336.1201(3)) 

3. The permittee shall comply with all provisions of the federal Standards of Performance for New Stationary 

Sources as specified in 40 CFR Part 60 Subparts A and J, as they apply to EG72-SULRBLOCK2. 

(40 CFR Part 60 Subparts A & J)

4. The permittee shall comply with all provisions of the National Emission Standards for Hazardous Air 

Pollutants as specified in 40 CFR Part 63 Subparts A and UUU, as they apply to EG72-SULRBLOCK2.

(40 CFR Part 63 Subparts A & UUU)

IV. DESIGN/EQUIPMENT PARAMETER(S)

1. The permittee shall not operate EG72-SULRBLOCK2 unless the thermal oxidizer is installed, maintained 

and operated in a satisfactory manner. Satisfactory operation of the thermal oxidizer includes operating the 

thermal oxidizer as described in the startup, shutdown, and malfunction plan required by 40 CFR Part 63, 

Subparts A and UUU. (R 336.1205, R 336.1224, R 336.1225, R 336.1702, R 336.2802, R 336.1901, 

R 336.1910, 40 CFR 52.21, 40 CFR 60.104(a)(2)(i))

2. The permittee shall equip and maintain the EG72-SULRBLOCK2 sulfur pits with a properly operating 

degassing system to remove and capture H2S and TRS from the sulfur in the sulfur pits prior to transfer to 

the sulfur storage tanks. Gases removed and captured by the degassing system shall be returned to the 

inlet of EG72-SULRBLOCK2. (R 336.1205, R 336.2802, 40 CFR 52.21)

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

1. Within 180 days after commencement of trial operation and every five years thereafter, the permittee shall 

verify NOX emission rates from EG72-SULRBLOCK2 by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee shall submit a complete test 

plan to the AQD. The AQD must approve the final plan prior to testing. Verification of emission rates 

includes the submittal of a complete report of the test 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, R 336.2803, R 336.2804, 

40 CFR 52.21, 40 CFR 60.104(a)(2)(i))

2. Within 180 days after commencement of trial operation and every five years thereafter, the permittee shall 

verify CO emission rates from EG72-SULRBLOCK2 by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee shall submit a complete test 

plan to the AQD. The AQD must approve the final plan prior to testing. Verification of emission rates 

includes the submittal of a complete report of the test results to the AQD within 60 days following the last 

date of the test. 2

 (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 PM-10 emission rates from EG72-SULRBLOCK2 by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee shall submit a complete test 

plan to the AQD. The AQD must approve the final plan prior to testing. Verification of emission rates 

includes the submittal of a complete report of the test results to the AQD within 60 days following the last 

date of the test. 2 For verification of PM-10 emissions, testing shall include both the filterable and 

condensable fractions. (R 336.2001, R 336.2003, R 336.2004, R 336.2802, 40 CFR 52.21)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 39 of 103 

4. Within 180 days after commencement of trial operation and every five years thereafter, the permittee shall 

verify PM emission rates from EG72-SULRBLOCK2 by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee shall submit a complete test 

plan to the AQD. The AQD must approve the final plan prior to testing. Verification of emission rates 

includes the submittal of a complete report of the test 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)

5. Within 180 days after commencement of trial operation and every five years thereafter, the permittee shall 

verify VOC emission rates from EG72-SULRBLOCK2 by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee shall submit a complete test 

plan to the AQD. The AQD must approve the final plan prior to testing. Verification of emission rates 

includes the submittal of a complete report of the test 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, R 336.2802, 

40 CFR 52.21)

6. Within 180 days after commencement of trial operation and every three years thereafter, the permittee shall 

verify sulfuric acid mist emission rates from EG72-SULRBLOCK2 by testing at owner's expense, in 

accordance with Department requirements. No less than 60 days prior to testing, the permittee shall submit 

a complete test plan to the AQD. The AQD must approve the final plan prior to testing. Verification of 

emission rates includes the submittal of a complete report of the test results to the AQD within 60 days 

following the last date of the test. 3

 (R 336.1201(3)) 

7. For tests required by SC V.1 through 6, the following applies for valid, 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 five year cycle, the frequency of such tests shall be annual for two 

consecutive years. Following two consecutive years of compliance, the frequency of testing shall return 

to the original three or five year cycle. 

VI. MONITORING/RECORDKEEPING

Records 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 and 

record the SO2 and oxygen emissions from EG72-SULRBLOCK2 on a continuous basis. The permittee 

shall install and operate the Continuous Emission Monitoring System (CEMS) to meet the timelines, 

requirements and reporting detailed in Appendix A to this permit and shall use the CEMS data for 

determining compliance with SC I.2. 2

 (R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR Part 60 Subparts 

A and J, 40 CFR 60.105(a)(5))

2. The permittee shall monitor the amount of natural gas used in the thermal oxidizer on a daily average 

basis. 2 (R 336.1205, R 336.1702, R 336.2802, 40 CFR 52.21)

3. On a daily basis, the permittee shall calculate the heat input of natural gas used in the thermal oxidizer and 

keep records of the fuel usage and heat input to the thermal oxidizer. 2 (R 336.1205, R 336.1702, 

R 336.2802, 40 CFR 52.21)

4. The permittee shall monitor emissions and operating information for EG72-SULRBLOCK2 in accordance 

with the federal Standards of Performance for New Stationary Sources as specified in 40 CFR Part 60 

Subparts A and J. 2

 (R 336.1205, R 336.1225, R 336.1901, 40 CFR Part 60 Subparts A & J)

5. The permittee shall monitor emissions and operating and maintenance information for EG72-SULRBLOCK2 

in accordance with the National Emission Standards for Hazardous Air Pollutants as specified in 

40 CFR Part 63 Subparts A and UUU. (40 CFR Part 63 Subparts A & UUU)

6. The permittee shall keep records of emissions and operating information to comply with the federal 

Standards of Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A and J. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 40 of 103 

The permittee shall keep all source emissions data and operating information on file at the facility for a 

period of at least five years and make them available to the Department upon request. (R 336.1205, 

40 CFR Part 60 Subparts A & J)

7. The permittee shall keep records of emission information and operating and maintenance information to 

comply with the National Emission Standards for Hazardous Air Pollutants as specified in 40 CFR Part 63 

Subparts A and UUU. The permittee shall keep all source emissions and operating and maintenance 

information on file at the facility for a period of at least five years and make them available to the 

Department upon request. (40 CFR Part 63 Subparts A & UUU) 

8. The permittee shall keep records of the long tons of elemental sulfur produced per day, on a 12-month 

rolling average, in EG72-SULRBLOCK2. (R 336.1205, R 336.2802, 40 CFR 52.21) 

9. The permittee shall keep records of the hours per month and 12-month rolling time period, as determined at 

the end of each calendar month, that the sulfur pit degassing system did not operate while 

EG72-SULRBLOCK2 was operating. (R 336.1205, R 336.2802, 40 CFR 52.21)

VII. REPORTING

1. The permittee shall provide written notification of construction and operation to comply with the federal 

Standards of Performance for New Stationary Sources, 40 CFR 60.7. The permittee shall submit this 

notification to the AQD District Supervisor within the time frames specified in 40 CFR 60.7. 2

 (40 CFR 60.7)

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards 

to the ambient air unless otherwise noted: 

Stack & Vent ID 

Maximum 

Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above Ground 

(feet) 

Underlying Applicable 

Requirements 

1. SV72-V22 96 2 150 2 R 336.1225 

IX. OTHER REQUIREMENT(S)

1. NA 

Footnotes:

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 3

This condition is included at the request of the permittee. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 41 of 103 

Flexible Group Special Conditions

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING All refinery heaters and boilers that burn refinery fuel gas. (NSPS, 40 CFR 60, 

Subpart J) 

Emission Unit/Process 

Groups 

EG04-VACHTR, EG04-VAC2HTR, EG05-CRUDEHTR, EG08-GOHTCHARHTR, 

EG09-ALKYDIBREBHTR, EG11-FCCUCHARHTR, EG14-CCRPLCHARHTR, 

EG14-CCRPLINTHTR, EG16-NHTSTRIPREBOIL, EG16-NHTCHARHTR, 

EG19-KHTCHARHTR, EG22-FUELOILHTR, EG27-ZURNBOILER, 

EU27-B&WBOILER1, EG70-COKERHTR, EG71-H2HTR, EG77-DHTHTR 

Flexible Grouping ID FGDHOUPANNUAL 

I. DESIGN PARAMETERS

A. Pollution Control 

Equipment 

None 

B. Stack/Vent 

Parameters 

Exhaust gases shall be discharged unobstructed vertically upwards unless 

otherwise noted. 

Stack/Vent ID 

a. Minimum 

Height (feet) 

b. Maximum Exhaust 

Dimension (inches) 

c. 

Temp 

(°F) 

d. Air Flow 

Rate (acfm) Applicable 

Requirement 

1. SV04-H1-05-H1 

(EG04-VACHTR and 

EG05-CRUDEHTR) 

199 118 NA NA R 336.1225 

2. SV08-H1 

(EG08-

GOHTCHARHTR) 

160 63 NA NA R 336.1225 

3. SV09-H7 

(EG09-

ALKDIBREBHTR) 

150 76 NA NA R 336.1225 

4. SV11-H1 

(EG11-

FCCUCHARHTR) 

150 90 NA NA R 336.1225 

5. SV14-H4A 

(EG14-

CCRPLINTHTR) 

195 66 NA NA R 336.1225

6. SV14-H6 

(EG14-

CCRPLCHARHTR) 

195 84 NA NA R 336.1225 

7. SV16-H3 

(EG16-

NHTSTRIPREBOIL) 

96.8 45 NA NA R 336.1225 

8. SV16-H4 

(EG16-

NHTCHARHTR) 

91.7 56 NA NA R 336.1225 

9. SV19-H2 

(EG19-

KHTCHARHTR) 

85.7 39 NA NA R 336.1225 

10. SV22-1-H1 

(unobstructed vertical 

discharge not 

required) 

(EG22-FUELOILHTR) 

29.8 NA NA NA R 336.1225 

11. SV04-H2 

(EG04-VAC2HTR) 

125 96 NA NA R 336.1225 

12. SV70-H1 150 112 NA NA R 336.1225 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 42 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

(EG70-COKERHTR) 

13. SV77-H1 

(EG77-DHTHTR) 

125 60 NA NA R 336.1225 

14. SV71-H1 

(EG71-H2HTR) 

150 192 NA NA R 336.1225 

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. Hydrogen sulfide content 

of the refinery fuel gas 

burned in any 

combustion device in 

FG-HEATERS 

1. Shall not exceed 0.10 grain per dry standard cubic foot (230 milligrams per dry 

standard cubic meter or 160 ppmdv) based on a three-hour average. 

(R 336.1226(d)), (40 CFR 60.104(a)(1)), (40 CFR Part 60, Subparts A and J)) 

2. Shall not exceed 60 ppmdv based on an annual rolling average, as determined at 

the end of each calendar month.3

 (R 336.1201(3)) 

B. Pollutants Maximum Emission Limit

1. Nitrogen oxides For each emission unit listed below that uses a nitrogen oxides (NOX) CEMS, the 

lb/MMBTU limit shall be based on a 12-month rolling time period as determined at 

the end of each calendar month. For each emission unit listed below that does not 

use a NOX CEMS, the lb/MMBTU limit shall be based on a 3-hour average. 

1. EG04-VACHTR 0.05 lb/MMBTU 

(R 336.1205), (R 336.2802), (40 CFR 52.21), (Consent Order No. 01-40119)

2. EG05-CRUDEHTR 0.05 lb/MMBTU 

(R 336.1205), (R 336.2802), (40 CFR 52.21), (Consent Order No. 01-40119)

3. EG08-GOHTCHARHTR 0.05 lb/MMBTU (R 336.1205, R 336.2802), 

(40 CFR 52.21)

4. EG11-FCCUCHARHTR 0.05 lb/MMBTU (R 336.1205, R 336.2802), 

(40 CFR 52.21)

5. EG14-CCRPLCHARHTR 0.05 lb/MMBTU (R 336.1205, R 336.2802), 

(40 CFR 52.21)

6. EG14-CCRPLINTHTR 0.05 lb/MMBTU (R 336.1205, R 336.2802), 

(40 CFR 52.21)

7. EG16-NHTCHARHTR 0.20 lb/MMBTU (R 336.1205), (R 336.2802), 

(40 CFR 52.21)

8. EG16-NHTSTRIPREBOIL 0.20 lb/MMBTU (R 336.1205), (R 336.2802), 

(40 CFR 52.21)

9. EG19-KHTCHARHTR 0.20 lb/MMBTU (R 336.1205), (R 336.2802), 

(40 CFR 52.21)

10. EG22-FUELOILHTR 0.10 lb/MMBTU (R 336.1205, R 336.2802), 

(40 CFR 52.21) 

11. EG04-VAC2HTR 0.05 lb/MMBTU (R 336.1205), (R 336.2802), 

(40 CFR 52.21)

12. EG70-COKERHTR 0.05 lb/MMBTU (R 336.1205), (R 336.2802), 

(40 CFR 52.21)

13. EG77-DHTHTR 0.05 lb/MMBTU (R 336.1205), (R 336.2802), 

(40 CFR 52.21)

14. EG71-H2HTR 0.013 lb/MMBTU (R 336.1205), (R 336.2802), 

(40 CFR 52.21) 

15. EG09-ALKYDIBREBHTR 0.05 lb/MM BTU (R 336.1205), (R 336.2802), 

(40 CFR 52.21)

16. EG04-VACHTR and EG05-CRUDEHTR combined 85 tons per year, based on 

a 12-month rolling time period as determined at the end of each calendar 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 43 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

month. (R 336.2802), (40 CFR 52.21), (Consent Order No. 01-40119) 

2. Particulate matter 1. EG71-H2HTR 6.86 tons per year, based on a 12-month rolling time period as 

determined at the end of each calendar month. (R 336.1205), (R 336.2802), 

(40 CFR 52.21) 

2. EG71-H2HTR 0.0034 lb/MMBTU. (R 336.1205), (R 336.2802), (40 CFR 52.21) 

3. Each other emission unit in FG-HEATERS 0.0019 lb/MMBTU (R 336.1205), 

(R 336.2802), (40 CFR 52.21)

3. PM10 - Particulate 

matter less than 10 

microns 

1. EG71-H2HTR 0.010 lb/MMBTU (R 336.1205), 

(R 336.2802), (40 CFR 52.21)

2. Each other emission unit in FG-HEATERS 0.0076 lb/MMBTU (R 336.1205), 

(R 336.2802), (40 CFR 52.21)

4. PM2.5 - Particulate 

matter less than 2.5 

microns 

1. EG09-ALKYDIBREBHTR 0.0076 lb/MMBTU (R 336.1205), 

(R 336.2903), (40 CFR Part 51 Appendix S)

5. Carbon monoxide, 

including periods of 

startup, shutdown, and 

malfunction 

1. EG05-CRUDEHTR 0.01 lb/MMBTU based on an annual rolling 

average, as determined at the end of each calendar month.3 (R 336.1201(3)) 

2. EG70-COKERHTR 0.01 lb/MMBTU based on an annual rolling 

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

 (R 336.1201(3))

3. EG11-FCCUCHARHTR 0.02 lb/MMBTU based on an annual rolling 

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

 (R 336.1201(3))

4. EG14-CCRPLCHARHTR 0.013 lb/MMBTU based on an annual rolling 

average, as determined at the end of each calendar month.3 (R 336.1201(3))

5. EG04-VACHTR 0.01 lb/MMBTU based on an annual rolling 

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

 (R 336.1201(3))

6. EG08-GOHTCHARHTR 0.02 lb/MMBTU based on an annual rolling 

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

 (R 336.1201(3))

7. EG14-CCRPLINTHTR 0.013 lb/MMBTU based on an annual rolling 

average, as determined at the end of each calendar month.3 (R 336.1201(3))

8. EG04-VAC2HTR 0.01 lb/MMBTU based on an annual rolling 

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

 (R 336.1201(3))

9. EG77-DHTHTR 0.02 lb/MMBTU based on an annual rolling 

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

 (R 336.1201(3))

10. EG16-NHTCHARHTR, EG16-NHTSTRIPREBOIL, EG19-KHTCHARHTR, 

EG22-FUELOILHTR, and EG09-ALKYDIBREBHTR 0.02 lb/MMBTU, based on 

a 3-hr average. (R 336.1205), (R 336.2802), (40 CFR 52.21)

11. EG71-H2HTR 13 tons per year, based on a 12-month rolling time period as 

determined at the end of each calendar month. (R 336.1910) 

6. Volatile organic 

compounds 

1. Each emission unit in FG-HEATERS 0.0055 lb/MMBTU (R 336.1702)

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) 

System and 

Recordkeeping 

1. Permittee shall monitor and keep records of the concentration of hydrogen 

sulfide (H2S) in the refinery fuel gas burned in each heater/boiler in accordance 

with the Federal Standards of Performance as specified in 40 CFR 60, Subpart J, 

in a manner and with instrumentation acceptable to the Air Quality Division. 

(R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR 60.105(a)(4)) 

2. Permittee shall monitor and keep records of the concentration of total reduced 

sulfur (TRS) in the refinery fuel gas burned in each heater/boiler, in a manner 

and with instrumentation acceptable to the Air Quality Division. The TRS monitor 

may be used as an alternative to the H2S monitoring required by SC III.A.1.3

(R 336.1201(3))
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 44 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

3. Fuel gas combustion devices having a common source of refinery fuel gas may 

be monitored at only one location, if monitoring at this location accurately 

represents the concentration of H2S or TRS in the refinery fuel gas being burned. 

(40 CFR 60.105(a)(4)(ii)) 

4. The permittee shall keep records of emissions and operating information to 

comply with the federal Standards of Performance for New Stationary Sources 

as specified in 40 CFR Part 60 Subparts A and J. (40 CFR Part 60 Subparts 

A & J)

5. Permittee shall monitor and keep records of the NOx emissions from the crude 

and vacuum heater stack. (SV04-H1-05-H1) (R 336.1205, Consent Order No. 

01-40119) 

6. The permittee shall install, certify, calibrate, maintain, and operate the NOx 

CEMS in requirement III.A.1.5 and an oxygen 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. With 

respect 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 Accuracy Test Audit (RATA) once 

every twelve (12) calendar quarters, provided that a Cylinder Gas Audit is 

conducted each calendar quarter. Within 30 days following the end of each 

calendar quarter, the permittee shall submit the results to the AQD in the format 

of the data assessment report. 

7. The permittee shall install, calibrate, maintain and operate in a satisfactory 

manner devices to monitor and record on a continuous basis the NOX and 

oxygen emissions from EG70-COKERHTR, EG08-GOHTCHARHTR, and EG71-

H2HTR. The permittee shall install and operate the Continuous Emission 

Monitoring System (CEMS) to meet the timelines, requirements and reporting 

detailed in Appendix A and shall use the CEMS data for determining compliance 

with the appropriate emission limits in II.B.1.3, 12 & 14. (R 336.1205, 

R 336.2802, 40 CFR 52.21)

8. The permittee shall install, calibrate, maintain and operate in a satisfactory 

manner devices to monitor and record on a continuous basis the NOX and 

oxygen emissions from EG14-CCRPLCHARHTR and EG14-CCRPLINTHTR. 

The permittee shall install and operate the Continuous Emission Monitoring 

System (CEMS) to meet the timelines, requirements and reporting detailed in 

Appendix A and shall use the CEMS data for determining compliance with the 

appropriate emission limits in II.B.1.4 & 5.3

 (R 336.1201(3))

9. The permittee shall install, calibrate, maintain and operate in a satisfactory 

manner devices to monitor and record on a continuous basis the CO and oxygen 

emissions from EG70-COKERHTR, EG71-H2HTR, EG08-GOHTCHARHTR, 

EG14-CCRPLCHARHTR, EG14-CCRPLINTHTR, EG11-FCCUCHARHTR, 

EG04-VAC2HTR, and EG77-DHTHTR, and, in their shared stack, EG04-

VACHTR and EG05-CRUDEHTR. The permittee shall install 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. With respect 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 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 45 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

permittee shall conduct either a Relative Accuracy Audit (RAA) or a Relative 

Accuracy Test Audit (RATA) once every twelve (12) calendar quarters, provided 

that a Cylinder Gas Audit is conducted each calendar quarter. Within 30 days 

following the end of each calendar quarter, the permittee shall submit the results 

to the AQD in the format of the data assessment report. (R 336.1205, 

R 336.2802, 40 CFR 52.21) 

See Appendix 1.3 of RO Permit 199700013c 

2. Process Monitoring 

System and 

Recordkeeping 

1. Alternate Monitoring Plan (AMP) for the Alky Unit Deethanizer off gas using 

hydrogen sulfide detector tubes as provided for in 40 CFR 60.13(i). 

2. Alternate Monitoring Plan (AMP) for the Propylene Unit Deethanizer off gas by 

daily using hydrogen sulfide detector tubes when it is being introduced directly 

into the refinery fuel gas system. 

3. The permittee shall monitor, in a satisfactory manner, the heat input for each 

heater in FG-HEATERS, in MMBTU/hr, on a daily, monthly, and rolling 12-month 

time period basis. (R 336.1205(1), R 336.1225, R 336.2802, 40 CFR 52.21)

3. Other Monitoring 

and/or Recordkeeping 

1. Daily records of the type and amount of fuel used in each heater/boiler in 

FG-HEATERS (R 336.1901), (45 FR 29720) 

2. The permittee shall keep, in a satisfactory manner, records of NOx emissions 

on a monthly and a 12-month rolling basis for EG04-VACHTR and 

EG05-CRUDEHTR combined. (R 336.2802), (40 CFR 52.21), (Consent Order 

No. 01-40119)

3. The permittee shall keep, in a satisfactory manner, records of CO emissions on a 

monthly and a 12-month rolling basis for EG71-H2HTR. (R 336.1910)

4. The permittee shall keep, in a satisfactory manner, daily, monthly, and rolling 

12-month time period records of the heat input for each heater in FG-HEATERS, 

in MMBTU/hr, as required by condition III.A.2.3. (R 336.1205), (R 336.1225), 

(R 336.2802), (40 CFR 52.21)

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

1. Parameter to be 

Tested/ Recorded 

For any emission unit in this section required to conduct an emission test for a 

specific pollutant every three years and every five years, the requirement to conduct 

an emission test every five years for that pollutant does not apply; emission testing 

for that emission unit for that pollutant is required every three years. 

1. Hydrogen sulfide or total reduced sulfur concentration in refinery fuel gas. 

(R 336.1213(3)), (R 336.1226(d)), (45 FR 29720) 

2. Daily average heat input, in MMBTU/hr, for each unit listed in requirements V.1 

through V.18. (R 336.1205), (R 336.1225), (R 336.2802), (40 CFR 52.21) 

3. Within 180 days after commencement of trial operation of EG71-H2HTR and 

annually thereafter, the permittee shall verify emission rates from EG71-H2HTR of 

the pollutants listed below by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee 

shall submit a complete test plan to the AQD. The AQD must approve the final 

plan prior to testing. Verification of emission rates includes the submittal of a 

complete report of the test 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. (R 336.2001), (R 336.2003), (R 336.2004)

PM-10 SC II.B.3.1 (R 336.1205), (R 336.2802), (40 CFR 52.21)

PM SC II.B.2.1 (R 336.1205), (R 336.2802), (40 CFR 52.21)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 46 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

VOC SC II.B.6.1 (R 336.1702) 

Sulfuric acid mist3

 (R 336.1201(3)) 

4. Within 180 days after commencement of trial operation of EG04-VAC2HTR and 

every five years thereafter, the permittee shall verify emission rates from EG04-

VAC2HTR of the pollutants listed below by testing at owner's expense, in 

accordance with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. The AQD must 

approve the final plan prior to testing. Verification of emission rates includes the 

submittal of a complete report of the test 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. (R 336.2001), 

(R 336.2003), (R 336.2004)

NOX SC II.B.1.11 (R 336.1205, R 336.2802, 40 CFR 52.21)

PM-10 SC II.B.3.2 (R 336.1205), (R 336.2802), (40 CFR 52.21)

PM SC II.B.2.1 (R 336.1205), (R 336.2802), (40 CFR 52.21)

VOC SC II.B.6.1 (R 336.1702) 

5. Within 180 days after commencement of trial operation of EG04-VAC2HTR and 

every five years thereafter for sulfuric acid mist, and every three years thereafter 

for VOC, the permittee shall verify emission rates from EG04-VAC2HTR of the 

pollutants listed below by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee 

shall submit a complete test plan to the AQD. The AQD must approve the final 

plan prior to testing. Verification of emission rates 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 336.2001), (R 336.2003), (R 336.2004)

VOC3

 (R 336.1201(3)) 

Sulfuric acid mist3

 (R 336.1201(3)) 

6. Within 180 days after commencement of trial operation of EG70-COKERHTR and 

annually thereafter, the permittee shall verify emission rates from 

EG70-COKERHTR of the pollutants listed below by testing at owner's expense, in 

accordance with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. The AQD must 

approve the final plan prior to testing. Verification of emission rates includes the 

submittal of a complete report of the test 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. (R 336.2001), 

(R 336.2003), (R 336.2004)

PM-10 SC II.B.3.2 (R 336.1205), (R 336.2802), (40 CFR 52.21)

PM SC II.B.2.1 (R 336.1205), (R 336.2802), (40 CFR 52.21)

VOC SC II.B.6.1 (R 336.1702) 

7. Within 180 days after commencement of trial operation of EG70-COKERHTR and 

every five years thereafter, the permittee shall verify emission rates from 

EG70-COKERHTR of the pollutants listed below by testing at owner's expense, in 

accordance with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. The AQD must 

approve the final plan prior to testing. Verification of emission rates 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 336.2001), (R 336.2003), (R 336.2004)

Sulfuric acid mist3

 (R 336.1201(3)) 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 47 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

8. Within 180 days after commencement of trial operation of EG77-DHTHTR and 

every five years thereafter, the permittee shall verify emission rates from 

EG77-DHTHTR of the pollutants listed below by testing at owner's expense, in 

accordance with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. The AQD must 

approve the final plan prior to testing. Verification of emission rates includes the 

submittal of a complete report of the test 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. (R 336.2001), 

(R 336.2003), (R 336.2004)

NOX SC II.B.1.13 (R 336.1205, R 336.2802, 40 CFR 52.21)

PM-10 SC II.B.3.2 (R 336.1205), (R 336.2802), (40 CFR 52.21)

PM SC II.B.2.1 (R 336.1205), (R 336.2802), (40 CFR 52.21)

VOC SC II.B.6.1 (R 336.1702) 

Sulfuric acid mist3

 (R 336.1201(3)) 

9. Within 180 days after commencement of trial operation of the heavy oil upgrade 

project and every five years thereafter, the permittee shall verify emission rates 

from EG09-ALKDIBREBHTR of the pollutants listed below by testing at owner's 

expense, in accordance with Department requirements. No less than 60 days 

prior to testing, the permittee shall submit a complete test plan to the AQD. The 

AQD must approve the final plan prior to testing. Verification of emission rates 

includes the submittal of a complete report of the test 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. (R 336.2001), 

(R 336.2003), (R 336.2004)

NOX applicable limits in SC II.B.1. (R 336.1205, R 336.2802, 40 CFR 52.21) 

PM-10 SC II.B.3.2 (R 336.1205), (R 336.2802), (40 CFR 52.21) 

PM SC II.B.2.1 (R 336.1205, R 336.2802, 40 CFR 52.21) 

PM-2.5 SC II.B.4.1 (R 336.1205), (R 336.2903), (40 CFR Part 51 Appendix S) 

CO applicable limits in SC II.B.5. (R 336.1205, R 336.2802, 40 CFR 52.21) 

Sulfuric acid mist3

 (R 336.1201(3))

10. Following issuance of this permit, but not later than 180 days after 

commencement of trial operation of the heavy oil upgrade project and every five 

years thereafter, the permittee shall verify emission rates from EG16-

NHTCHARHTR, EG16-NHTSTRIPREBOIL, EG19-KHTCHARHTR, and EG22-

FUELOILHTR of the pollutants listed below by testing at owner's expense, in 

accordance with Department requirements. No less than 60 days prior to testing, 

the permittee shall submit a complete test plan to the AQD. For tests conducted 

prior to commencement of trial operation of the heavy oil upgrade project, the test 

plan shall demonstrate that test conditions will be representative of post-startup 

conditions. The AQD must approve the final plan prior to testing. Verification of 

emission rates includes the submittal of a complete report of the test 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. 

(R 336.2001), (R 336.2003), (R 336.2004)

NOX applicable limits in SC II.B.1. (R 336.1205, R 336.2802, 40 CFR 52.21) 

PM-10 SC II.B.3.2 (R 336.1205), (R 336.2802), (40 CFR 52.21) 

PM SC II.B.2.1 (R 336.1205, R 336.2802, 40 CFR 52.21)

CO applicable limits in SC II.B.5. (R 336.1205, R 336.2802, 40 CFR 52.21) 

Sulfuric acid mist3

 (R 336.1201(3))

11. Following issuance of this permit, but not later than 180 days after 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 48 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

commencement of trial operation of the heavy oil upgrade project and every three 

years thereafter, the permittee shall verify emission rates from EG16-

NHTCHARHTR and EG16-NHTSTRIPREBOIL of the pollutants listed below by 

testing at owner's expense, in accordance with Department requirements. No less 

than 60 days prior to testing, the permittee shall submit a complete test plan to the 

AQD. For tests conducted prior to commencement of trial operation of the heavy 

oil upgrade project, the test plan shall demonstrate that test conditions will be 

representative of post-startup conditions. The AQD must approve the final plan 

prior to testing. Verification of emission rates 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 336.2001), (R 336.2003), (R 336.2004)

NOX

3

 (R 336.1201(3)) 

12. Within 180 days after commencement of trial operation of the heavy oil upgrade 

project and every five years thereafter for VOC, and every three years thereafter 

for NOx, the permittee shall verify emission rates from EG09-ALKDIBREBHTR of 

the pollutants listed below by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee 

shall submit a complete test plan to the AQD. The AQD must approve the final 

plan prior to testing. Verification of emission rates 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 336.2001), (R 336.2003), (R 336.2004)

NOX

3

 (R 336.1201(3)) 

VOC3 (R 336.1201(3)) 

13. Following issuance of this permit, but not later than 180 days after 

commencement of trial operation of the heavy oil upgrade project and every five 

years thereafter, the permittee shall verify emission rates from EG11-

FCCUCHARHTR, EG14-CCRPLCHARHTR, and EG14-CCRPLINTHTR of the 

pollutants listed below by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee 

shall submit a complete test plan to the AQD. For tests conducted prior to 

commencement of trial operation of the heavy oil upgrade project, the test plan 

shall demonstrate that test conditions will be representative of post-startup 

conditions. The AQD must approve the final plan prior to testing. Verification of 

emission rates includes the submittal of a complete report of the test 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. 

(R 336.2001), (R 336.2003), (R 336.2004)

NOX applicable limits in SC II.B.1. (R 336.1205, R 336.2802, 40 CFR 52.21) 

PM-10 SC II.B.3.2 (R 336.1205), (R 336.2802), (40 CFR 52.21) 

PM SC II.B.2. (R 336.1205, R 336.2802, 40 CFR 52.21) 

Sulfuric acid mist3

 (R 336.1201(3)) 

14. Following issuance of this permit, but not later than 180 days after 

commencement of trial operation of the heavy oil upgrade project and every three 

years thereafter, the permittee shall verify emission rates from EG11-

FCCUCHARHTR, EG14-CCRPLCHARHTR, and EG14-CCRPLINTHTR of the 

pollutants listed below by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee 

shall submit a complete test plan to the AQD. For tests conducted prior to 

commencement of trial operation of the heavy oil upgrade project, the test plan 

shall demonstrate that test conditions will be representative of post-startup 

conditions. The AQD must approve the final plan prior to testing. Verification of 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 49 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

emission rates 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 336.2001), 

(R 336.2003), (R 336.2004)

PM3

 (R 336.1201(3)) 

VOC3

 (R 336.1201(3)) 

15. Following issuance of this permit, but not later than 180 days after 

commencement of trial operation of the heavy oil upgrade project and every five 

years thereafter, the permittee shall verify emission rates from EG04-VACHTR, 

EG05-CRUDEHTR, EG08-GOHTCHARHTR, and EU27-B&WBOILER1 of the 

pollutants listed below by testing at owner's expense, in accordance with 

Department requirements. No less than 60 days prior to testing, the permittee 

shall submit a complete test plan to the AQD. For tests conducted prior to 

commencement of trial operation of the heavy oil upgrade project, the test plan 

shall demonstrate that test conditions will be representative of post-startup 

conditions. The AQD must approve the final plan prior to testing. Verification of 

emission rates includes the submittal of a complete report of the test 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. 

(R 336.2001), (R 336.2003), (R 336.2004)

PM-10 SC II.B.3.2 (R 336.1205), (R 336.2802), (40 CFR 52.21) 

PM SC II.B.2.1 (R 336.1205, R 336.2802, 40 CFR 52.21) 

Sulfuric acid mist3

 (R 336.1201(3)) 

16. Following issuance of this permit, but not later than 180 days after 

commencement of trial operation of the heavy oil upgrade project and annually 

thereafter, the permittee shall verify emission rates from EG04-VACHTR, EG05-

CRUDEHTR, and EU27-B&WBOILER1 of the pollutants listed below by testing at 

owner's expense, in accordance with Department requirements. No less than 60 

days prior to testing, the permittee shall submit a complete test plan to the AQD. 

For tests conducted prior to commencement of trial operation of the heavy oil 

upgrade project, the test plan shall demonstrate that test conditions will be 

representative of post-startup conditions. The AQD must approve the final plan 

prior to testing. Verification of emission rates 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 336.2001), (R 336.2003), (R 336.2004)

PM3

 (R 336.1201(3)) 

VOC3

 (R 336.1201(3))

17. Following issuance of this permit, but not later than 180 days after 

commencement of trial operation of the heavy oil upgrade project and every five 

years thereafter for VOC, and every three years thereafter for PM, the permittee 

shall verify emission rates from EG08-GOHTCHARHTR of the pollutants listed 

below by testing at owner's expense, in accordance with Department 

requirements. No less than 60 days prior to testing, the permittee shall submit a 

complete test plan to the AQD. For tests conducted prior to commencement of 

trial operation of the heavy oil upgrade project, the test plan shall demonstrate that 

test conditions will be representative of post-startup conditions. The AQD must 

approve the final plan prior to testing. Verification of emission rates 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 336.2001), (R 336.2003), (R 336.2004)

PM3

 (R 336.1201(3)) 

VOC3

 (R 336.1201(3))
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 50 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

18. For tests required by SC III.B.1, the following applies for valid, 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 five year cycle, the 

frequency of such tests shall be annual for two consecutive years. 

Following two consecutive years of compliance, the frequency of testing 

shall return to the original three or five year cycle. 

2. Method/Analysis 1. All testing shall be conducted using methods acceptable to the Air Quality 

Division. (R 336.1213(3)), (45 FR 29720)

See Appendix 1.5 of RO Permit 199700013c 

3. Frequency and 

Schedule of Testing / 

Recordkeeping 

1. As requested by the Air Quality Division (R 336.1213(3))

IV. REPORTING 

Reports and Schedules 1. Permittee shall submit the data on the concentration of hydrogen sulfide or total 

reduced sulfur in the refinery fuel gas burned in the heaters to the Air Quality 

Division (AQD) District Supervisor in acceptable format within 30 days following 

the end of the quarter in which the data were collected. (40 CFR 60.7)

See Appendix 1.8 of RO Permit 199700013c 

V. OPERATIONAL PARAMETERS 

1. The heat input to EG04-VACHTR shall not exceed 177 MMBTU/hr on a daily average. (R 336.1205), 

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

2. The heat input to EG05-CRUDEHTR shall not exceed 240 MMBTU/hr on a daily average. (R 336.1205), 

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

3. The heat input to EG08-GOHTHTR shall not exceed 115 MMBTU/hr on a daily average. (R 336.1205), 

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

4. The heat input to EG09-ALKDIBREBHTR shall not exceed 78 MMBTU/hr on a daily average. (R 336.1205), 

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

5. The heat input to EG09-ALKDIBREBHTR shall not exceed 65 MMBTU/hr on an annual rolling average, as 

determined at the end of each calendar month.3

 (R 336.1201(3)) 

6. The heat input to EG11-FCCUCHARHTR shall not exceed 130 MMBTU/hr on a daily average. (R 336.1205), 

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

7. The heat input to EG14-CCRPLCHARHTR shall not exceed 138 MMBTU/hr on a daily average. (R 336.1205), 

(R 336.1225), (40 CFR 52.21) 

8. The heat input to EG14-CCRPLINTHTR shall not exceed 138 MMBTU/hr on a daily average. (R 336.1205), 

(R 336.1225), (R336.2802), (40 CFR 52.21) 

9. The heat input to EG16-NHTCHARHTR shall not exceed 64 MMBTU/hr on a daily average. (R 336.1205), 

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

10. The heat input to EG16-NHTSTRIPREBOIL shall not exceed 46 MMBTU/hr on a daily average. (R 336.1205), 

(R 336.1225), (R 336.2802), (40 CFR 52.21) 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 51 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

11. The heat input to EG19-KHTCHARHTR shall not exceed 18 MMBTU/hr on a daily average. (R 336.1205), 

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

12. The heat input to EG22-FUELOILHTR shall not exceed 7.5 MMBTU/hr on a daily average. (R 336.1205), 

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

13. The heat input to EG04-VAC2HTR shall not exceed 96 MMBTU/hr on a daily average. (R 336.1205), 

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

14. The heat input to EG04-VAC2HTR shall not exceed 46 MMBTU/hr on an annual rolling average, as 

determined at the end of each calendar month.3

 (R 336.1201(3)) 

15. The heat input to EG70-COKERHTR shall not exceed 228 MMBTU/hr on a daily average. (R 336.1205), 

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

16. The heat input to EG70-COKERHTR shall not exceed 209 MMBTU/hr on an annual rolling average, as 

determined at the end of each calendar month.3

 (R 336.1201(3)) 

17. The heat input to EG77-DHTHTR shall not exceed 91 MMBTU/hr on a daily average. (R 336.1205), 

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

18. The heat input to EG77-DHTHTR shall not exceed 55 MMBTU/hr on an annual rolling average, as determined 

at the end of each calendar month.3

 (R 336.1201(3)) 

19. The heat input to EG71-H2HTR shall not exceed 950 MMBTU/hr on a daily average. (R 336.1205), 

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

20. The heat input to EG71-H2HTR shall not exceed 640 MMBTU/hr on an annual rolling average, as determined 

at the end of each calendar month.3

 (R 336.1201(3)) 

21. Except for EG71-H2HTR, the permittee shall only fire refinery fuel gas and/or sweet natural gas in FGHEATERS. (R 336.1205), (R 336.1225), (R 336.2802), (40 CFR 52.21) 

22. The permittee shall only fire refinery fuel gas, pressure swing absorption gas, Syngas, and/or natural gas in 

EG71-H2HTR. (R 336.1205), (R 336.1225), (R 336.2802), (40 CFR 52.21) 

23. The permittee shall not operate EG04-VACHTR, EG05-CRUDEHTR, EG77-DHTCHARHTR, 

EG08-GOHTHTR, EG11-FCCUCHARHTR, EG14-CCRPLCHARHTR, or EG14-CCRPLINTHTR unless the 

unit’s low NOx burners are installed, maintained, and operated in a satisfactory manner. (R 336.1205), 

(R 336.1910), (R 336.2802), (40 CFR 52.21) 

24. The permittee shall not operate EG04-VAC2HTR, EG09-ALKDIBREBHTR, EG70-COKERHTR, or 

EG77-DHTHTR unless the unit’s ultra low-NOX burners are installed, maintained, and operated in a 

satisfactory manner. (R 336.1205, R 336.1910, R 336.2802, 40 CFR 52.21)

25. The permittee shall not operate EG71-H2HTR unless the selective catalytic reduction (SCR) system is 

installed, maintained, and operated in a satisfactory manner. Satisfactory operation includes following the 

approved malfunction abatement plan. (R 336.1205, R 336.1910, R 336.2802, 40 CFR 52.21) 

26. The permittee shall not operate EG71-H2HTR unless an acceptable malfunction abatement plan (MAP) for the 

SCR system has been submitted to the AQD District Supervisor. The plan shall include a catalyst replacement 

schedule based on the SCR manufacturer's recommended guidelines. If at any time the MAP fails to address 

or inadequately addresses an event that meets the characteristics of a malfunction, the permittee shall amend 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 52 of 103 

TABLE F-1.1 {FG-HEATERS} 

FLEXIBLE GROUPING REQUIREMENTS

the MAP within 45 days after such an event occurs. The permittee shall also amend the MAP within 45 days, if 

new equipment is installed or upon request from the District Supervisor. The permittee shall submit the MAP 

and any amendments to the MAP to the AQD District Supervisor for review and approval. If the AQD does not 

notify the permittee within 90 days of submittal, the MAP or amended MAP shall be considered approved. 

Until an amended plan is approved, the permittee shall implement corrective procedures or operational 

changes to achieve compliance with all applicable emission limits. (R 336.1205, R 336.1224, R 336.1225, 

R 336.1911, R 336.2802, 40 CFR 52.21)

VI. OTHER REQUIREMENTS 

1. Permittee shall comply with all requirements of the following subparts of 40 CFR Part 60: Subpart A – General 

and Subpart J - Standards of Performance for Petroleum Refineries. (40 CFR 60, Subparts A and J) 

2. Monitoring requirements for subject emission units are shown in Appendix 3 of RO Permit 199700013c. 

(40 CFR 60.105)

3. Reporting and recordkeeping requirements for subject emission units are shown in Appendix 4 of RO Permit 

199700013c. (40 CFR 60.107)

4. Testing Procedures, except initial testing, for subject emission units are shown in Appendix 5 of RO Permit 

199700013c. (40 CFR 60.106) 

5. No later than 180 days after startup of the new DHT heater installed as part of the HOUP (EG77-DHTHTR), the 

permittee shall cease operating the existing DHT heater (EG07-DHTCHARHTR). (R 336.1205, R 336.2802, 

40 CFR 52.21)

6. On and after startup of the heavy oil upgrade project, the permittee shall not operate any emission unit in 

FG-HEATERS unless an acceptable plan that describes how emissions will be minimized during all startups, 

shutdowns, and malfunctions has been submitted to the AQD District Supervisor and the plan is being 

implemented, maintained, and followed.. The plan shall incorporate procedures recommended by the 

equipment manufacturer as well as standard industry practices. (R 336.1205, R 336.1911, R 336.1912, 

R 336.2802, 40 CFR 52.21)

* This requirement is state enforceable only. 

3

This condition is included at the request of the permittee.
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 53 of 103 

FGFLARES 

FLEXIBLE GROUP CONDITIONS

DESCRIPTION

All refinery flares. Four flares are subject to the NSR Consent Decree and subsequent revisions: 

EG-CRUDEFLARE, EG-UNIFFLARE, EG-ALKYFLARE, and EG-CPFLARE 

Emission Units: EG-CRUDEFLARE, EG-UNIFFLARE, EG-ALKYFLARE, EG-CPFLARE, 

EG-COKERFLARE 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ Operating 

Scenario 

Equipment Monitoring/ 

Testing Method

Underlying 

Applicable 

Requirements

1. NA 

2. There shall be no visible emissions from any flare in FGFLARES except for periods not to exceed a total of 

five minutes during any two consecutive hours. This requirement is based on the federal Standards of 

Performance for New Stationary Sources, 40 CFR 60.18(c)(1). 2

 (40 CFR Part 60 Subparts A and J)

II. MATERIAL LIMIT(S)

Material Limit Time Period/ Operating 

Scenario 

Equipment Monitoring/ 

Testing Method

Underlying 

Applicable 

Requirements

1. H2S in refinery 

fuel gas burneda 160 ppmv on a 

3 hour rolling 

average basis 2

According to method Each flare in 

FGFLARES 

SC VI.1 40 CFR 

60.104(a)(1) 

a

 The combustion in a flare of process upset gases or fuel gas that is released to the flare as a result of relief 

valve leakage or other emergency malfunctions is exempt from this requirement. For flares equipped with flare 

gas recovery, the determination that a relief valve leakage or other emergency malfunction is exempt from this 

requirement will be based on the root cause analysis conducted in accordance with SC III.1 through 14. 

III. PROCESS/OPERATIONAL RESTRICTION(S)

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

Sources as specified in 40 CFR Part 60 Subparts A and J, as they apply to FGFLARES. 2

 (R 336.1702, 

40 CFR Part 60 Subparts A & J)

2. The permittee shall comply with all provisions of the National Emission Standards for Hazardous Air 

Pollutants as specified in 40 CFR Part 63 Subparts A and CC, as they apply to FGFLARES. 2

 (R 336.1702, 

40 CFR Part 63 Subparts A and CC)

3. The permittee shall conduct an event-specific investigation into each flaring incident that results in sulfur 

dioxide emissions greater than 500 pounds from FGFLARES in any 24-hour period. The investigation shall 

be performed in accordance with the requirements outlined in Special Condition III.11. The Permittee may 

rely on prior investigation reports for events that have the same or similar root causes. 2 (R 336.1205, 

R 336.2802, 40 CFR 52.21, U.S. EPA Consent Order 01-40119)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 54 of 103 

4. The permittee shall conduct an event-specific investigation into each flaring incident that results in sulfur 

dioxide or volatile organic compound emissions greater than 500 pounds from FGFLARES in any 24-hour 

period. The investigation shall be performed in accordance with the requirements outlined in Special 

Condition III.12. The Permittee may rely on prior investigation reports for events that have the same or 

similar root causes. 3 (R 336.1201(3))

5. The permittee shall maintain FGFLARES in good working order and in a manner consistent with good 

pollution control practices for minimizing emissions including during periods of startup, shutdown, and 

malfunction. Good air pollution control practice for FGFLARES shall include, at a minimum, development, 

implementation, and operation in accordance with an approved Sulfur Shedding Plan to minimize or prevent 

excess sulfur dioxide emissions from the Sulfur Recovery Units, Tail Gas Treating Units (“TGTUs”), and 

associated amine system. The Sulfur Shedding Plan shall have as a goal the elimination of flaring incidents 

in excess of 500 pounds of sulfur dioxide in any 24-hour period through the following. 2 (R 336.1205, 

40 CFR 60.11(d), U.S. EPA Consent Order 01-40119)

a. Define maintenance and operation practices for the new Sulfur Recovery Plants, the Tail Gas Treating 

Units (“TGTUs”), and amine system, and associated equipment in conjunction with this project. The 

plan should also evaluate and address any upstream process unit that has a direct impact on the 

operation and maintenance of the new Sulfur Recovery Plants, TGTUs, and Amine Systems. 

b. Define good air pollution control practices to minimize the duration and amount of excess sulfur dioxide 

emissions from flaring events associated with the Sulfur Recovery Plants, TGTUs, and Amine Systems. 

The good pollution control practices shall include but not be limited to procedures to reduce excess 

sulfur dioxide emissions from a flaring incident through rate reduction or even shutdown of applicable 

process units associated with the flaring event. These practices should also entail operating measures 

and procedures to divert material being flared to other Sulfur Recovery Plants at the refinery. 

c. Define measures to ensure continuous operation of the Sulfur Recovery Plants and Amine Systems 

between scheduled maintenance turnarounds. The measures shall include, but not be limited to, sulfur 

shedding procedures, adequate equipment redundancy, new startup and shutdown procedures, 

emergency procedures and schedules to coordinate maintenance turnarounds of the Sulfur Recovery 

Plants, TGTUs, and any supplemental control device to coincide with scheduled turnarounds of major 

upstream process units. 

6. The permittee shall review and revise the Sulfur Shedding Plan on at least an annual basis to ensure it 

remains accurate. 2 (40 CFR 60.11(d), U.S. EPA Consent Order 01-40119)

7. The permittee shall conduct an event-specific investigation into each event that resulted in flaring more than 

500,000 standard cubic feet of material in FGFLARES in any 24-hour period. The permitted pilot and sweep 

gas routed to the flares shall be excluded from the 500,000 standard cubic feet threshold. The investigation 

shall be performed in accordance with the requirements outlined in Special Condition III.11. The permittee 

may rely on prior investigation reports for events that have the same or similar root causes. 2 (R 336.1205, 

R 336.2802, 40 CFR 52.21) 

8. The permittee shall establish a tracking system for flaring incidents that result in emissions greater than 100 

pounds but fewer than 500 pounds of VOC from FGFLARES in any 24-hour period. The permittee will take 

action to minimize the likelihood of recurrence of such incidents. After 28 instances of flaring events 

between 100 and 499 pounds of VOC within a consecutive twelve month period, permittee shall conduct an 

event-specific investigation into all such instances for the next six month period, at which point a new 12-

month period for purposes of counting instances shall begin.3 (R 336.1201(3))

9. The permittee shall prepare and follow a Flare Minimization Plan for FGFLARES. The plan shall be 

designed and implemented to reduce or eliminate flaring events and shall include, at a minimum, the 

following elements. 2 (R 336.1205, R 336.2802, 40 CFR 52.21)

a. A description and technical information for each flare that includes: 

i. Detailed process flow diagram accurately depicting all pipelines, process units, flare gas recovery 

systems, surge drums and knock-out pots, compressors and other equipment that vent to each 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 55 of 103 

flare. At a minimum, this shall include full and accurate as built dimensions and design capacities of 

the flare gas recovery systems, compressors, surge drums and knock-out pots. 

ii. Description of equipment, processes and procedures installed or implemented within the last five 

years to reduce flaring. The description shall specify the year of installation. 

iii. Description of any equipment, processes, or procedures the owner or operator plans to install or 

implement to eliminate or reduce flaring. The description shall specify the scheduled year of 

installation or implementation. 

iv. Description and evaluation of prevention measures to address the following: 

1. Flaring that has occurred or reasonably may be expected to occur during planned major 

maintenance activities, including startup and shutdown. The evaluation shall include a review of 

flaring that has occurred during these activities in the past five years and shall consider the 

feasibility of performing these activities without flaring. 

2. Flaring that may reasonably be expected to occur due to issues of gas quantity and quality. The 

evaluation shall include an audit of the storage capacity available for excess vent gases, the 

scrubbing capacity available for vent gases including any limitations associated with scrubbing 

the vent gases for use as a fuel, and shall consider the feasibility of reducing flaring through the 

recovery, treatment, and use of the gas or other means. 

3. Flaring caused by the recent failure of air pollution control equipment, process equipment, or a 

process to operate in a normal or usual manner. The evaluation shall consider the adequacy of 

existing maintenance schedules and protocols for such equipment. For purposes of this section, 

a failure is recurrent if it occurs more than twice in any five year period as a result of the same 

causes as identified in the event-specific investigations. 

b. A program of corrective action for malfunctioning process, air pollution control, and monitoring 

equipment related to the performance of FGFLARES. 

c. Procedures for conducting event-specific investigations as required by Conditions III.3 and III.7. 

d. A determination of the appropriate steam to hydrocarbon ratio for each material for each flare, the basis 

for the ratios, and methods for estimating emissions from each flare, including when the steam to 

hydrocarbon ratios are not maintained at the appropriate level. 

10. The permittee shall review and revise the Flare Minimization Plan on at least an annual basis to that ensure 

it remains current and complies with the provisions outlined in Special Condition III.9. 2 (R 336.1205, 

R 336.2802, 40 CFR 52.21)

11. At a minimum, the permittee shall include all of the following specific information in the event-specific 

investigations for the reportable flaring events (i.e. greater than 500 pounds SO2 or 500,000 scf of gas). 2

(R 336.1205, R 336.2802, 40 CFR 52.21, U.S. EPA Consent Order 01-40119)

a. The date and time that the flaring event started and ended. 

b. The total quantity of gas flared during each event. 

c. An estimate of the quantity of sulfur dioxide and VOC that was emitted and the calculations used to 

determine the quantities. 

d. The steps taken to limit the duration of the flaring event or the quantity of emissions associated with the 

event. 

e. A detailed analysis that sets forth the root cause and all significant contributing causes of the flaring 

event to the extent determinable. 

f. An analysis of the measures, if any, available to reduce the likelihood of a recurrence of a flaring event 

resulting from the same root cause or significant contributing causes in the future. 

g. A demonstration that the actions taken during the flaring event are consistent with the procedures 

specified in the Flare Minimization and Sulfur Shedding plans, as appropriate. If the actions taken 

during the flaring event are not consistent with the procedures specified in the appropriate plan, then the 

permittee must record the actions taken for that event and identify the reasons why the plan was not 

followed. 

h. For any flaring event that lasts longer than 24 hours, each calendar day shall constitute a separate 

event. 

12. At a minimum, the permittee shall include all of the following specific information in the event-specific 

investigations for the reportable flaring events (i.e. greater than 500 pounds SO2 or VOC, or more than 

500,000 scf of gas). 3 (R 336.1201(3))
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 56 of 103 

a. The date and time that the flaring event started and ended. 

b. The total quantity of gas flared during each event. 

c. An estimate of the quantity of sulfur dioxide and VOC that was emitted and the calculations used to 

determine the quantities. 

d. The steps taken to limit the duration of the flaring event or the quantity of emissions associated with the 

event. 

e. A detailed analysis that sets forth the root cause and all significant contributing causes of the flaring 

event to the extent determinable. 

f. An analysis of the measures, if any, available to reduce the likelihood of a recurrence of a flaring event 

resulting from the same root cause or significant contributing causes in the future. 

g. A demonstration that the actions taken during the flaring event are consistent with the procedures 

specified in the Flare Minimization and Sulfur Shedding plans, as appropriate. If the actions taken 

during the flaring event are not consistent with the procedures specified in the appropriate plan, then the 

permittee must record the actions taken for that event and identify the reasons why the plan was not 

followed. 

h. For any flaring event that lasts longer than 24 hours, each calendar day shall constitute a separate 

event. 

13. The permittee shall complete each event-specific investigation report within 45 calendar days after the 

reportable flaring incident. 2 (R 336.1205, R 336.2802, 40 CFR 52.21, U.S. EPA Consent Order 01-40119)

14. The permittee shall operate each flare in FGFLARES in a satisfactory manner at all times that emissions 

may be vented to it, including maintaining an adequate steam to hydrocarbon ratio in each flare and a 

minimum heat content of 300 BTU/scf in the vent gas to each flare. 2 (R 336.1910, 40 CFR 60.18)

IV. DESIGN/EQUIPMENT PARAMETER(S)

1. The permittee shall equip and maintain each flare in FGFLARES with a pilot flame. 2

 (R 336.1910, 40 CFR 

Part 60 Subpart A, 40 CFR 63.11(b)(5))

2. Each flare in FGFLARES shall be designed and installed so that it complies with the requirements of 

40 CFR Part 60 Subpart A. 2 (R 336.1910, 40 CFR 60.18(c))

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. Within 180 days after commencement of trial operation of the heavy oil upgrade project, the permittee shall 

verify by testing, at the owner’s expense, that each flare in FGFLARES is operating within the specified 

velocity and heat content limits specified within 40 CFR 60.18. No less than 60 days prior to testing, the 

Permittee shall submit a complete test plan to the AQD. The AQD must approve the final plan prior to 

testing. Verification 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 336.1910, 40 CFR 60.18)

See Appendix 1.5 of RO permit 199700013c 

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. Permittee shall monitor and keep records of the concentration of hydrogen sulfide in the refinery fuel gas 

burned in each flare in accordance with the Federal Standards of Performance as specified in 40 CFR 60, 

Subpart J, in a manner and with instrumentation acceptable to the Division. Fuel gas combustion devices 

having a common source of fuel gas may be monitored at only one location, if monitoring at this location 

accurately represents the concentration of H2S in the fuel gas being burned. 2 (40 CFR 60.105(a)(4))
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 57 of 103 

2. The permittee shall keep records of emissions and operating information for each flare in FGFLARES to 

comply with the federal Standards of Performance for New Stationary Sources as specified in 40 CFR 

Part 60 Subparts A and J. 2 (40 CFR Part 60 Subparts A & J)

3. The permittee shall monitor emissions and operating and maintenance information for each flare in 

FGFLARES in accordance with the National Emission Standards for Hazardous Air Pollutants as specified 

in 40 CFR Part 63 Subparts A and CC. 2 (40 CFR Part 63 Subparts A & CC)

4. The permittee shall keep records of emission information and operating and maintenance information for 

each flare in FGFLARES to comply with the National Emission Standards for Hazardous Air Pollutants as 

specified in 40 CFR Part 63 Subparts A and CC. The permittee shall keep all source emissions and 

operating and maintenance information on file at the facility for a period of at least five years and make them 

available to the Department upon request. 2 (40 CFR Part 63 Subparts A & CC)

5. The permittee shall track and ensure timely closure of the corrective actions, if any, identified to minimize 

the likelihood of a recurrence of the reportable flaring events. Permittee shall report every six months on the 

status of the yet-to-be-completed corrective actions related to the reportable flaring incidents. 2 (R 336.1205, 

R 336.2802, 40 CFR 52.21, U.S. EPA Consent Order 01-40119)

6. The permittee shall keep, in a satisfactory manner, a record of the current and prior versions of the Sulfur 

Shedding Plan and the Flare Minimization Plan for FGFLARES, as required by SC III.6 and III.10. The 

permittee shall keep all records on file at the facility and make them available to the Department upon 

request. (R 336.1205, R 336.2802, 40 CFR 52.21, U.S. EPA Consent Order 01-40119)

7. The Permittee shall monitor all flares for visible emissions using color video monitors with date and time 

stamp. (R 336.1205)

8. The permittee shall calculate and keep records of the annual emissions of PM, PM10, NOX, VOC, CO, SO2, 

sulfuric acid mist (H2SO4), hydrogen sulfide (H2S), and Total Reduced Sulfur (TRS) from the Detroit heavy 

oil upgrade project (Detroit HOUP), in tons per year on a calendar year basis. Records shall be kept in the 

format described in Appendix B, or an alternate format acceptable to the AQD Permit Section Supervisor. 

Calculations and record keeping shall begin the month in which the Detroit HOUP begins normal operations 

and shall continue for 10 years. (R 336.2818, 40 CFR 52.21(r)(6)(iii), 40 CFR Part 51 Appendix S) 

9. The permittee shall calculate, keep records of, and annually report to the AQD, the annual emissions of PM, 

PM10, NOX, VOC, CO, SO2, sulfuric acid mist (H2SO4), hydrogen sulfide (H2S), and Total Reduced Sulfur 

(TRS) from the Detroit heavy oil upgrade project (Detroit HOUP), in tons per year on a calendar year basis. 

Calculations shall be based on the best available and representative data. Supporting documentation shall 

be submitted with the emissions report, and shall be generally consistent with the format and specificity of 

Exhibit 7 of the Sierra Club Agreement. Records shall be kept in the format described in Appendix B, or an 

alternate format acceptable to the AQD Permit Section Supervisor. Calculations and record keeping shall 

begin the month in which the Detroit HOUP begins normal operations and shall continue for 10 years.3

(R 336.1201(3))

10. The permittee shall install, maintain, and continuously operate, for EG-CRUDEFLARE, EG-UNIFFLARE, 

EG-ALKYFLARE, and EG-CPFLARE, continuous flow measuring devices to continuously monitor and 

record the flow of gas to each of these flares. The flow measuring devices shall be sensitive to rapid flow 

changes, and have the capability of reporting both instantaneous velocity and totalized flow. Materials 

exposed to the flare gas shall be corrosion resistant. The flow measuring devices shall (i) feature 

automated daily calibrations at low and high ranges, and (ii) shall signal alarms if the calibration error or drift 

is exceeded, provided that the monitor is equipped with such capability. The volumetric flow measuring 

devices may consist of one or more flow meters, and, as combined, shall meet the following specifications. 

(R 336.1205, R 335.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

a. Velocity Range: 0.1-250 ft/sec. 

b. Repeatability: ± 1% of reading over the velocity range. 

c. Accuracy: ± 20% of reading over the velocity range of 0.1-1 ft/s and ± 5% of reading over the velocity 

range of 1-250 ft/s. 

d. Installation: Applicable AGA, ANSI, API, or equivalent standard. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 58 of 103 

e. Flow Rate Determination: Must be corrected to one atmosphere pressure and 68 °F and recorded as 

one-minute averages. 

f. Data Records: Measured continuously and recorded over one minute averages. The instrument shall 

be capable of storing or transferring all data for later retrieval. 

g. QA/QC: An annual verification of accuracy is required, and shall be specified by the manufacturer. 

11. The permittee shall install, maintain, and continuously operate devices to continuously monitor and record 

the flow of steam to each flare in FGFLARES, the VOC composition of the vent gas stream to each flare, 

and the steam to hydrocarbon ratio in each flare. The monitoring devices shall meet the following 

specifications. (R 336.1205, R 335.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

a. Turndown Ratio: 25:1. 

b. Repeatability: ± 1% of reading over the range of the instrument. 

c. Accuracy: +/- 1% from 100% to 15 % of span,+/- 2% from 15 % of span to 6 % of span, +/- 3% from 6 % 

of span to 4% of span. 

d. Installation: Applicable AGA, ANSI, API, or equivalent standard. 

e. Flow Rate Determination: Must be corrected to one atmosphere pressure and 68 °F and recorded as 

one-minute averages. 

f. Data Records: Measured continuously and recorded over one minute averages. The data acquisition 

system shall be capable of storing and transferring all data for later retrieval. 

g. QA/QC: An annual verification of accuracy is required, and shall be specified by the manufacturer. 

12. All data as generated by the flare and steam flow measuring devices shall be continuously recorded. The 

recording system(s) must have the capability to generate one-minute average data from that which is 

continuously generated by the flow measuring devices. (R 336.1205, R 335.1224, R 336.1702, R 336.2802, 

40 CFR 52.21)

13. The permittee shall maintain the flare and steam flow measuring devices and steam to hydrocarbon control 

system in good operating condition at all times when the flare that it serves is operational, except when out 

of service due to: 

a. Breakdowns and unplanned system maintenance of each monitoring device shall not exceed 96 hours, 

cumulatively, per quarter for each reporting period; or, 

b. Planned maintenance, which shall not exceed 14 days per 18 month period, provided that a written 

notification detailing the reason for maintenance and methods that will be used during the maintenance 

period to determine emissions associated with flare events is provided to the AQD District Supervisor 

prior to, or within 24 hours of, removal of the monitoring system from service. (R 336.1205, R 335.1224, 

R 336.1702, R 336.2802, 40 CFR 52.21)

14. The permittee shall install, calibrate, maintain and operate in a satisfactory manner a device to monitor and 

record the TRS concentration in the vent gas to each flare in FGFLARES on a continuous basis. 

(R 336.1205, R 335.1224, R 336.1702, R 336.2802, 40 CFR 52.21)

 

15. The permittee shall install, calibrate, maintain and operate in a satisfactory manner a gas chromatography 

system to monitor and record the total hydrocarbon, methane, and TRS concentration in the vent gas to 

each flare in FGFLARES on a continuous basis.3 (R 336.1201(3))

a. The gas chromatography system shall be maintained to be accurate within 5% of full scale. 

b. The minimum sampling frequency shall be one sample every 30 minutes. 

See Appendices 1.3 and 1.4 of RO Permit 199700013c 

VII. REPORTING

1. The permittee shall provide written notification of construction and operation of EG-COKERFLARE to 

comply with the federal Standards of Performance for New Stationary Sources, 40 CFR 60.7. The permittee 

shall submit this notification to the AQD District Supervisor within the time frames specified in 

40 CFR 60.7. 2

 (40 CFR 60.7)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 59 of 103 

2. The permittee shall submit a copy of the Sulfur Shedding and Flare Minimization Plans to the AQD District 

Supervisor for review at least 60 days before commencing operation of equipment associated with the 

heavy oil upgrade project. 2 (R 336.1205, R 336.2802, 40 CFR 52.21, U.S. EPA Consent Order 01-40119)

3. The permittee shall submit to the AQD District Supervisor an operations and maintenance (O&M) plan and a 

Flare Minimization Plan for each flare in FGFLARES at least 120 days before commencing operation of 

EG70-COKER. At a minimum the O&M plan shall include an inspection schedule and description of 

inspection procedures for the flare components, including the flare tips and pilots. 2 (40 CFR Part 63 

Subparts A & CC)

4. The permittee shall submit the data on the concentration of hydrogen sulfide in the refinery fuel gas burned 

in the flares to the AQD District Supervisor in an acceptable format within 30 days following the end of the 

quarter in which the records were collected. 2 (40 CFR 60.105(a)(4))

5. The permittee shall submit a semiannual summary of reportable flaring incidents to the AQD District 

Supervisor. Each report shall include, as a minimum, the number of reportable flaring incidents that 

occurred during the period, the amount of excess emissions during each reportable flaring incident, and the 

status of all yet-to-be-completed corrective actions from reportable flaring incidents. The permittee shall 

submit each report in an acceptable format within 30 days following the end of the semiannual period that 

the report covers. 2 (R 336.1205, R 336.2802, 40 CFR 52.21, U.S. EPA Consent Order 01-40119)

6. The permittee shall submit the information required by SC VI.8 to the AQD Permit Section Supervisor within 

60 days following the end of each reporting year if both the following occur for any of these pollutants: 

a. The calendar year actual emission from the Detroit HOUP exceed the baseline actual emissions (BAE) 

by a significant amount, and 

b. The calendar year actual emissions from the Detroit HOUP differ from the pre-construction projection for 

the emission units included in the Hybrid Applicability Test used for the Detroit HOUP. The preconstruction projection is the sum of the projected actual emissions from each emission unit using the 

actual-to-projected actual emissions test as part of the Hybrid Applicability Test, and the potential 

emissions from each emission unit using the potential-to-emit test as part of the Hybrid Applicability 

Test. 

The report shall contain the name, address, and telephone number of the facility (major stationary 

source); the annual emissions as calculated pursuant to this SC, and any other information the owner or 

operator wishes to include (i.e., an explanation why emissions differ from the pre-construction 

projection). (R 336.2818, 40 CFR 52.21(r)(6)(v))

7. The permittee shall submit the information required by SC VI.8 to the AQD Permit Section Supervisor within 

60 days following the end of each reporting year. The report shall contain the name, address, and 

telephone number of the facility (major stationary source); the annual emissions as calculated pursuant to 

this SC, and any other information the owner or operator wishes to include (i.e., an explanation why 

emissions differ from the pre-construction projection).3 (R 336.1201(3))

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards 

to the ambient air unless otherwise noted: 

Stack & Vent ID 

Maximum 

Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above Ground 

(feet) 

Underlying Applicable Requirements 

1. NA NA NA NA 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 60 of 103 

IX. OTHER REQUIREMENT(S)

1. NA 

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 3

This condition is included at the request of the permittee.
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 61 of 103 

TABLE F-1.4 {FG-PROCVENTS} 

FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING This emission group includes miscellaneous process vents subject to 

Refinery MACT 1 (40 CFR Part 63, Subpart CC) 

Emission Unit/Process Groups EG06-VENTV34, EG07-VENTV12, EG11-VENT14SUMP, EG11-

VENT21XF, EG11-VENT14XH, EG11-VENT21V47, EG21-S2OFFGAS 

I. DESIGN PARAMETERS

A. Pollution Control Equipment Flare, FCCU Charge Heater 

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

otherwise noted.

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. 

Temp. 

(°F) 

d. 

Air Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. NA NA NA NA NA NA 

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. NA 1. NA 

B. Pollutants Maximum Emission Limit

 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. NA 

3. Other Monitoring and/or 

Recordkeeping 

1. See Appendices 1.3 and 1.4 of RO Permit 199700013c 

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

1. Parameter to be Tested/ 

Recorded 

1. See Appendix 1.5 of RO Permit 199700013c 

2. Method/Analysis 1. See Appendix 1.5 of RO Permit 199700013c 

3. Frequency and Schedule of 

Testing/Recordkeeping 

1. See Appendix 1.5 of RO Permit 199700013c 

IV. REPORTING 

Reports and Schedules See Appendix 1.8 of RO Permit 199700013c 

V. OPERATIONAL PARAMETERS 

NA 

VI. OTHER REQUIREMENTS 

1. Permittee shall comply with all applicable requirements of 40 CFR Part 63, National Emission Standards for 

Hazardous Air Pollutants for Source Categories, Subpart A-General Provisions. (40 CFR Part 63, Subpart A)

2. Permittee shall comply with all applicable requirements of 40 CFR Part 63, Subpart CC-National Emission 

Standards for Hazardous Air Pollutants from Petroleum Refineries. See Appendix 1.7 of RO Permit 

199700013c. (40 CFR Part 63, Subpart CC)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 62 of 103 

TABLE F-1.4 {FG-PROCVENTS} 

FLEXIBLE GROUPING REQUIREMENTS

3. Permittee for a Group 1 miscellaneous process vent as defined in 40 CFR 63.641 shall comply with the 

requirements of either paragraphs (a) or (b) as follows: (40 CFR 63.643(a)) 

a. Permittee shall reduce emissions of organic HAPs using a flare that meets the requirements of 

40 CFR 63.11(b). Flares shall be operated at all times when emissions may be vented to them. 

(40 CFR 63.643(a)(1))

b. Permittee shall reduce emissions of organic HAPs, using a control device, by 98 percent or to a 

concentration of 20 parts per million by volume, on a dry basis, corrected to 3 percent oxygen, whichever 

is less stringent. Compliance can be determined by measuring either organic HAPs or TOCs using the 

procedures in 40 CFR 63.645. (40 CFR 63.643(a)(2))

4. If a boiler or process heater is used to comply with the percentage of reduction requirement or concentration 

limit specified in paragraph 40 CFR 63.643(a)(2), then the vent stream shall be introduced into the flame 

zone of such a device, or in a location such that the required percent reduction or concentration is achieved. 

Testing and monitoring is required only as specified in 40 CFR 63.644(a) and 63.645. (40 CFR 63.643(b))

* This requirement is state enforceable only. 

TABLE F-1.7 {FGGROUP2} 

FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING 

Emission Unit/Process Groups 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, EGTANK105, EGTANK106, EGTANK107, 

EGTANK120, EGTANK125, EGTANK126, EGTANK127, EGTANK128, 

EGTANK314, EGTANK315, EGTANK316, EGTANK317, EGTANK318, 

EGTANK319, EGTANK320, EGTANK324, EGTANK603, EGTANK608 

I. DESIGN PARAMETERS

A. Pollution Control 

Equipment 

None 

B. Stack/Vent Parameters NA

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. Temp 

(°F) 

d. Air 

Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. NA NA NA NA NA NA 

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. Sour kerosene 1. Throughput for FGGROUP2 shall not exceed a monthly average 

of 8,400 barrels per day. (R 336.1205, R 336.1225, R 336.2802, 

40 CFR 52.21) 

2. Sweet kerosene 1. Throughput for FGGROUP2 shall not exceed a monthly average 

of 8,400 barrels per day. (R 336.1205, R 336.1225, R 336.2802, 

40 CFR 52.21) 

3. Sour distillates 1. Throughput for FGGROUP2 shall not exceed a monthly average 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 63 of 103 

TABLE F-1.7 {FGGROUP2} 

FLEXIBLE GROUPING REQUIREMENTS

of 44,400 barrels per day. (R 336.1205, R 336.1225, R 336.2802, 

40 CFR 52.21)

4. Sweet distillates 1. Throughput for FGGROUP2 shall not exceed a monthly average 

of 44,400 barrels per day. (R 336.1205, R 336.1225, R 336.2802, 

40 CFR 52.21)

5. Sour gasoil 1. Throughput for FGGROUP2 shall not exceed a monthly average 

of 46,800 barrels per day. (R 336.1205, R 336.1225, R 336.2802, 

40 CFR 52.21)

6. Sweet gasoil 1. Throughput for FGGROUP2 shall not exceed a monthly average 

of 46,800 barrels per day. (R 336.1205, R 336.1225, R 336.2802, 

40 CFR 52.21)

B. Pollutants Maximum Emission Limit

1. NA 1. NA 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. Permittee for each Group 1 or Group 2 storage vessel shall keep readily 

accessible records showing the dimensions of the storage vessel and an 

analysis showing the capacity of the storage vessel. This record shall be 

kept as long as the storage vessel retains Group 1 or Group 2 status and 

is in operation. (40 CFR 63.123(a)), (40 CFR 63.654(i)) 

2. For each material identified in II.A. above, the permittee shall keep 

monthly throughput records for FGGROUP2 . All records shall be kept 

on file for a period of at least five years and made available to the 

Department upon request. (R 336.1205, R 336.1702(a), R 336.2802, 

40 CFR 52.21) 

3. Other Monitoring and/or 

Recordkeeping 

1. Recordkeeping as specified in Appendix 1.4 of RO Permit 199700013c 

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

1. Parameter to be Tested/ 

Recorded 

1. The permittee shall record the temperature of the stored product on a 

daily basis (alternative to true vapor pressure). (40 CFR 60.113) 

2. Method/Analysis 1. NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

1. NA 

IV. REPORTING 

Reports and Schedules See Appendix 1.8 of RO Permit 199700013c 

V. OPERATIONAL PARAMETERS 

1. NA 

VI. OTHER REQUIREMENTS 

1. Permittee shall comply with all applicable requirements of 40 CFR 63, Subparts A, General and Subpart CC, 

National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries. (40 CFR 63.640)

2. Permittee shall identify each storage tank subject to 40 CFR 63, Subpart CC requirements. 

(40 CFR 63.654(f)(1)(i)(A)) 

3. Permittee shall comply with all applicable requirements of 40 CFR 63.640(l) for group 2 tanks that are 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 64 of 103 

TABLE F-1.7 {FGGROUP2} 

FLEXIBLE GROUPING REQUIREMENTS

converted to Group 1 tanks. (40 CFR 63.640(l)) 

* This requirement is state enforceable only. 

TABLE F-1.8 {FG-IFRTANKS} 

FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING Internal floating roof tanks (IFR) that are subject to 40 CFR Part 63, Subpart 

CC as Group 1 Vessels or subject to 40 CFR 60, Subpart Kb. These tanks 

also may be subject to Michigan Air Pollution Control Rule 604 

(R 336.1604). This represents a consolidated requirement for internal 

floating roof tanks. 

Emission Unit/Process Groups 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 

I. DESIGN PARAMETERS 

A. Pollution Control 

Equipment 

Internal Floating Roof 

B. Stack/Vent Parameters NA 

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. Temp 

(°F) 

d. Air 

Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. NA NA NA NA NA NA 

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. NA 1. NA 

B. Pollutants Maximum Emission Limit

1. VOC 1. Vapor Pressure Maximum 11.0 psia (R 336.1225), (R 336.1702) 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. NA 

3. Other Monitoring and/or 

Recordkeeping 

1. Recordkeeping as specified in Appendix 1.4 of RO Permit 199700013c 

2. Permittee shall comply with the applicable requirements of 40 CFR 60, 

Subpart Kb, section 60.116b (Monitoring of Operations) for EGTANK19, 

EGTANK23, EGTANK40, EGTANK49, EGTANK51, EGTANK53, 

EGTANK57, EGTANK79, EGTANK101, EGTANK104, EGTANK116, 

EGTANK120, EGTANK135, EGTANK508, and EGTANK216. 

(R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), 

(40 CFR 52.21), (40 CFR 60, Subpart Kb, Section 60.116b) 
Marathon Petroleum Company LP (A9831) January 11, 2012 

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TABLE F-1.8 {FG-IFRTANKS} 

FLEXIBLE GROUPING REQUIREMENTS

3. Permittee shall comply with the applicable requirements of 40 CFR 60, 

Subpart Kb, section 60.116b (Monitoring of Operations) for EGTANK6, 

EGTANK8, EGTANK45, EGTANK46, EGTANK47, EGTANK48, 

EGTANK55, EGTANK58, EGTANK61, EGTANK72, and EGTANK507. 

For purposes of this requirement, the term “applicable requirements of 

40 CFR 60, Subpart Kb, section 60.116b (Monitoring of Operations)” 

refers to those requirements that would apply to these tanks if the tanks 

were actually subject to 40 CFR Part 60, Subpart Kb. (R 336.1205), 

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

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

1. Parameter to be Tested/ 

Recorded 

1. Permittee shall comply with the applicable requirements of 40 CFR 60, 

Subpart Kb, section 60.113b (Testing and Procedures), except as 

provided for in Refinery MACT 1, for EGTANK19, EGTANK23, 

EGTANK40, EGTANK49, EGTANK51, EGTANK53, EGTANK57, 

EGTANK79, EGTANK101, EGTANK104, EGTANK116, EGTANK120, 

EGTANK135, EGTANK508, and EGTANK216. (R 336.1205), 

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

(40 CFR 60, Subpart Kb, Section 60.113b), (40 CFR 63, Subpart CC) 

2. Permittee shall comply with the requirements of 40 CFR 60, Subpart Kb, 

section 60.113b (Testing and Procedures) that apply to tanks with 

internal floating roofs, except as provided for in Refinery MACT 1, for 

EGTANK6, EGTANK8, EGTANK45, EGTANK46, EGTANK47, 

EGTANK48, EGTANK55, EGTANK58, EGTANK61, EGTANK72, and 

EGTANK507. (R 336.1205), (R 336.1225), (R 336.1702(a)), 

(R 336.2802), (40 CFR 52.21)

2. Method/Analysis 1. NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

1. NA 

IV. REPORTING 

Reports and Schedules See Appendix 1.8 of RO Permit 199700013c 

V. OPERATIONAL PARAMETERS 

Requirements V.1-V.3 apply to EGTANK19, EGTANK23, EGTANK40, EGTANK49, EGTANK51, EGTANK53, 

EGTANK57, EGTANK79, EGTANK101, EGTANK104, EGTANK116, EGTANK120, EGTANK135, EGTANK508, 

and EGTANK216. 

1. Each opening in the internal floating roof except for leg sleeves, automatic bleeder vents, rim space vents, 

column wells, ladder wells, sample wells, and stub drains is to be equipped with a cover or lid which is to be 

maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use. The 

cover or lid shall be equipped with a gasket. Covers on each access hatch and automatic gauge float well 

shall be bolted except when they are in use. (R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), 

(40 CFR 52.21), (40 CFR 60.112b(a)(1)(iv)) 

2. Automatic bleeder vents shall be equipped with a gasket and are to be closed at all times when the roof is 

floating except when the roof is being floated off or is being landed on the roof leg supports. (R 336.1205), 

(R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.112b(a)(1)(v))

3. The internal floating roof shall rest or float on the liquid surface (but not necessarily in complete contact with 

it) inside a storage vessel that has a fixed roof. The internal floating roof shall be floating on the liquid 

surface at all times, except during initial fill and during those intervals when the storage vessel is completely 

emptied or subsequently emptied and refilled. When the roof is resting on the leg supports, the process of 

filling, emptying, or refilling shall be continuous and shall be accomplished as rapidly as possible. 

(R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.112b(a)(1)(i)) 
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FLEXIBLE GROUPING REQUIREMENTS

Requirements V.4-V.6 apply to EGTANK6, EGTANK8, EGTANK45, EGTANK46, EGTANK47, EGTANK48, 

EGTANK55, EGTANK58, EGTANK61, EGTANK72, and EGTANK507. 

4. Each opening in the internal floating roof except for leg sleeves, automatic bleeder vents, rim space vents, 

column wells, ladder wells, sample wells, and stub drains is to be equipped with a cover or lid which is to be 

maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use. The 

cover or lid shall be equipped with a gasket. Covers on each access hatch and automatic gauge float well 

shall be bolted except when they are in use. (R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), 

(40 CFR 52.21)

5. Automatic bleeder vents shall be equipped with a gasket and are to be closed at all times when the roof is 

floating except when the roof is being floated off or is being landed on the roof leg supports. (R 336.1205), 

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

6. The internal floating roof shall rest or float on the liquid surface (but not necessarily in complete contact with 

it) inside a storage vessel that has a fixed roof. The internal floating roof shall be floating on the liquid 

surface at all times, except during initial fill and during those intervals when the storage vessel is completely 

emptied or subsequently emptied and refilled. When the roof is resting on the leg supports, the process of 

filling, emptying, or refilling shall be continuous and shall be accomplished as rapidly as possible. 

(R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), (40 CFR 52.21)

VI. OTHER REQUIREMENTS 

Requirements VI.1-VI.14 apply to EGTANK19, EGTANK23, EGTANK40, EGTANK49, EGTANK51, EGTANK53, 

EGTANK57, EGTANK79, EGTANK101, EGTANK104, EGTANK116, EGTANK120, EGTANK135, EGTANK508, 

and EGTANK216. 

1. Each internal floating roof shall be equipped with one of the following closure devices between the wall of 

the storage vessel and the edge of the internal floating roof: 

a. A foam- or liquid-filled seal mounted in contact with the liquid (liquid-mounted seal). A liquid-mounted 

seal means a foam- or liquid-filled seal mounted in contact with the liquid between the wall of the 

storage vessel and the floating roof continuously around the circumference of the tank. 

b. Two seals mounted one above the other so that each forms a continuous closure that completely 

covers the space between the wall of the storage vessel and the edge of the internal floating roof. The 

lower seal may be vapor-mounted, but both must be continuous. 

c. A mechanical shoe seal. A mechanical shoe seal is a metal sheet held vertically against the wall 

of the storage vessel by springs or weighted levers and is connected by braces to the floating roof. 

A flexible coated fabric (envelope) spans the annular space between the metal sheet and the 

floating roof. (R 336.1205), R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), 

(40 CFR 60.112(b)(a)(1)(ii))

2. Each opening in a non-contact internal floating roof except for automatic bleeder vents (vacuum breaker 

vents) and the rim space vents is to provide a projection below the liquid surface. (R 336.1205), 

(R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.112(b)(a)(1)(iii))

3. Rim space vents shall be equipped with a gasket and are to be set to open only when the internal floating 

roof is not floating or at the manufacturer's recommended setting. (R 336.1205), (R 336.1225), 

(R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.112(b)(a)(1)(vi))

4. Each penetration of the internal floating roof for the purpose of sampling shall be a sample well. The sample 

well shall have a slit fabric cover that covers at least 90 percent of the opening. (R 336.1205), 

(R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.112(b)(a)(1)(viii))

5. Each penetration of the internal floating roof that allows for passage of a column supporting the fixed roof 
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FLEXIBLE GROUPING REQUIREMENTS

shall have a flexible fabric sleeve seal or a gasketed sliding cover. (R 336.1205), (R 336.1225), 

(R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.112(b)(a)(1)(viii))

6. Each penetration of the internal floating roof that allows for passage of a ladder shall have a gasketed 

sliding cover. (R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), 

(40 CFR 60.112(b)(a)(1)(ix))

7. Visually inspect the internal floating roof, the primary seal, and the secondary seal (if one is in service), 

prior to filling the storage vessel with VOL. If there are holes, tears, or other openings in the primary seal, 

the secondary seal, or the seal fabric or defects in the internal floating roof, or both, the owner or 

operator shall repair the items before filling the storage vessel. (R 336.1205), (R 336.1225), 

(R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.113(b)(a)(1))

8. For Vessels equipped with a liquid-mounted or mechanical shoe primary seal, visually inspect the internal 

floating roof and the primary seal or the secondary seal (if one is in service) through manholes and roof 

hatches on the fixed roof at least once every 12 months after initial fill. (R 336.1205), (R 336.1225), 

(R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.113(b)(a)(2))

9. If the internal floating roof is not resting on the surface of the VOL inside the storage vessel, or there is 

liquid accumulated on the roof, or the seal is detached, or there are holes or tears in the seal fabric, the 

owner or operator shall repair the items or empty and remove the storage vessel from service within 45 

days. If a failure that is detected during inspections required in this paragraph cannot be repaired within 45 

days and if the vessel cannot be emptied within 45 days, a 30-day extension may be requested from the 

Administrator in the inspection report required in Sec. 60.115b(a)(3). Such a request for an extension 

must document that alternate storage capacity is unavailable and specify a schedule of actions the 

company will take that will assure that the control equipment will be repaired or the vessel will be emptied 

as soon as possible. (R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), 

(40 CFR 60.113(b)(a)(3))

10. For vessels equipped with a double-seal system, permittee must visually inspect the internal floating roof, 

the primary seal, the secondary seal (if one is in service), gaskets, slotted membranes and sleeve seals (if 

any) each time the storage vessel is emptied and degassed, or at least every five years; or visually inspect 

the IFR and the primary and secondary seal through the manhole and roof hatches at least once every 12 

months after initial fill. (R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), 

(40 CFR 60.113(b)(a)(2))

11. Visually inspect the internal floating roof, the primary seal, the secondary seal (if one is in service), gaskets, 

slotted membranes and sleeve seals (if any) each time the storage vessel is emptied and degassed. If the 

internal floating roof has defects, the primary seal has holes, tears, or other openings in the seal or the seal 

fabric, or the secondary seal has holes, tears, or other openings in the seal or the seal fabric, or the gaskets 

no longer close off the liquid surfaces from the atmosphere, or the slotted membrane has more than 10 

percent open area, the owner or operator shall repair the items as necessary so that none of the conditions 

specified in this paragraph exist before refilling the storage vessel with VOL. In no event shall inspections 

conducted in accordance with this provision occur at intervals greater than 10 years in the case of 

vessels conducting the annual visual inspection as specified in paragraphs40 CFR 60.113b(a)(2) and 

(a)(3)(ii) and at intervals no greater than five years in the case of vessels specified in paragraph 40 CFR 

60.113b (a)(3)(i). (R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 

60.113(b)(a)(4))

12. Notify the Administrator in writing at least 30 days prior to the filling or refilling of each storage vessel for 

which an inspection is required by paragraphs (a)(1) and (a)(4) of this section to afford the Administrator 

the opportunity to have an observer present. (R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), 

(40 CFR 52.21), (40 CFR 60.113(b)(a)(5))
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FLEXIBLE GROUPING REQUIREMENTS

13. If the inspection required by paragraph 40 CFR 60.113b(a)(4) is not planned and the owner or operator 

could not have known about the inspection 30 days in advance or refilling the tank, the owner or operator 

shall notify the Administrator at least seven days prior to the refilling of the storage vessel. Notification shall 

be made by telephone immediately followed by written documentation demonstrating why the inspection 

was unplanned. Alternatively, this notification including the written documentation may be made in writing 

and sent by express mail so that it is received by the Administrator at least seven days prior to the refilling. 

(R 336.1205), (R 336.1225), (R 336.1702(b)), (R 336.2802), (40 CFR 52.21), (40 CFR 60.113(b)(a)(5))

14. The permittee shall comply with all applicable provisions of 40 CFR 60, Subparts A and Kb. (40 CFR 60, 

Subparts A and Kb) 

Requirements VI.15-V.27 apply to EGTANK6, EGTANK8, EGTANK45, EGTANK46, EGTANK47, EGTANK48, 

EGTANK55, EGTANK58, EGTANK61, EGTANK72, and EGTANK507. 

15. Each internal floating roof shall be equipped with one of the following closure devices between the wall of 

the storage vessel and the edge of the internal floating roof: 

a. A foam- or liquid-filled seal mounted in contact with the liquid (liquid-mounted seal). A liquid-mounted 

seal means a foam- or liquid-filled seal mounted in contact with the liquid between the wall of the 

storage vessel and the floating roof continuously around the circumference of the tank. 

b. Two seals mounted one above the other so that each forms a continuous closure that completely 

covers the space between the wall of the storage vessel and the edge of the internal floating roof. The 

lower seal may be vapor-mounted, but both must be continuous. 

c. A mechanical shoe seal. A mechanical shoe seal is a metal sheet held vertically against the wall of the 

storage vessel by springs or weighted levers and is connected by braces to the floating roof. A flexible 

coated fabric (envelope) spans the annular space between the metal sheet and the floating roof. 

(R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), (40 CFR 52.21)

16. Each opening in a non-contact internal floating roof except for automatic bleeder vents (vacuum breaker 

vents) and the rim space vents is to provide a projection below the liquid surface. (R 336.1205), 

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

17. Rim space vents shall be equipped with a gasket and are to be set to open only when the internal floating 

roof is not floating or at the manufacturer's recommended setting. R 336.1205), ((R 336.1225), 

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

18. Each penetration of the internal floating roof for the purpose of sampling shall be a sample well. The sample 

well shall have a slit fabric cover that covers at least 90 percent of the opening. (R 336.1205), 

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

19. Each penetration of the internal floating roof that allows for passage of a column supporting the fixed roof 

shall have a flexible fabric sleeve seal or a gasketed sliding cover. (R 336.1205), (R 336.1225), 

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

20. Each penetration of the internal floating roof that allows for passage of a ladder shall have a gasketed 

sliding cover. (R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), (40 CFR 52.21)

21. Visually inspect the internal floating roof, the primary seal, and the secondary seal (if one is in service), prior 

to filling the storage vessel with VOL. If there are holes, tears, or other openings in the primary seal, the 

secondary seal, or the seal fabric or defects in the internal floating roof, or both, the owner or operator shall 

repair the items before filling the storage vessel. (R 336.1205), (R 336.1225), (R 336.1702(a)), 

(R 336.2802), (40 CFR 52.21)

22. For Vessels equipped with a liquid-mounted or mechanical shoe primary seal, visually inspect the internal 

floating roof and the primary seal or the secondary seal (if one is in service) through manholes and roof 
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hatches on the fixed roof at least once every 12 months after initial fill. (R 336.1205), (R 336.1225), 

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

23. If the internal floating roof is not resting on the surface of the VOL inside the storage vessel, or there is 

liquid accumulated on the roof, or the seal is detached, or there are holes or tears in the seal fabric, the 

owner or operator shall repair the items or empty and remove the storage vessel from service within 45 

days. If a failure that is detected during inspections required in this paragraph cannot be repaired within 45 

days and if the vessel cannot be emptied within 45 days, a 30-day extension may be requested from the 

Administrator in the inspection report required in Sec. 60.115b(a)(3). Such a request for an extension must 

document that alternate storage capacity is unavailable and specify a schedule of actions the company will 

take that will assure that the control equipment will be repaired or the vessel will be emptied as soon as 

possible. (R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), (40 CFR 52.21)

24. For vessels equipped with a double-seal system, permittee must visually inspect the internal floating roof, 

the primary seal, the secondary seal (if one is in service), gaskets, slotted membranes and sleeve seals (if 

any) each time the storage vessel is emptied and degassed, or at least every five years; or visually inspect 

the IFR and the primary and secondary seal through the manhole and roof hatches at least once every 12 

months after initial fill. (R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), (40 CFR 52.21)

25. Visually inspect the internal floating roof, the primary seal, the secondary seal (if one is in service), gaskets, 

slotted membranes and sleeve seals (if any) each time the storage vessel is emptied and degassed. If the 

internal floating roof has defects, the primary seal has holes, tears, or other openings in the seal or the seal 

fabric, or the secondary seal has holes, tears, or other openings in the seal or the seal fabric, or the gaskets 

no longer close off the liquid surfaces from the atmosphere, or the slotted membrane has more than 10 

percent open area, the owner or operator shall repair the items as necessary so that none of the conditions 

specified in this paragraph exist before refilling the storage vessel with VOL. In no event shall inspections 

conducted in accordance with this provision occur at intervals greater than 10 years in the case of vessels 

conducting the annual visual inspection as specified in paragraphs40 CFR 60.113b(a)(2) and (a)(3)(ii) and 

at intervals no greater than five years in the case of vessels specified in paragraph 40 CFR 60.113b 

(a)(3)(i). (R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), (40 CFR 52.21)

26. Notify the Administrator in writing at least 30 days prior to the filling or refilling of each storage vessel for 

which an inspection is required by paragraphs (a)(1) and (a)(4) of this section to afford the Administrator the 

opportunity to have an observer present. (R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), 

(40 CFR 52.21)

27. If the inspection required by paragraph 40 CFR 60.113b(a)(4) is not planned and the owner or operator 

could not have known about the inspection 30 days in advance or refilling the tank, the owner or operator 

shall notify the Administrator at least seven days prior to the refilling of the storage vessel. Notification shall 

be made by telephone immediately followed by written documentation demonstrating why the inspection 

was unplanned. Alternatively, this notification including the written documentation may be made in writing 

and sent by express mail so that it is received by the Administrator at least seven days prior to the refilling. 

(R 336.1205), (R 336.1225), (R 336.1702(a)), (R 336.2802), (40 CFR 52.21)

The following requirements apply to all tanks in FG-IFRTANKS. 

28. The permittee shall comply with all applicable provisions of Rule 604. (R 336.1604)

29. The permittee may utilize the provisions of 40 CFR 63, Subpart CC, Section 63.640(n) for storage vessels 

included in FG-IFRTANKS (Overlap of subpart CC with other regulations for storage vessels). (40 CFR 63, 

Subpart CC, Section 63.640(n))

* This requirement is state enforceable only. 
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FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING This flexible group represents a consolidated requirement for external 

floating roof (EFR) tanks that are subject to 40 CFR Part 63, Subpart CC as 

Group 1 Vessels or subject to 40 CFR 60, Subpart Kb. These tanks may 

also be subject to Michigan Air Pollution Control Rule 623 (R 336.1623) 

and/or NSPS Subpart QQQ. This consolidated requirement basically 

adopts NSPS Kb for these EFR tanks. 

Emission Unit/Process Groups EGTANK32, EGTANK33, EGTANK108, EGTANK109, EGTANK110, 

EGTANK112, EGTANK113, EGTANK114, EGTANK115, EGTANK128, 

EGTANK129, EGTANK130, EGTANK601 

I. DESIGN PARAMETERS 

A. Pollution Control 

Equipment 

External Floating Roof 

B. Stack/Vent Parameters NA 

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. Temp 

(°F) 

d. Air 

Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. NA NA NA NA NA NA 

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. NA 1. NA 

B. Pollutants Maximum Emission Limit

1. NA 1. NA 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. NA 

3. Other Monitoring and/or 

Recordkeeping 

1. Recordkeeping as specified in Appendix 1.4 of RO Permit 199700013c. 

2. Permittee shall comply with the applicable requirements of 40 CFR 60, 

Subpart Kb, section 60.116b (Monitoring of Operations) for 

EGTANK129. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 

40 CFR 52.21, 40 CFR 60, Subpart Kb, Section 60.116b) 

3. Permittee shall comply with the requirements of 40 CFR 60, Subpart Kb, 

section 60.116b (Monitoring of Operations) that apply to tanks with 

external floating roofs, for EGTANK32, EGTANK33, EGTANK108, 

EGTANK109, EGTANK110, EGTANK112, EGTANK113, EGTANK114, 

EGTANK115, EGTANK130, and EGTANK601. (R 336.1205, 

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

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

1. Parameter to be Tested/ 

Recorded 

1. Permittee shall comply with the applicable requirements of 40 CFR 60, 

Subpart Kb, section 60.113b (Testing and Procedures), except as 
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provided for in Refinery MACT 1, for EGTANK129. (R 336.1205, 

R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 60, 

Subpart Kb, Section 60.113b, 40 CFR 63, Subpart CC) 

2. Permittee shall comply with the applicable requirements of 40 CFR 60, 

Subpart Kb, section 60.113b (Testing and Procedures), except as 

provided for in Refinery MACT 1, for EGTANK32, EGTANK33, 

EGTANK108, EGTANK109, EGTANK110, EGTANK112, EGTANK113, 

EGTANK114, EGTANK115, EGTANK130, and EGTANK601. For 

purposes of this requirement, the term “applicable requirements of 

40 CFR 60, Subpart Kb, section 60.113b (Testing and Procedures), 

except as provided for in Refinery MACT 1” refers to those 

requirements that would apply to these tanks if the tanks were actually 

subject to 40 CFR Part 60, Subpart Kb. (R 336.1205, R 336.1225*, 

R 336.1702(a), R 338.2802, 40 CFR 52.21)

2. Method/Analysis 1. NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

1. NA 

IV. REPORTING 

Reports and Schedules 

V. OPERATIONAL PARAMETERS 

Requirements V.1-V.4 apply to EGTANK129. 

1. Each external floating roof shall be equipped with a closure device between the wall of the storage vessel and 

the roof edge. The closure device is to consist of two seals, one above the other. The lower seal is referred 

to as the primary seal, and the upper seal is referred to as the secondary seal. (R 336.1205, R 336.1225*, 

R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 60.112b(a)(2)(i))

2. The primary seal shall be either a mechanical shoe seal or a liquid-mounted seal. Except as provided in 

40 CFR 60.113b(b)(4), the seal shall completely cover the annular space between the edge of the floating 

roof and tank wall. The secondary seal shall completely cover the annular space between the external 

floating roof and the wall of the storage vessel in a continuous fashion except as allowed in 40 CFR 

60.113(b)(4) (45-day repair requirement + 30-day extension). (R 336.1205, R 336.1225*, R 336.1702(b), 

R 336.2802, 40 CFR 52.21, 40 CFR 60.112b(a)(2)(i)(A) and (B))

3. Except for automatic bleeder vents and rim space vents, each opening in a noncontact external floating roof 

shall provide a projection below the liquid surface. Except for automatic bleeder vents, rim space vents, roof 

drains, and leg sleeves, each opening in the roof is to be equipped with a gasket cover, seal, or lid that is to 

be maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use. 

Automatic bleeder vents are to be closed at all times when the roof is floating except when the roof is being 

floated off or is being landed on the roof leg supports. Rim vents are to be set to open when the roof is being 

floated off the roof legs supports or at the manufacturer's recommended setting. Automatic bleeder vents 

and rim space vents are to be gasketed. Each emergency roof drain is to be provided with a slotted 

membrane fabric cover that covers at least 90 percent of the area of the opening. (R 336.1205, R 336.1225*, 

R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 60.112b(a)(2)(ii))

4. The roof shall be floating on the liquid at all times (i.e., off the roof leg supports) except during initial fill until 

the roof is lifted off leg supports and when the tank is completely emptied and subsequently refilled. The 

process of filling, emptying, or refilling when the roof is resting on the leg supports shall be continuous and 

shall be accomplished as rapidly as possible. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 

40 CFR 52.21, 40 CFR 60.112b(a)(2)(iii)) 

Requirements V.5-V.8 apply to EGTANK32, EGTANK33, EGTANK108, EGTANK109, EGTANK110, 

EGTANK112, EGTANK113, EGTANK114, EGTANK115, EGTANK130, and EGTANK601 
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5. Each external floating roof shall be equipped with a closure device between the wall of the storage vessel and 

the roof edge. The closure device is to consist of two seals, one above the other. The lower seal is referred 

to as the primary seal, and the upper seal is referred to as the secondary seal. (R 336.1205, R 336.1225*, 

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

6. The primary seal shall be either a mechanical shoe seal or a liquid-mounted seal. Except as provided in 

40 CFR 60.113b(b)(4), the seal shall completely cover the annular space between the edge of the floating 

roof and tank wall. The secondary seal shall completely cover the annular space between the external 

floating roof and the wall of the storage vessel in a continuous fashion except as allowed in 

40 CFR 60.113(b)(4) (45-day repair requirement + 30-day extension). (R 336.1205, R 336.1225*, 

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

7. Except for automatic bleeder vents and rim space vents, each opening in a noncontact external floating roof 

shall provide a projection below the liquid surface. Except for automatic bleeder vents, rim space vents, roof 

drains, and leg sleeves, each opening in the roof is to be equipped with a gasket cover, seal, or lid that is to 

be maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use. 

Automatic bleeder vents are to be closed at all times when the roof is floating except when the roof is being 

floated off or is being landed on the roof leg supports. Rim vents are to be set to open when the roof is being 

floated off the roof legs supports or at the manufacturer's recommended setting. Automatic bleeder vents 

and rim space vents are to be gasketed. Each emergency roof drain is to be provided with a slotted 

membrane fabric cover that covers at least 90 percent of the area of the opening. (R 336.1205, R 336.1225*, 

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

8. The roof shall be floating on the liquid at all times (i.e., off the roof leg supports) except during initial fill until 

the roof is lifted off leg supports and when the tank is completely emptied and subsequently refilled. The 

process of filling, emptying, or refilling when the roof is resting on the leg supports shall be continuous and 

shall be accomplished as rapidly as possible. (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 

40 CFR 52.21)

VI. OTHER REQUIREMENTS 

Requirements VI.1-VI.9 apply to EGTANK129. 

1. Permittee shall determine the gap areas and maximum gap widths, between the primary seal and the wall of 

the storage vessel and between the secondary seal and the wall of the storage vessel according to the 

following frequency: (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(1))

i. Measurements of gaps between the tank wall and the primary seal (seal gaps) shall be performed 

during the hydrostatic testing of the vessel or within 60 days of the initial fill with VOL and at least once 

every five years thereafter. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(1)(i))

ii. Measurements of gaps between the tank wall and the secondary seal shall be performed within 60 

days of the initial fill with VOL and at least once per year thereafter. (R 336.1205, R 336.1225*, 

R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(1)(ii))

iii. If any source ceases to store VOL for a period of 1 year or more, subsequent introduction of 

VOL into the vessel shall be considered an initial fill for the purposes of paragraphs 40 CFR 

60.113b(b)(1)(i) and (b)(1)(ii). (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(1)(iii))

2. Permittee shall determine gap widths and areas in the primary and secondary seals individually by the 

following procedures: (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(2))

i. Measure seal gaps, if any, at one or more floating roof levels when the roof is floating off the 

roof leg supports. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(2)(i)) 
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FLEXIBLE GROUPING REQUIREMENTS

ii. Measure seal gaps around the entire circumference of the tank in each place where a 0.32-cm 

diameter uniform probe passes freely (without forcing or binding against the seal) between the seal and 

the wall of storage vessel and measure the circumferential distance of each such location. 

(R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(2)(ii))

iii. The total surface area of each gap described in paragraph (b)(2)(ii) of this section shall be determined 

by using probes of various widths to measure accurately the actual distance from the tank wall to 

the seal and multiplying each such width by its respective circumferential distance. (R 336.1205, 

R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(2)(iii))

3. Permittee shall add the gap surface area of each gap location for the primary seal and the secondary seal 

individually and divide the sum for each seal by the nominal diameter of the tank and compare each ratio to 

the respective standards in paragraph 40 CFR 60.113b(b)(4). (R 336.1205, R 336.1225*, R 336.1702(b), 

R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(3))

4. Permittee shall make necessary repairs or empty the storage vessel within 45 days of identification in any 

inspection for seals not meeting the following requirements (R 336.1205, R 336.1225*, R 336.1702(b), 

R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(4)): 

i. The accumulated area of gaps between the tank wall and the mechanical shoe or liquid-mounted 

primary seal shall not exceed 212 Cm(2) per meter of tank diameter, and the width of any portion of 

any gap shall not exceed 3.81 cm. (A) One end of the mechanical shoe is to extend into the stored 

liquid, and the other end is to extend a minimum vertical distance of 61 cm above the stored liquid 

surface. (B) There are to be no holes, tears, or other openings in the shoe, seal fabric, or seal 

envelope. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 

60.113b(b)(4)(i))

ii. The secondary seal is to meet the following requirements: (A) The secondary seal is to be installed 

above the primary seal so that it completely covers the space between the roof edge and the tank wall 

except as provided in paragraph 40 CFR 60.113b(b)(2)(iii). (B) The accumulated area of gaps between 

the tank wall and the secondary seal shall not exceed 21.2 cm(2) per meter of tank diameter, and the 

width of any portion of any gap shall not exceed 1.27 cm. (C) There are to be no holes, tears, or other 

openings in the secondary seal or seal fabric. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 

40 CFR 52.21, 40 CFR 60.113b(b)(4)(ii)) 

iii. If a failure that is detected during inspections required in paragraph 40 CFR 60.113b(b)(1) cannot be 

repaired within 45 days and if the vessel cannot be emptied within 45 days, a 30-day extension may be 

requested from the Administrator in the inspection report required in 40 CFR 60.115(b)(4). Such 

extension request must include a demonstration of unavailability of alternate storage capacity and a 

specification of a schedule that will assure that the control equipment will be repaired or the vessel will 

be emptied as soon as possible. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 

40 CFR 52.21, 40 CFR 60.113b(b)(4)(iii))

5. Permittee shall notify the Administrator 30 days in advance of any gap measurements required by 

paragraph 40 CFR 60.113b(b)(1) to afford the Administrator the opportunity to have an observer present. 

(R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(5))

6. Permittee shall visually inspect the external floating roof, the primary seal, secondary seal, and fittings each 

time the vessel is emptied and degassed. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 

40 CFR 52.21, 40 CFR 60.113b(b)(6))

7. If the external floating roof has holes, tears, or other openings in the seal or the seal fabric, or the secondary 

seal has holes, tears, or other openings in the seal or the seal fabric, the permittee shall repair the items 

as necessary so that none of the conditions specified in this paragraph exist before filling or refilling 

the storage vessel with VOL. (R 336.1205, R 336.1225*, R 336.1702(b), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(6)(i))
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8. For all the inspections required by paragraph 40 CFR 60.113b(b)(6), the permittee shall notify the 

Administrator in writing at least 30 days prior to the filling or refilling of each storage vessel to afford the 

Administrator the opportunity to inspect the storage vessel prior to refilling. If the inspection required by 

paragraph 40 CFR 60.113b(b)(6) is not planned and the permittee could not have known about the 

inspection 30 days in advance of refilling the tank, the permittee shall notify the Administrator at least seven 

days prior to the refilling of the storage vessel. Notification shall be made by telephone immediately 

followed by written documentation demonstrating why the inspection was unplanned. Alternatively, this 

notification including the written documentation may be made in writing and sent by express mail so that it is 

received by the Administrator at least seven days prior to the refilling. (R 336.1205, R 336.1225*, 

R 336.1702(b), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(6)(ii))

9. The permittee shall comply with all applicable provisions of 40 CFR 60 as follows:

Subpart A- General Subpart Kb- Standards of Performance for Volatile Organic Liquid Storage Vessels 

(40 CFR 60, Subparts A and Kb) 

Requirements VI.10-VI.17 apply to EGTANK32, EGTANK33, EGTANK108, EGTANK109, EGTANK110, 

EGTANK112, EGTANK113, EGTANK114, EGTANK115, EGTANK130, and EGTANK601. 

10. Permittee shall determine the gap areas and maximum gap widths, between the primary seal and the wall of 

the storage vessel and between the secondary seal and the wall of the storage vessel according to the 

following frequency: (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(1))

i. Measurements of gaps between the tank wall and the primary seal (seal gaps) shall be performed 

during the hydrostatic testing of the vessel or within 60 days of the initial fill with VOL and at least once 

every five years thereafter. (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(1)(i))

ii. Measurements of gaps between the tank wall and the secondary seal shall be performed within 60 

days of the initial fill with VOL and at least once per year thereafter. (R 336.1205, R 336.1225*, 

R 336.1702(a), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(1)(ii))

iii. If any source ceases to store VOL for a period of one year or more, subsequent introduction of 

VOL into the vessel shall be considered an initial fill for the purposes of paragraphs 40 CFR 

60.113b(b)(1)(i) and (b)(1)(ii). (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(1)(iii))

11. Permittee shall determine gap widths and areas in the primary and secondary seals individually by 

the following procedures: (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(2))

i. Measure seal gaps, if any, at one or more floating roof levels when the roof is floating off the 

roof leg supports. (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 

40 CFR 60.113b(b)(2)(i))

ii. Measure seal gaps around the entire circumference of the tank in each place where a 0.32-cm 

diameter uniform probe passes freely (without forcing or binding against the seal) between the seal and 

the wall of storage vessel and measure the circumferential distance of each such location. 

(R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(2)(ii))

iii. The total surface area of each gap described in paragraph (b)(2)(ii) of this section shall be determined 

by using probes of various widths to measure accurately the actual distance from the tank wall to the 

seal and multiplying each such width by its respective circumferential distance. (R 336.1205, 

R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(2)(iii))

12. Permittee shall add the gap surface area of each gap location for the primary seal and the secondary seal 

individually and divide the sum for each seal by the nominal diameter of the tank and compare each ratio to 

the respective standards in paragraph 40 CFR 60.113b(b)(4). (R 336.1205, R 336.1225*, R 336.1702(a), 

R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(3))
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FLEXIBLE GROUPING REQUIREMENTS

13. Permittee shall make necessary repairs or empty the storage vessel within 45 days of identification in any 

inspection for seals not meeting the following requirements (R 336.1205, R 336.1225*, R 336.1702(a), 

R 336.2802, (40 CFR 52.21, 40 CFR 60.113b(b)(4)): 

i. The accumulated area of gaps between the tank wall and the mechanical shoe or liquid-mounted 

primary seal shall not exceed 212 Cm(2) per meter of tank diameter, and the width of any portion of 

any gap shall not exceed 3.81 cm. (A) One end of the mechanical shoe is to extend into the stored 

liquid, and the other end is to extend a minimum vertical distance of 61 cm above the stored liquid 

surface. (B) There are to be no holes, tears, or other openings in the shoe, seal fabric, or seal 

envelope. (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 40 CFR 

60.113b(b)(4)(i))

ii. The secondary seal is to meet the following requirements: (A) The secondary seal is to be installed 

above the primary seal so that it completely covers the space between the roof edge and the tank wall 

except as provided in paragraph 40 CFR 60.113b(b)(2)(iii). (B) The accumulated area of gaps between 

the tank wall and the secondary seal shall not exceed 21.2 cm(2) per meter of tank diameter, and the 

width of any portion of any gap shall not exceed 1.27 cm. (C) There are to be no holes, tears, or other 

openings in the secondary seal or seal fabric. (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 

40 CFR 52.21, 40 CFR 60.113b(b)(4)(ii))

iii. If a failure that is detected during inspections required in paragraph 40 CFR 60.113b(b)(1) cannot be 

repaired within 45 days and if the vessel cannot be emptied within 45 days, a 30-day extension may be 

requested from the Administrator in the inspection report required in 40 CFR 60.115(b)(4). Such 

extension request must include a demonstration of unavailability of alternate storage capacity and a 

specification of a schedule that will assure that the control equipment will be repaired or the vessel will 

be emptied as soon as possible. (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 

40 CFR 52.21, 40 CFR 60.113b(b)(4)(iii)

14. Permittee shall notify the Administrator 30 days in advance of any gap measurements required by 

paragraph 40 CFR 60.113b(b)(1) to afford the Administrator the opportunity to have an observer present. 

(R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(5))

15. Permittee shall visually inspect the external floating roof, the primary seal, secondary seal, and fittings each 

time the vessel is emptied and degassed. (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 

40 CFR 52.21, 40 CFR 60.113b(b)(6))

16. If the external floating roof has holes, tears, or other openings in the seal or the seal fabric, or the 

secondary seal has holes, tears, or other openings in the seal or the seal fabric, the permittee shall repair 

the items as necessary so that none of the conditions specified in this paragraph exist before filling or 

refilling the storage vessel with VOL. (R 336.1205, R 336.1225*, R 336.1702(a), R 336.2802, 40 CFR 

52.21, 40 CFR 60.113b(b)(6)(i))

17. For all the inspections required by paragraph 40 CFR 60.113b(b)(6), the permittee shall notify the 

Administrator in writing at least 30 days prior to the filling or refilling of each storage vessel to afford the 

Administrator the opportunity to inspect the storage vessel prior to refilling. If the inspection required by 

paragraph 40 CFR 60.113b(b)(6) is not planned and the permittee could not have known about the 

inspection 30 days in advance of refilling the tank, the permittee shall notify the Administrator at least seven 

days prior to the refilling of the storage vessel. Notification shall be made by telephone immediately followed 

by written documentation demonstrating why the inspection was unplanned. Alternatively, this notification 

including the written documentation may be made in writing and sent by express mail so that it is received 

by the Administrator at least seven days prior to the refilling. (R 336.1205, R 336.1225*, R 336.1702(a), 

R 336.2802, 40 CFR 52.21, 40 CFR 60.113b(b)(6)(ii))

The following requirements apply to all tanks in FG-EFRTANKS. 

18. The permittee shall comply with all applicable provisions of Rule 623. (R 336.1623) 
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FLEXIBLE GROUPING REQUIREMENTS

19. The permittee may utilize the provisions of 40 CFR 63, Subpart CC, Section 63.640(n) for storage vessels 

included in FG-EFRTANKS (Overlap of subpart CC with other regulations for storage vessels). (40 CFR 63, 

Subpart CC, Section 63.640(n)) 

20. The permittee shall document it’s current storage tank inspection and maintenance protocol. The protocol 

shall include provisions to increase inspection frequency on the storage tanks during winter months and to 

winterize the storage tank roof drains seasonally.3

 (R 336.1201(3))

* This requirement is state enforceable only. 

3

This condition is included at the request of the permittee.

TABLE F-1.12 {FG29-IGF} 

FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING Flexible grouping consisting of two induced gas flotation units which are 

part of the wastewater treatment plant and are covered by permit 190-00A. 

Emission Unit/Process Groups EG29-IGF1, EG29-IGF2 

Flexible Grouping ID FGDHOUPANNUAL 

I. DESIGN PARAMETERS 

A. Pollution Control Equipment None 

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

otherwise noted.

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. Temp 

(°F) 

d. 

Air Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. SV29-IGF1 20 * 6 * NA NA R 336.1225 

2. SV29-IGF2 20 * 6 * NA NA R 336.1225

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. NA 1. NA 

B. Pollutants Maximum Emission Limit

1.Volatile Organic Compounds 1. 8.41 tons per 12-month rolling time period (R 336.1702(a)), 

(R 336.1225)

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. The permittee shall monitor the pressure setting on each decant vessel 

conservation vent in a manner and with instrumentation acceptable to 

the Division. (R 336.1225), (R 336.1702(a)), (R 336.1910)

2. Permittee shall continuously monitor the wastewater throughput for 

FG29-IGF in a manner and with instrumentation acceptable to the 

Division. (R 336.1225), (R 336.1702(a)), (R 336.1910)
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TABLE F-1.12 {FG29-IGF} 

FLEXIBLE GROUPING REQUIREMENTS

3. Other Monitoring and/or 

Recordkeeping 

1. Permittee shall maintain the following written records for FG29-IGF: 

a. A record of monthly wastewater throughputs as determined at the 

end of each calendar month. 

b. A record of monthly VOC emission rate including the 12-month 

rolling time period emission rate. 

c. A record demonstrating the calculations used to determine the 

VOC emission rate. 

d. Once every eight-hour shift, the permittee shall record the 

pressure setting for each decant vessel conservation vent. 

e. Once every eight-hour shift, the permittee shall record the position 

of each decant vessel conservation vent valve. 

The above written records shall be maintained for a period of at least 

five years and shall be made available to the Division upon request. 

(R 336.1225), (R 336.1702(a)), (R 336.1910) 

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

1. Parameter to be Tested/ 

Recorded 

1. NA 

2. Method/Analysis 1. NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

1. NA 

IV. REPORTING 

Reports and Schedules 

V. OPERATIONAL PARAMETERS 

1. The wastewater throughput for FG29-IGF shall not exceed 1,682,000,000 gallons per 12-month rolling time 

period as determined at the end of each calendar month. (R 336.1225), (R 336.1702(a))

2. Permittee shall ensure FG29-IGF meets all the applicable standards of the Federal National Emission 

Standards for Hazardous Air Pollutants, 40 CFR, Part 61, Subparts A and FF. (R 336.1213(3))

3. Permittee shall ensure FG29-IGF meets all the applicable standards of the Federal National Emission 

Standards for Hazardous Air Pollutants for Source Categories, 40 CFR, Part 63, Subparts A and CC at 

existing sources. (R 336.1213(3))

4. Permittee shall not operate EG29-IGF1 or EG29-IGF2 unless the fixed roofs and conservation vent for the 

emission unit are installed and operating properly. (R 336.1225), (R 336.1702(a)), (R 336.1910)

5. The pressure setting on decant vessel conservation vents in FG29-IGF shall be equal to or greater than 2.0 

pounds per square inch gauge. (R 336.1225), (R 336.1702(a), (R 336.1910)

VI. OTHER REQUIREMENTS 

1. NA 

* This requirement is state enforceable only. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

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TABLE F-1.11 {FG-PROCUNITS} 

FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING Process groups subject to leak detection and repair requirements (LDAR). This 

flexible grouping is subject to the consolidated LDAR requirements of 

40 CFR 60, Subparts VV and VVa; 40 CFR 60, Subparts GGG and GGGa; 

40 CFR 63, Subpart CC as listed in Section VI of this table. For the purpose of 

this consolidated LDAR requirement the following are affected facilities: (1) 

compressors and (2) the group of all equipment {see definition in 40 CFR 

60.591} within a process unit. 

Emission Unit/Process Groups EG04VACUUM, EG05-CRUDE, EG07-DHT, EG08-GOHT, 

EG09-ALKYLATION, EG11-FCCU, EG12-GASCON, EG13-PROPYLENE, 

EG14-CCRPLATFORMER, EG16-NAPHHYTREAT, EG19-KEROHYTREAT, 

EG21-CPTREATER, EG22-TANKFARMS, EG22-LPGRAILRACK, 

EG29-WASTEWATER, EG38-ROUGETERMNL, EG42-43SULRECOV, 

EG99-LPGLOADRACK, EG41-SOURWATER, EG22-ASPHLOAD, 

EG70-COKERPLANT, EG71-H2PLANT, EG72-SULRBLOCK2, 

EG73-SOURWATER2, EG77-DHTHYTREAT, EG76-UTILITIES, 

EG78-FUELGASRECOVERY 

Flexible Grouping ID FGDHOUPANNUAL 

I. DESIGN PARAMETERS

A. Pollution Control Equipment NA 

B. Stack/Vent Parameters NA

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust Dimension 

(inches) 

c. 

Temp 

(F) 

d. Air 

Flow Rate 

(acfm) 

Applicable 

Requirement 

NA NA NA NA NA NA 

C. Other Design Parameters 

1. 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. NA 1. NA 

B. Pollutants Maximum Emission Limit

1. VOC For all pumps: 

A leak shall be defined as an instrument reading of 2,000 ppm or greater, as 

specified in NSPS Subpart VVa. (Consent Order No. 01-40119, 

40 CFR Part 60 Subpart GGGa) 

For valves in gas/vapor or light liquid service: 

A leak shall be defined as an instrument reading of 500 ppm or greater, as 

specified in NSPS Subpart VVa. (Consent Order No. 01-40119, 

40 CFR Part 60 Subpart GGGa) 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. NA 

3. Other Monitoring and/or 

Recordkeeping 

1. See Appendix 1.4 of RO Permit 199700013c 
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FLEXIBLE GROUPING REQUIREMENTS

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

1. Parameter to be Tested/ 

Recorded 

NA 

2. Method/Analysis NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

NA 

IV. REPORTING 

Reports and Schedules See Appendix 1.8 of RO Permit 199700013c

V. OPERATIONAL PARAMETERS 

NA 

VI. OTHER REQUIREMENTS 

1. Permittee shall not cause or allow the emission of any volatile organic compound from any existing component, 

as listed in R 336.1622(2), of a petroleum refinery, including topping plants, unless all applicable provisions of 

40 CFR 60.590 to 60.593 (2000), standards of performance for equipment leaks of volatile organic compound in 

petroleum refineries, are implemented. NOTE: The following more stringent leak definitions shall be 

implemented: (R 336.1622(1), 40 CFR Part 60 Subpart GGGa)

a. Pumps 2,000 ppm instead of 10,000 ppm 

b. Valves in gas/vapor or light liquid service 500 ppm instead of 10,000 ppm 

2. Permittee shall comply with the applicable requirements of 40 CFR Part 60, Subpart GGGa as soon as 

practicable after startup of the heavy oil upgrade project. (R 336.1622(1), (40 CFR 60.592(a)), 40 CFR Part 60 

Subpart GGGa)

3. Permittee may elect to comply with the requirements of 40 CFR 60.483-1 and 483-2. (R 336.1622(1), 

(40 CFR 60.592(b))

4. Permittee may apply to the EPA Administrator for a determination of equivalency for any means of emission 

limitation that achieves a reduction in emissions of VOC at least equivalent to the reduction in emission of VOC 

achieved by the controls required in 40 CFR 60, Subpart GGG. In doing so, the permittee shall comply with the 

requirements of 40 CFR 60.484. (R 336.1622(1), (40 CFR 60.592(c))

5. Permittee shall comply with the provisions of 40 CFR 60.485 except as provided in 40 CFR 60.593. 

(R 336.1622(1), (40 CFR 60.592(d))

6. Permittee shall comply with the requirements of 40 CFR 60.486 and 487. (R 336.1622(1), (40 CFR 60.592(e))

7. Permittee subject to the provisions of Subpart GGG may comply with the following exemptions/provisions. 

(40 CFR 60.593)

a. Compressors in hydrogen service are exempt from the requirements of 40 CFR 63.648 (a) and (c) if the 

permittee demonstrates that a compressor is in hydrogen service. (40 CFR 60.593(b)(1))

b. Each compressor is presumed not to be in hydrogen service unless permittee demonstrates that the piece of 

equipment is in hydrogen service. For a piece of equipment to be considered in hydrogen service, it must 

be determined that the percentage hydrogen content can be reasonably expected always to exceed 50 

percent by volume. For purposes of determining the percentage hydrogen content in the process fluid that 

is contained in or contacts a compressor, procedures that conform to the general method described in 

ASTM E260-73, 91 or 96, E168-67, 77, or 92, or E169-63, 77, or 93 shall be used (incorporated by 

reference as specified in 40 CR 60.17). (ASTM E260 is “Standard Practices for Packed Column Gas 

Chromatography”; ASTM E168 is ”Standard Practices for General Techniques of Infrared Quantitative 

Analysis”; E169 is “Standard Practices for General Techniques of Ultraviolet – Visible Quantitative Analysis”; 

(40 CFR 60.593(b)(2)), (40 CFR 63.648(g)(2)(i)(A))
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 80 of 103 

TABLE F-1.11 {FG-PROCUNITS} 

FLEXIBLE GROUPING REQUIREMENTS

c. Permittee may use engineering judgment rather than procedures in paragraph (b) of this condition to 

demonstrate that the percent content exceeds 50 percent by volume, provided the engineering judgment 

demonstrates that the content clearly exceeds 50 percent by volume. When the permittee and the 

Administrator do not agree on whether a piece of equipment is in hydrogen service, the procedures in 

paragraph (b) shall be used to resolve the disagreement. (40 CFR 60.593(b)(3)(i))

d. If the permittee determines that a piece of equipment is in hydrogen service, the determination can be 

revised only by following the procedures in paragraph (b) of this condition. (40 CFR 60.593(b)(3)(ii))

e. Permittee may use the following provision in addition to 40 CFR 60.485(e): Equipment is in light liquid 

service if the percent evaporated is greater than10 percent at 150°C as determined by ASTM Method 

D86-78, 82, 90, 95, or 96 (incorporated by reference as specified in 40 CFR 60.18). (40 CFR 60.593(d))

f. Calculation of percentage leaking equipment components for subpart VV of 40 CFR 60 may be done on a 

process unit basis or a sourcewide basis. Once the permittee has decided, all subsequent calculations shall 

be on the same basis unless a permit change is made. (40 CFR63.648(a)(2))

g. Reciprocating pumps in light liquid service are exempt from 40 CFR 60.482 if recasting the distance piece or 

reciprocating pump replacement is required. (40 CFR 63.648(f))

h. Reciprocating compressors are exempt from seal requirements if recasting the distance piece or compressor 

replacement is required. (40 CFR 63.648(i))

8. Permittee must maintain all records for a minimum of 5 years. (40 CFR 63.648(h)) 

9. Compliance with conditions 1-8 of this section shall be considered compliance with Michigan Air Pollution 

Control Rule R 336.1622 and the equipment leak standards in 40 CFR Part 63, Subpart CC-National Emission 

Standards for Hazardous Air Pollutants from Petroleum Refineries. 

10. The permittee shall comply with all applicable provisions of the following regulations: 

40 CFR 60, Subpart VVa and Subpart GGGa: 

a. Pumps 2,000 ppm 

b. Valves in gas/vapor or light liquid service 500 ppm 

40 CFR 63, Subpart CC, See Appendix 1.7 of RO Permit 199700013c 

Michigan Air Pollution Control Rule R 336.1622 

11. Permittee shall implement a program to monitor at least 90% of the flanges and connectors in gas/vapor 

and light liquid VOC service in the following emission units: EG70-COKER, EG71-H2PLANT, 

EG72-SULRBLOCK2, EG73-SOURWATER2, EG77-DHTHYTREAT, EG22-TANKFARMS, EG76-UTILITIES, 

and EG78-FUELGASRECOVERY. The program shall meet the following requirements. (R 336.1205, 

R 336.1225, R 336.1226(d), R 336.1702(a), R 336.2802, 

40 CFR 52.21)

a. Monitoring shall be conducted on a quarterly basis, using test methods and procedures described in 

Appendix 1.5, Section D of RO Permit 199700013c. 

b. A leak shall be defined as an instrument reading of 500 ppm or greater, as specified in NSPS Subpart VVa. 

c. Flanges and connectors may be excluded from the monitoring program if they are "unsafe to monitor" as 

defined in 40 CFR 60.482-7(g)(1), or "difficult to monitor" as defined in 40 CFR 60.482-7(h)(1). 

d. Permittee shall maintain records utilizing the procedures in Appendix 1.4, Section E, of RO permit 

199700013c. 

12. Permittee shall implement a program to monitor at least 50% of the flanges and connectors in gas/vapor and 

light liquid VOC service in the following emission units: EG04-VACUUM, EG05-CRUDE, EG08-GOHT, 

EG16-NAPHHYTREAT, EG19-KEROHYTREAT, EG14-CCRPLATFORMER, and EG21-CPTREATER. The 

program shall meet the following requirements. (R 336.1205, R 336.1225, R 336.1226(d), R 336.1702(a), 

R 336.2802)

a. Monitoring shall be conducted on a quarterly basis, using test methods and procedures described in 

Appendix 1.5, Section D of RO Permit 199700013c. 

b. A leak shall be defined as an instrument reading of 500 ppm or greater, as specified in NSPS Subpart VVa. 

c. Flanges and connectors may be excluded from the monitoring program if they are "unsafe to monitor" as 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 81 of 103 

TABLE F-1.11 {FG-PROCUNITS} 

FLEXIBLE GROUPING REQUIREMENTS

defined in 40 CFR 60.482-7(g)(1), or "difficult to monitor" as defined in 40 CFR 60.482-7(h)(1). 

d. Permittee shall maintain records utilizing the procedures in Appendix 1.4, Section E, of RO permit 

199700013c. 

* This requirement is state enforceable only. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 82 of 103 

TABLE F-1.14 {FG-CRUDETANKS} 

FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING This flexible group represents a consolidated requirement for external 

floating roof (EFR) tanks that are subject to 40 CFR Part 63, Subpart CC as 

Group 1 Vessels or subject to 40 CFR 60, Subpart Kb. These tanks may 

also be subject to Michigan Air Pollution Control Rule 623 (R 336.1623) 

and/or NSPS Subpart QQQ. This consolidated requirement basically 

adopts NSPS Kb for these EFR tanks. 

Emission Unit/Process Groups EGTANK112, EGTANK113, EGTANK114, EGTANK115, EGTANK129, 

EGTANK130 

I. DESIGN PARAMETERS

A. Pollution Control 

Equipment 

External Floating Roof 

B. Stack/Vent Parameters NA 

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. Temp 

(°F) 

d. Air 

Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. NA NA NA NA NA NA 

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. Crude oil 1. Throughput for FG-CRUDETANKS shall not exceed a monthly average 

of 140,000 barrels per day. (R 336.1225)

B. Pollutants Maximum Emission Limit

1. NA 1. NA 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. NA 

3. Other Monitoring and/or 

Recordkeeping 

1. The permittee shall perform inspections and monitor operating 

information for FGCRUDETANKS in accordance with the federal 

Standards of Performance for New Stationary Sources as specified in 

40 CFR Part 60 Subparts A & Kb. (40 CFR Part 60 Subparts A & Kb)

2. The permittee shall keep record of inspections and operating 

information for FGCRUDETANKS in accordance with the federal 

Standards of Performance for New Stationary Sources as specified in 

40 CFR Part 60 Subparts A & Kb. All records shall be kept on file for a 

period of at least five years and made available to the Department upon 

request. (40 CFR Part 60 Subparts A & Kb)

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

1. Parameter to be Tested/ 

Recorded 

1. The permittee shall comply with all provisions of the Federal Standards 

of Performance for New Stationary Sources as specified in 

40 CFR Part 60 Subparts A & Kb as they apply to FGCRUDETANKS. 

(40 CFR Part 60 Subparts A & Kb)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 83 of 103 

TABLE F-1.14 {FG-CRUDETANKS} 

FLEXIBLE GROUPING REQUIREMENTS

2. Method/Analysis 1. NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

1. The permittee shall keep VOC emission calculations and monthly 

throughput records for FGCRUDETANKS. All records shall be kept on 

file for a period of at least five years and made available to the 

Department upon request. (R 336.1225, 40 CFR 52.21 (a) & (b))

IV. REPORTING 

Reports and Schedules 

V. OPERATIONAL PARAMETERS 

1. The permittee shall maintain each storage tank in FGCRUDETANKS with the following equipment, or a deck 

and seal configuration that results in the same or lower VOC emissions from the tanks: (40 CFR 52.21 (a) & 

(b)) 

floating roof 

welded deck 

mechanical shoe primary seal 

rim-mounted secondary seal 

VI. OTHER REQUIREMENTS 

NA 

* This requirement is state enforceable only. 

TABLE F-1.15 {FG-NAPHTHATANKS} 

FLEXIBLE GROUPING REQUIREMENTS

FLEXIBLE GROUPING This flexible group represents a consolidated requirement for internal and 

external floating roof tanks that are subject to 40 CFR Part 63, Subpart CC 

as Group 1 Vessels or subject to 40 CFR 60, Subpart Kb. These tanks may 

also be subject to Michigan Air Pollution Control Rule 623 (R 336.1623) 

and/or NSPS Subpart QQQ. This consolidated requirement basically 

adopts NSPS Kb for these tanks. 

Emission Unit/Process Groups EGTANK19, EGTANK40, EGTANK45, EGTANK46, EGTANK47, 

EGTANK48, EGTANK49, EGTANK53, EGTANK55, EGTANK57, 

EGTANK58, EGTANK61, EGTANK72, EGTANK101, EGTANK108, 

EGTANK109, EGTANK110, EGTANK116, EGTANK128, EGTANK104, 

EGTANK120, EGTANK79, EGTANK135 

I. DESIGN PARAMETERS 

A. Pollution Control 

Equipment 

Internal Floating Roof 

External Floating Roof 

B. Stack/Vent Parameters NA 

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. Temp 

(°F) 

d. Air 

Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. NA NA NA NA NA NA 

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

NHT charge 

sweet naphtha 

38,400 barrels per day monthly average 

38,400 barrels per day monthly average 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 84 of 103 

TABLE F-1.15 {FG-NAPHTHATANKS} 

FLEXIBLE GROUPING REQUIREMENTS

reformate naphtha 

FCCU naphtha 

alkylate naphtha 

ethanol 

coker naphtha 

gasoline 

24,000 barrels per day monthly average 

30,420 barrels per day monthly average 

8,300 barrels per day monthly average 

17,340 barrels per day monthly average 

36,000 barrels per day monthly average 

74,700 barrels per day monthly average 

(R 336.1225)

B. Pollutants Maximum Emission Limit

1. NA 1. NA 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System 

and Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. NA 

3. Other Monitoring and/or 

Recordkeeping 

1. The permittee shall perform inspections and monitor operating 

information for FGNAPHTHATANKS in accordance with the federal 

Standards of Performance for New Stationary Sources as specified in 

40 CFR Part 60 Subparts A & Kb. (40 CFR Part 60 Subparts A & Kb)

2. The permittee shall keep records of inspections and operating 

information for FGNAPHTHATANKS in accordance with the federal 

Standards of Performance for New Stationary Sources as specified in 

40 CFR Part 60 Subparts A & Kb. All records shall be kept on file for a 

period of at least five years and made available to the Department upon 

request. (40 CFR Part 60 Subparts A & Kb)

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

1. Parameter to be Tested/ 

Recorded 

1. The permittee shall comply with all provisions of the Federal Standards 

of Performance for New Stationary Sources as specified in 40 CFR 

Part 60 Subparts A & Kb as they apply to FGNAPHTHATANKS. 

(R 336.1702, 40 CFR Part 60 Subparts A & Kb)

2. Method/Analysis 1. NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

1. The permittee shall keep VOC emission calculations and monthly 

throughput records for FGNAPHTHATANKS. All records shall be kept 

on file for a period of at least five years and made available to the 

Department upon request. (R 336.1225, R 336.1702)

IV. REPORTING 

Reports and Schedules 

V. OPERATIONAL PARAMETERS 

1. The permittee shall equip and maintain EGTANK108, EGTANK109, EGTANK110, and EGTANK128 with 

slotted guidepole controls. (R 336.1225, R 336.1702)

2. The permittee shall maintain each storage tank in FGNAPHTHATANKS with the following deck and seal 

configuration, or a deck and seal configuration that results in the same or lower VOC emissions from the 

tanks: (R 336.1225, R 336.1702) 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 85 of 103 

TABLE F-1.15 {FG-NAPHTHATANKS} 

FLEXIBLE GROUPING REQUIREMENTS

 Equipment Type Deck Primary Seal Secondary Seal 

 EGTANK19 Internal floating roof Welded Mechanical Shoe None 

 EGTANK40 Internal floating roof Welded Mechanical Shoe None 

 EGTANK45 Internal floating roof Bolted Vapor Mounted Rim - Mounted 

 EGTANK46 Internal floating roof Bolted Vapor Mounted Rim - Mounted 

 EGTANK47 Internal floating roof Bolted Vapor Mounted Rim - Mounted 

 EGTANK48 Internal floating roof Bolted Vapor Mounted Rim - Mounted 

 EGTANK49 Internal floating roof Welded Mechanical Shoe None 

 EGTANK53 Internal floating roof Welded Mechanical Shoe None 

 EGTANK55 Internal floating roof Welded Mechanical Shoe None 

 EGTANK57 Internal floating roof Welded Mechanical Shoe None 

 EGTANK58 Internal floating roof Welded Mechanical Shoe None 

 EGTANK61 Internal floating roof Welded Mechanical Shoe None 

 EGTANK72 Internal floating roof Bolted Vapor Mounted Rim - Mounted 

 EGTANK101 Internal floating roof Welded Mechanical Shoe None 

 EGTANK108 External floating roof Welded Mechanical Shoe Rim - Mounted 

 EGTANK109 External floating roof Welded Mechanical Shoe Rim - Mounted 

 EGTANK110 External floating roof Welded Mechanical Shoe Rim - Mounted 

 EGTANK116 Internal floating roof Welded Liquid Mounted None 

 EGTANK128 External floating roof Welded Mechanical Shoe Rim - Mounted 

 EGTANK79 Internal floating roof Welded Mechanical Shoe None 

 EGTANK104 Internal floating roof Welded Mechanical Shoe None 

 EGTANK120 Internal floating roof Welded Mechanical Shoe None 

 EGTANK135 Internal floating roof Welded Mechanical Shoe None 

VI. OTHER REQUIREMENTS 

NA 

* This requirement is state enforceable only. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 86 of 103 

FG-COOLTOWERS 

FLEXIBLE GROUP CONDITIONS

DESCRIPTION

These requirements apply to the cooling towers that are new or being modified as part of the heavy oil upgrade 

project (HOUP): D, E, G, H, and the new cooling tower. These requirements also apply to existing cooling 

towers that are not being modified as part of the HOUP: A, C, and F. 

Emission Units: EGCOOLTOWERA, EGCOOLTOWERC, EGCOOLTOWERD, EGCOOLTOWERE, 

EGCOOLTOWERF, EGCOOLTOWERG, EGCOOLTOWERH, and EGCOOLTOWERNEW 

Flexible Group ID: FGDHOUPANNUAL 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ Operating 

Scenario 

Equipment Monitoring/ 

Testing Method

Underlying 

Applicable 

Requirements

1. NA 

II. MATERIAL LIMIT(S)

Material Limit Time Period/ Operating 

Scenario 

Equipment Monitoring/ 

Testing Method

Underlying 

Applicable 

Requirements

1. NA 

III. PROCESS/OPERATIONAL RESTRICTION(S) 

1. Within 180 days after start-up of EG70-COKER, the permittee shall submit, to the AQD District Supervisor, 

an inspection and maintenance program for each cooling tower in FG-COOLTOWERS. The permittee shall 

comply with the submitted program until the AQD District Supervisor approves the program or approves an 

amended program. Thereafter, the permittee shall comply with the approved program. At any time, the 

permittee may submit a modified program to the AQD District Supervisor for review and approval. 2

(R 336.1205, R 336.2802, 40 CFR 52.21)

2. Within 180 days after start-up of EG70-COKER, the permittee shall submit, to the AQD District Supervisor, a 

program for monitoring each cooling tower in FG-COOLTOWERS for leaks of process fluids into the cooling 

water. The submitted program shall include, as a minimum, all of the following: 

a. A description of the parameter or condition to be monitored and an explanation of how the selected 

parameter or condition will reliably indicate the presence of a leak. 

b. The parameter level(s) or conditions(s) that shall constitute a leak. This shall be documented by 

data or calculations showing that the selected levels or conditions will reliably identify leaks. The 

monitoring must be sufficiently sensitive to determine the range of parameter levels or conditions 

when the system is not leaking. When the selected parameter level or condition is outside that 

range, a leak is indicated. 

c. The monitoring frequency which shall be no less frequent than monthly for the first 6 months and 

quarterly thereafter to detect leaks. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 87 of 103 

d. The records that will be maintained to document compliance with the requirements of this section. 

e. If a leak is detected, the permittee shall comply with the following requirements:

i. The leak shall be repaired as soon as practical but not later than 45 calendar days after the 

permittee receives results of monitoring tests indicating a leak. The leak shall be repaired unless 

the permittee demonstrates that the results are due to a condition other than a leak. Once the 

leak has been repaired, the permittee shall confirm that the heat exchange system has been 

repaired within seven calendar days of the repair or startup, whichever is later.

ii. Delay of repair of heat exchange systems for which leaks have been detected is allowed if the 

equipment is isolated from the process. Delay of repair is also allowed if repair is technically 

infeasible without a shutdown and any one of the following conditions are met. All of the 

following time periods shall be determined from the date when the permittee determines that 

delay of repair is necessary. 

1. If a shutdown is expected within the next 2 months, a special shutdown before that planned 

shutdown is not required. Documentation of a decision to delay repair shall state the 

reasons repair was delayed and shall specify a schedule for completing the repair as soon 

as practical. 

2. If a shutdown for repair would cause greater emissions than the potential emissions from 

delaying repair, the permittee may delay repair until the next shutdown of the process 

equipment associated with the leaking heat exchanger. The permittee shall document the 

basis for the determination that a shutdown for repair would cause greater emissions than 

the emissions likely to result from delaying repair. 

3. If a shutdown is not expected within the next 2 months, and the permittee delays repair 

because the necessary parts or personnel are not available, the permitee may delay repair 

up to a maximum of 120 calendar days. The permittee shall demonstrate that the necessary 

parts or personnel were not available. 

The permittee shall comply with the submitted program until the AQD District Supervisor approves the 

program or approves an amended program. Thereafter, the permittee shall comply with the approved 

program. At any time, the permittee may submit a modified program to the AQD District Supervisor for 

review and approval. 2

 (R 336.1205, R 336.2802, 40 CFR 52.21)

IV. DESIGN/EQUIPMENT PARAMETER(S)

1. The permittee shall equip and maintain each cooling tower in FG-COOLTOWERS with drift eliminators with 

a vendor-certified maximum drift rate of 0.005 percent or less. (R 336.1205, R 336.2802, 40 CFR 52.21)

 

V. TESTING/SAMPLING

Records 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 start-up of EG70-COKER, and every 

seven years thereafter, the permittee shall determine drift loss from EGCOOLTOWERA, 

EGCOOLTOWERC, EGCOOLTOWERD, EGCOOLTOWERE, EGCOOLTOWERF, EGCOOLTOWERG, 

and EGCOOLTOWERH by testing, at owner's expense, in accordance with Department requirements. The 

permittee shall use the 1994 version of the Cooling Technology Institute's Acceptable Test Code (ATC) 140, 

unless the AQD approves use of an alternate method. No less than 60 days prior to testing, the permittee 

shall submit a complete test plan to the AQD. For tests conducted prior to start-up of EG70-COKER, the 

test plan shall demonstrate that test conditions will be representative of post-startup conditions. The AQD 

must approve the final plan prior to testing. Determination of drift loss includes the submittal of a complete 

report of the test results to the AQD within 60 days following the last date of the test. 2

 (R 336.1205, 

R 336.2802, 40 CFR 52.21)

2. Within 180 days after start-up of EG70-COKER, and every seven years thereafter, the permittee shall 

determine drift loss from EGCOOLTOWERNEW by testing, at owner's expense, in accordance with 

Department requirements. The permittee shall use the 1994 version of the Cooling Technology Institute's 

Acceptable Test Code (ATC) 140, unless the AQD approves use of an alternate method. No less than 60 

days prior to testing, the permittee shall submit a complete test plan to the AQD. The AQD must approve 

the final plan prior to testing. Determination of drift loss includes the submittal of a complete report of the 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 88 of 103 

test results to the AQD within 60 days following the last date of the test. 2 (R 336.1205, R 336.2802, 40 CFR 

52.21)

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. For each cooling tower in FG-COOLTOWERS, the permittee shall maintain a record, for the life of the 

cooling tower, of the vendor’s certification required in SC IV.1. 2 (R 336.1205, R 336.2802, 40 CFR 52.21)

2. The permittee shall monitor the following for each cooling tower in FG-COOLTOWERS. 2 (R 336.1205, 

R 336.2802, 40 CFR 52.21)

a. On a weekly basis, parameters needed to determine the total dissolved solids content of the 

circulating water. 

b. On a monthly basis, parameters needed to determine the water recirculation rate. 

3. The permittee shall calculate the PM and PM-10 emission rates from each cooling tower in 

FG-COOLTOWERS monthly, for the preceding 12-month rolling time period, using a method acceptable to 

the AQD District Supervisor. 2

 (R 336.1205, R 336.2802, 40 CFR 52.21) 

4. The permittee shall keep, for each cooling tower in FG-COOLTOWERS, a record of the date the two most 

recent drift loss determinations were conducted. This record shall be maintained for more than five years if 

necessary. (R 336.1205, R 336.2802, 40 CFR 52.21)

VII. REPORTING

1. If the permittee invokes the delay of repair provisions for a heat exchange system, the following information 

shall be submitted in the next semi-annual periodic report required by 40 CFR 63.152(c). If the leak remains 

unrepaired, the information shall also be submitted in each subsequent periodic report, until repair of the 

leak is reported. (R 336.1205, R 336.2802, 40 CFR 52.21)

a. The permittee shall report the presence of the leak and the date that the leak was detected. 

b. The permittee shall report whether or not the leak has been repaired. 

c. The permittee shall report the reason(s) for delay of repair. If delay of repair is invoked because a 

shutdown for repair would cause greater emissions than the potential emissions from delaying 

repair, documentation of emissions estimates must also be submitted. 

d. If the leak remains unrepaired, the permittee shall report the expected date of repair. 

e. If the leak is repaired, the permittee shall report the date the leak was successfully repaired. 

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards 

to the ambient air unless otherwise noted: 

Stack & Vent ID Maximum 

Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above Ground 

(feet) 

Underlying Applicable 

Requirements 

1. NA 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 89 of 103 

IX. OTHER REQUIREMENT(S)

1. NA 

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 90 of 103 

FG-FirePumps 

EMISSION UNIT CONDITIONS

DESCRIPTION

Two diesel-driven fire water booster pumps 

Emission Units: EG24P1, EG24P2

Flexible Group ID: FGDHOUPANNUAL 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ Operating 

Scenario Equipment Monitoring/ Testing Method

Underlying 

Applicable 

Requirements

1. NA 

II. MATERIAL LIMIT(S)

Material Limit Time Period/ Operating 

Scenario 

Equipment Monitoring/ 

Testing Method

Underlying 

Applicable 

Requirements

1. NA 

III. PROCESS/OPERATIONAL RESTRICTION(S)

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

Sources as specified in 40 CFR Part 60 Subparts A and IIII, as they apply to each engine in 

FG-FirePumps. 2

 (40 CFR Part 60 Subparts A & IIII)

2. The permittee shall maintain each engine in FG-FirePumps according to manufacturer’s recommendations, 

to ensure that the emissions from each engine continue to meet the certified values in SC IV.1. 2

(R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR 60.4211)

IV. DESIGN/EQUIPMENT PARAMETER(S)

1. The permittee shall only install engines in FG-FirePumps that have been certified by the manufacturer, 

using the procedures of 40 CFR Part 89 Subpart E, to meet or exceed the emission standards in 

40 CFR 89.112 listed below, as in effect for model year 2007. 

a. PM10: 0.20 gram per kilowatt-hour 2 (R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR 60.4205)

b. CO: 3.5 grams per kilowatt-hour 2 (R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR 60.4205)

c. NOX and non-methane hydrocarbons: 4.0 grams per kilowatt-hour 2 (R 336.1205, R 336.2802, 

40 CFR 52.21, 40 CFR 60.4205)

2. The permittee shall equip and maintain each engine in FG-FirePumps with a non-resettable hour meter. 2

(R 336.1205, R 336.2802, 40 CFR 52.21, 40 CFR 60.4209)
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 91 of 103 

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

1. NA 

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall monitor emissions and operating information for each engine in FG-FirePumps in 

accordance with the federal Standards of Performance for New Stationary Sources as specified in 

40 CFR Part 60 Subparts A and IIII. 2 (R 336.1205, R 336.1225, R 336.1702, R 336.1901, 40 CFR Part 

60 Subparts A & IIII)

2. For each engine in FG-FirePumps, the permittee shall maintain a record, for the life of the engine, of the 

manufacturer’s certification required in SC IV.1. 2 (R 336.1205, R 336.2802, 40 CFR 52.21) 

3. The permittee shall keep records of emissions and operating information to comply with the federal 

Standards of Performance for New Stationary Sources as specified in 40 CFR Part 60 Subparts A and IIII. 2

(40 CFR Part 60 Subparts A & IIII, R 336.1205)

VII. REPORTING

1. The permittee shall provide written notification of construction and operation to comply with the federal 

Standards of Performance for New Stationary Sources, 40 CFR 60.7. The permittee shall submit this 

notification to the AQD District Supervisor within the time frames specified in 40 CFR 60.7. 2

 (40 CFR 60.7)

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards 

to the ambient air unless otherwise noted: 

Stack & Vent ID 

Maximum 

Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above Ground 

(feet) 

Underlying Applicable 

Requirements 

1. SVEngine1 6 2 10 2 R 336.1225 

2. SVEngine2 6 2 10 2 R 336.1225 

IX. OTHER REQUIREMENT(S)

1. NA 

Footnotes:

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 92 of 103 

FGDHOUPANNUAL 

FLEXIBLE GROUP CONDITIONS

DESCRIPTION

These emission units and flexible groups used the Actual-to-Potential test for PSD applicability. The emission 

limits in this group serve to limit the Potential to Emit of covered equipment. 

Emission Units/Flexible Groups: EG11-FCCU, EG14-CCRPLCATREG, EG21-S2OFFGAS, 

FG29-IGF, EG42-43SULRECOV, EG70-COKER, EG-COKERFLARE, 

EG72-SULRBLOCK2, FG-HEATERS, FG-PROCUNITS, FGCOOLTOWERS, 

FGFIREPUMPS, FGHOUPTANKS, EG71-H2STEAMSYS 

POLLUTION CONTROL EQUIPMENT

I. EMISSION LIMIT(S)

Pollutant Limit Time Period/ Operating 

Scenario Equipment Monitoring/ Testing Method

Underlying 

Applicable 

Requirements

1. PM 122.4 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

2. PM10 206.8 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

3. NOX 642 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

4. SO2 373 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

5. CO 251.5 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

6. VOC 465 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

7. H2SO4 24.25 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

8. H2S 8.57 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

9. Total reduced 

sulfur (TRS) 9.86 tpy Rolling 12-month time 

period * FGDHOUPANNUAL SC VI.1 

R 336.1205, 

R 336.2802, 

40 CFR 52.21 

* Rolling 12-month time period as determined at the end of each calendar month. 

Limits on the units and processes put in place in this permit for the operation of the facility will not cause a 

combination of increases or decreases that would violate the netting conclusion. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 93 of 103 

II. MATERIAL LIMIT(S)

Material Limit Time Period/ Operating 

Scenario Equipment Monitoring/ Testing Method

Underlying 

Applicable 

Requirements

1. NA NA NA NA NA NA 

III. PROCESS/OPERATIONAL RESTRICTION(S)

1. NA 

IV. DESIGN/EQUIPMENT PARAMETER(S)

1. NA 

V. TESTING/SAMPLING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. NA 

VI. MONITORING/RECORDKEEPING

Records shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii))

1. The permittee shall calculate the PM, PM10, NOX, SO2, CO, VOC, H2SO4, H2S, and TRS emission rates 

from FGDHOUPANNUAL monthly, for the preceding 12-month rolling time period, using a method 

acceptable to the AQD District Supervisor, considering the following. (R 336.1205, R 336.2802, 

40 CFR 52.21, 40 CFR Part 51 Appendix S)

a. For storage tanks, the permittee may maintain VOC emission calculations and monthly throughput 

records in lieu of performing monthly VOC calculations. 

b. CO emissions during periods of startup, shutdown, and malfunction for each emission unit in 

FG-HEATERS without a CO CEMS shall be calculated at 400 ppmv at 3 percent excess oxygen. For 

each emission unit in FG-HEATERS without a CO CEMS, for which the permittee has collected CO 

emissions data during startup, shutdown and malfunction periods from representative process heaters, 

the permittee may, after submitting a demonstration to the AQD District Supervisor that the emission 

data is representative, use the representative process heater data for calculating the CO emission rate 

from that emission unit. 

c. VOC, H2S, and TRS emissions from cooling towers shall be calculated for periods of leaks of process 

fluids into the cooling water. 

d. H2S and TRS emissions from EG72-SULRBLOCK2 shall include the emissions resulting from nonoperation of the sulfur pit degassing system. 

e. Fugitive emissions from all components that may leak, such as those addressed in leak detection and 

repair programs. 

f. H2S and TRS emissions from sulfur recovery and loading operations. 

g. All emission calculations shall include emissions from startups, shutdowns, and malfunctions. 

h. The data obtained from the sulfur content sampling program for various sulfur laden products and 

process streams. 

i. Emissions resulting from the steam to hydrocarbon ration not being maintained at the appropriate level 

for each flare. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 94 of 103 

VII. REPORTING

1. Within 30 days after completion of the installation, construction, reconstruction, relocation, or modification 

authorized by this Permit to Install, the permittee or the authorized agent pursuant to Rule 204, shall notify 

the AQD District Supervisor, in writing, of the date of completion of the activity. Completion of the 

installation, construction, reconstruction, relocation, or modification is considered to occur not later than 180 

days after the start-up of EG-70COKER. (R 336.1216(1), R 336.1201(7)(a))

VIII. STACK/VENT RESTRICTION(S)

The exhaust gases from the stacks listed in the table below shall be discharged unobstructed vertically upwards 

to the ambient air unless otherwise noted: 

Stack & Vent ID 

Maximum 

Exhaust 

Dimensions 

(inches) 

Minimum Height 

Above Ground 

(feet) 

Underlying Applicable Requirements 

 

IX. OTHER REQUIREMENT(S)

1. NA 

Footnotes: 

1

This condition is state only enforceable and was established pursuant to Rule 201(1)(b). 2

This condition is federally enforceable and was established pursuant to Rule 201(1)(a). 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 95 of 103 

TABLE B-1 

SOURCE-WIDE REQUIREMENTS

I. DESIGN PARAMETERS 

A. Pollution Control 

Equipment

NA 

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

otherwise noted.

Stack/Vent ID a. Minimum 

Height 

(feet) 

b. Maximum 

Exhaust 

Dimension 

(inches) 

c. Temp 

(°F) 

d. 

Air Flow 

Rate 

(acfm) 

Applicable 

Requirement 

1. NA NA NA NA NA NA 

C. Other Design Parameters 

1. NA 

II. MATERIAL USAGE/EMISSION LIMITS 

A. Material Maximum Usage Rate

1. NA 1. NA 

B. Pollutants Maximum Emission Limit

1. NA 1. NA 

III. COMPLIANCE EVALUATION 

Records of all of the following shall be maintained on file for a period of five years. (R 336.1213(3)(b)(ii)) 

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

1. Continuous Emission 

Monitoring (CEM) System and 

Recordkeeping 

1. NA 

2. Process Monitoring System 

and Recordkeeping 

1. NA 

3. Other Monitoring and/or 

Recordkeeping 

1. The permittee shall conduct an enhanced air monitoring program at the facility 

to address citizen concerns. The permittee shall monitor concentrations of 

carbon monoxide, PM-10, sulfur dioxide, volatile organic compounds (TO-15 

canister method – subset to be determined and approved in the enhanced air 

monitoring program), and total reduced sulfur at no less than four sites in a 

manner and with instrumentation approved by the AQD Air Monitoring Unit. 

No less than 180 days after beginning construction pursuant to Permit to 

Install No. 63-08, the permittee shall submit a monitoring plan for the 

enhanced air monitoring program to the AQD Air Monitoring Unit. Following 

approval of a plan, the permittee shall begin monitoring all required pollutants, 

according to the approved plan, no later than the date of startup of the heavy 

oil upgrade project. Monitoring shall continue for at least ten years. * 

(R 336.1901)

2. The permittee shall keep records of all air monitoring data collected in the air 

monitoring program. The permittee shall submit all records to the AQD Air 

Monitoring Unit in an acceptable format within 45 days following the end of the 

quarter in which the data were collected. * (R 336.1901)

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

1. Parameter to be Tested/ 

Recorded 

1. The permittee shall keep monthly and 12-month rolling time period records of 

the hours of operation of each non-continuous drain. (R 336.1205, 

R 336.2802, 40 CFR 52.21)

2. Method/Analysis 1. NA 

3. Frequency and Schedule of 

Testing/Recordkeeping 

1. NA 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 96 of 103 

TABLE B-1 

SOURCE-WIDE REQUIREMENTS

IV. REPORTING 

Reports and Schedules 1. The installation and modification of all emissions units designated as part of 

the DHOUP, and all projects resulting in emissions decreases necessary to 

ensure that this project is minor under the New Source Review regulations, 

shall be completed no later than 180 days from the start-up of EG-70COKER. 

This shall be considered the completion of DHOUP construction, and the end 

of the contemporaneous period for this project. (R 336.1205, R 336.2802, 

40 CFR 52.21, 40 CFR Part 51 Appendix S)

V. OPERATIONAL PARAMETERS 

1. The permittee shall not operate any non-continuous drain for more than 100 hours per 12-month rolling time 

period, as determined at the end of each calendar month. (R 336.1205, R 336.2802, 40 CFR 52.21)

VI. OTHER REQUIREMENTS 

1. The conditions contained in this RO Permit for which a Consent Decree is the only identified applicable 

requirement shall be considered null and void upon the effective date of termination of the Consent Decree. The 

effective date of termination is defined for the purposes of this condition as the date upon which the Stipulation 

and Order for Termination is signed by a Circuit Court Judge. (R 336.1213(3))

2. Permittee shall comply with the requirements of the Consent Decree No. 01-40119 between United States of 

America (Plaintiff) and County of Wayne, Michigan, State of Louisiana, State of Minnesota (Plaintiff-Interveners) v. 

Marathon Ashland Petroleum, LLC (Defendant), and revisions thereto. (R 336.1213(3))

3. Each Responsible Official shall certify annually, using the format in Appendix 8 of RO Permit 199700013c, that the 

stationary source is in compliance with all stationary source-wide requirements. This certification shall be included 

as part of the annual certification of compliance as required in General Conditions 28 and 29 in Part A of the RO 

Permit. (R 336.1213(4)(c))

4. Permittee shall comply with the Fugitive Dust Control Program dated December 27, 1996 and revisions thereto. 

(R 336.1213(3))

5. Permittee shall comply with all applicable requirements of 40 CFR Part 63, National Emission Standards for 

Hazardous Air Pollutants for Source Categories, Subpart A-General Provisions. (40 CFR 63, Subpart A)

6. Permittee shall comply with all applicable requirements of 40 CFR Part 63, Subpart CC-National Emission 

Standards for Hazardous Air Pollutants from Petroleum Refineries. 

(40 CFR 63, Subpart CC)

7. Permittee shall comply with all applicable requirements of 40 CFR Part 61, National Emission Standards for 

Hazardous Air Pollutants, Subpart A-General Provisions. 

(40 CFR 61, Subpart A)

8. Permittee shall comply with all applicable requirements of 40 CFR Part 61, National Emission Standards 

for Hazardous Air Pollutants, Subpart M-National Emission Standard for Asbestos. 

(40 CFR 61, Subpart M)

9. Permittee shall comply with all applicable requirements of 40 CFR Part 61, National Emission Standards for 

Hazardous Air Pollutants, Subpart FF-National Emission Standard for Benzene Waste Operations. (Paragraph 

18 and 19 of Consent Decree No. 01-40119), (40 CFR 61, Subpart FF), (Consent Decree No. 01-40119)

10. Permittee shall comply with all applicable requirements of Natural Resources and Environmental Protection Act, 

Act 451 of 1994, Subpart 324.5524. (Act 451, Part 55, 324.5524)

11. Permittee shall not cause or allow the emission of any volatile organic compound from any process unit 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 97 of 103 

TABLE B-1 

SOURCE-WIDE REQUIREMENTS

turnaround at the facility, unless such emission is controlled by one of the following methods: 

a. Capture and disposal in a fuel gas system. 

b. Combustion in a smokeless flare. 

c. Any method approved by the Division that recovers no less than 90%, by weight, of the uncontrolled volatile 

organic compounds that would otherwise be emitted into the atmosphere. 

(R 336.1616(1)(a, b & c)) 

12. Permittee shall comply with the provisions of R336.1616 until the pressure of all vessels in the system is less than 

5 psi gauge. (R 336.1616(2))

13. Except as provided for in condition 14, permittee shall notify the Division not less than 30 days before any process 

unit turnaround subject to the provisions of R336.1616. (R 336.1616(3))

14. In the case of process unit turnarounds caused by circumstances beyond the control of the permittee, the Division 

shall be notified as soon as reasonably possible. (R 336.1616(4)), (R 336.1213)(3) 

Note: Process Unit Turnarounds, for this ROP, are defined as “planned and scheduled shutdowns in which the entire 

process unit is shutdown and deinventoried for major maintenance activities”. 

15. Permittee shall comply with all applicable requirements of 40 CFR Part 63, Subpart UUU-National Emission 

Standards for Hazardous Air Pollutants for Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming 

Units, and Sulfur Recovery Units. (40 CFR 63, Subpart UUU)

16. The provisions of Rule 406(2) are applicable requirements for the permittee. (R 336.1406(2))

17. The permittee shall conduct a program of enhanced sweeping of paved roads in the vicinity of the Detroit refinery. 

No less than 180 days after beginning construction pursuant to Permit to Install No. 63-08, the permittee shall 

submit a plan for the enhanced street sweeping program to the AQD District Supervisor as a proposed revision to 

the Fugitive Dust Control Program required in Table B-1 of RO Permit 199700013c. The plan shall include the 

location, frequency, and estimated PM and PM-10 benefits of the program. The permittee shall begin enhanced 

sweeping, according to the plan, no later than the date of startup of the heavy oil upgrade project. At any time, the 

permittee may submit a modified plan to the AQD District Supervisor. (R 336.1901)

18. The permittee shall notify the Department if a change in land use occurs for property classified as industrial or as a 

public roadway, where this classification was relied upon to demonstrate compliance with Rule 225(1) for the 

heavy oil upgrade project. The permittee shall submit the notification to the AQD District Supervisor within 30 

days of the actual land use change. Within 60 days of the land use change, the permittee shall submit to the AQD 

District Supervisor a plan for complying with the requirements of Rule 225(1). The plan shall require compliance 

with Rule 225(1) no later than one year after the due date of the plan submittal. (R 336.1225(4))

19. The permittee shall comply with all provisions of the federal Standards of Performance for New Stationary Sources 

as specified in 40 CFR Part 60 Subparts A and Ja, as they apply to the facility. (40 CFR Part 60 Subparts A & Ja) 

20. No later than startup of EG-70COKER, as defined in R 336.1119(p), the permittee shall permanently cease 

operating DHT compressors 1, 2, and 3, FCCU compressor 6, EG17-BTPLCHARHTR, EG17-BTPLINTRHTR, 

EG17-BTPLATFORMR, and EG07-DHTCHARHTR, and shall control emissions from 29 pressure relief valves to 

atmosphere in the LPG Tank Farm. (R 336.1205, R 336.2802, 40 CFR 52.21)

21. Within 180 days after commencement of trial operation, the permittee shall submit to the AQD a sulfur content 

sampling plan for sulfur-laden process streams and products for the process units and products listed below. The 

plan shall consider catalyst life (“start of run” and “end of run” conditions) for the affected process units and 

products. The purpose of this sampling plan is to verify the sulfur distributions in the process simulations relied on 

in the permit application. (R 336.1205, R 336.1225, R 336.2802, 40 CFR 52.21)

• Crude unit 

• Vacuum unit 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 98 of 103 

TABLE B-1 

SOURCE-WIDE REQUIREMENTS

• Coker and coker gas plant 

• Naphtha hydrotreater 

• Distillate hydrotreater 

• Kerosene hydrotreater 

• Gasoil hydrotreater 

• Sulfur recovery units, including sulfur storage tanks and rail car loading operations 

• Asphalt produced 

22. Within 180 days after commencement of trial operation, the permittee shall submit to the AQD a sulfur content 

sampling plan for sulfur-laden process streams, products, sour water streams, and sulfur laden gaseous streams 

for the process units and products listed below. The plan shall consider catalyst life (“start of run” and “end of run” 

conditions) for the affected process units and products. Sampling under the plan must occur at least annually. 

The purpose of this sampling plan is to verify the sulfur distributions in the process simulations relied on in the 

permit application.3

 (R 336.1201(3))

• Crude unit 

• Vacuum unit 

• Coker and coker gas plant 

• Naphtha hydrotreater 

• Distillate hydrotreater 

• Kerosene hydrotreater 

• Gasoil hydrotreater 

• Sulfur recovery units, including tail gas units, sulfur storage tanks and rail car loading operations 

• Asphalt produced 

3

This condition is included at the request of the permittee.
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 99 of 103 

APPENDIX A 

NOX, SO2, O2 and CO Monitoring 

Continuous Emission Monitoring System (CEMS) Requirements 

1. Within 30 calendar days after commencement of trial operation, the permittee shall submit two copies of a 

Monitoring Plan to the AQD, for review and approval. The Monitoring Plan shall include drawings or 

specifications showing proposed locations and descriptions of the required CEMS. 

2. Within 150 calendar days after commencement of trial operation, the permittee shall submit two copies of 

a complete test plan for the CEMS to the AQD for approval. 

3. Within 180 calendar days after commencement of trial operation, the permittee shall complete the 

installation and testing of the CEMS. 

4. Within 60 days of completion of testing, the permittee shall submit to the AQD two copies of the final 

report demonstrating the CEMS complies with the requirements of the corresponding Performance 

Specifications (PS) in the following table. 

Pollutant Applicable PS 

NOX 2 

SO2 2 

O2 3 

CO 4 

5. The span value shall be 2.0 times the lowest emission standard or as specified in the federal regulations. 

6. The CEMS shall be installed, calibrated, maintained, and operated in accordance with the procedures set 

forth in 40 CFR 60.13 and PS 2 of Appendix B to 40 CFR Part 60. 

7. Each calendar quarter, the permittee shall perform the Quality Assurance Procedures of the CEMS set 

forth in Appendix F of 40 CFR Part 60. Within 30 days following the end of each calendar quarter, the 

permittee shall submit the results to the AQD in the format of the data assessment report (Figure 1, 

Appendix F). 

8. In accordance with 40 CFR 60.7(c) and (d), the permittee shall submit two copies of an excess emission 

report (EER) and summary report in an acceptable format to the AQD, within 30 days following the end of 

each calendar quarter. The Summary Report shall follow the format of Figure 1 in 40 CFR 60.7(d). The 

EER shall include the following information: 

a) A report of each exceedance above the limits specified in the conditions of this permit. This includes 

the date, time, magnitude, cause and corrective actions of all occurrences during the reporting period. 

b) A report of all periods of CEMS downtime and corrective action. 

c) A report of the total operating time of the emission unit during the reporting period. 

d) A report of any periods that the CEMS exceeds the instrument range. 

e) If no exceedances or CEMS downtime occurred during the reporting period, the permittee shall report 

that fact. 

The permittee shall keep all monitoring data on file for a period of at least five years and make them available to 

the AQD upon request. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 100 of 103 

APPENDIX B 

Recordkeeping Provisions – Actual to Projected-Actual Applicability Test 

All information in this Appendix shall be maintained pursuant to R 336.2818 and 40 CFR 52.21(r)(6)(i) for 10 

years after the emission units identified in Table C resume normal operations, and shall be made available to 

the Department upon request. 

A. Project Description: 

 The Detroit Heavy Oil Upgrade Project (Detroit HOUP) will expand the capacity of the Detroit Refinery and 

install new process units and support equipment to allow the facility to refine a new source of crude oil. The 

proposed changes include the installation of a new delayed coker and coker gas plant, a new hydrogen 

plant and a second sulfur recovery unit, a replacement distillate hydrotreater, new storage tanks, a new flare 

system, a new cooling tower and changes to many of the existing process units at the refinery. 

 These changes are described in Permit to Install application number 63-08. 

B. Applicability Test Description: 

 For all new emission units, the increase in actual emissions from the Detroit HOUP is based on the actualto-potential test. For most existing emission units included in the Detroit HOUP, the potential to emit is 

based on requested maximum allowable emission rates as opposed to the maximum design capacity of the 

units, and the actual emissions increase due to the Detroit HOUP for those emission units was also based 

on the actual-to-potential calculation. The only exception to the use of the actual-to-potential test is for the 

existing flare systems, included in 

FGREFINEFLARES in the permit. 

C. Emission Units Using Actual-to-Projected Actual Test: 

 Emissions (tpy) 

Emission Unit/Flexible 

Group ID Pollutant Baseline Actual 

Projected 

Actual Excluded Reason for Exclusion 

FGREFINEFLARES NOx 3.1 2.9 - 

 SO2 23.2 3.3 - 

 VOC 13.5 6.9 - 

 CO 13.5 15.6 - 

 PM 0.08 0.08 - 

 PM10 0.31 0.31 - 

 H2SO4 1.87 0.26 - 

 H2S 3.1 0.03 

 TRS 3.4 0.03 

D. Emission Units Using Potential to Emit: 

 Emission estimates for the Detroit HOUP have used Potential to Emit for the following emission units/flexible 

groups: 

 EG11-FCCU EG14-CCRPLCATREGEN EG21-S2OFFGAS 

 FG29-IGF EG42-43SULRECOV EG70-COKER 

 EG72-SULRBLOCK2 EG-COKERFLARE FG-HEATERS 

 FG-PROCUNITS FGCOOLTOWERS FGFIREPUMPS 

 FGHOUPTANKS 

The flexible group FGDHOUPANNUAL has been created to account for the emissions from this group of 

equipment. 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 101 of 103 

E. Netting Calculations and Discussion: 

 Emissions changes from the Detroit HOUP are summarized below. The Detroit HOUP emissions include 

the projected actual emissions from the existing refinery flares. In cases where the project emissions 

exceed their regulatory significance threshold, a netting analysis was conducted whereby the sum of the 

contemporaneous emission increases and decreases were combined with the Detroit HOUP emissions to 

determine the net emissions impact. Emission decreases associated with a federal Consent Decree are not 

creditable in determining the net emissions impact and have been excluded from the calculation. 

Detroit HOUP Net Emissions Changes (tons per year) 

 VOC NOx SO2 PM PM10 CO H2SO4 H2S TRS 

Detroit HOUP -36 198 210 33 -13 85 13 3 3 

Contemporaneous Increases 54 91 8 10 18 0 1 - - 

Contemporaneous Decreases 20 290 219 43 18 0 18 - - 

Total -2 -1 -1 0 -13 85 -4 3 3 

Significance Level 40 40 40 25 15 100 7 10 10 

F. Pre-Construction Projection of Emissions: 

 The following table shows the pre-construction estimate of emissions from the Detroit HOUP. The table 

identifies the projected annual emission rate for emission units using the actual-to-projected actual test, and 

the potential emission rate for emission units using the actual-to-potential test. 

Detroit HOUP Pre-Construction Emissions Projection (tons per year) 

 VOC NOx SO2 PM PM10 CO H2SO4 H2S TRS 

Projected emissions for units using 

actual-to-projected actual test 

(FGREFINEFLARES) 

7 3 3 0.1 0.3 16 0.26 0.03 0.03 

Potential to emit for units using 

actual-to-potential test 

(FGDHOUPANNUAL) 

465 642 373 122.4 206.8 251.5 24.25 8.57 9.86 

Detroit HOUP Total Projected 

Emissions 472 645 376 122.5 207.1 270 24.51 8.60 9.89 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 102 of 103 

G. Recordkeeping: 

The annual records shall contain the following information and be presented in a format acceptable to the 

AQD Permit Section Supervisor: 

Pre-construction projection of actual emissions for emission units using the actual-to-projected actual 

test (FGREFINEFLARES). 

Calendar year actual emissions for emission units using the actual-to-projected actual test 

(FGREFINEFLARES). 

Potential-to-emit for emission units using the actual-to-potential test (FGDHOUPANNUAL). 

Detroit HOUP Annual Emissions Record (tons per year) 

 VOC NOx SO2 PM PM10 CO H2SO4 H2S TRS 

Projected emissions for 

units using actual-toprojected actual test 

(FGREFINEFLARES) 

7 3 3 0.1 0.3 16 0.26 0.03 0.03 

Potential to emit for units 

using actual-to-potential test 

(FGDHOUPANNUAL) 

465 642 373 122.4 206.8 251.5 24.25 8.57 9.86 

Detroit HOUP Preconstruction Projection 472 645 376 122.5 207.1 267.5 24.51 8.60 9.89 

 

Actual emissions for units 

using actual-to-projected 

actual test 

(FGREFINEFLARES) 

 

Potential to emit for units 

using actual-to-potential test 

(FGDHOUPANNUAL) 

465 642 373 122.4 206.8 251.5 24.25 8.57 9.86 

Detroit HOUP Annual 

Emissions for Calendar 

Year(1)

 

(1) Sum of actual emissions for units using actual-to-projected actual test (FGREFINEFLARES) plus 

potential to emit for units using actual-to-potential test (FGDHOUPANNUAL). 
Marathon Petroleum Company LP (A9831) January 11, 2012 

Permit No. 63-08C Page 103 of 103 

H. Netting Summary: 

The net emissions for DHOUP shall be summarized based on the calendar year actual emissions for all 

emission units associated with the project. 

Detroit HOUP Emission Netting Summary (tons per year) 

 VOC NOx SO2 PM PM10 CO H2SO4 H2S TRS 

Actual emissions for units 

using actual-to-projected 

actual test 

(FGREFINEFLARES) 

 

Actual emissions for units 

using actual-to-potential test 

(FGDHOUPANNUAL) 

 

Detroit HOUP Actual 

Emissions for Calendar 

Year(1)

 

Detroit HOUP Baseline 

Emissions 441 357 178 81 202.3 183 12.04 8.84 10.01 

DHOUP Actual Emissions 

minus Baseline Emissions(2) 

Contemporaneous Emission 

Increases (3), (4) 26 0 0 0 0 0 0 - - 

Contemporaneous/Creditable 

Emission Decreases (4), (5) -66 -290 -219 -43 -18 0 -18 - - 

Other Contemporaneous 

Increases/Decreases(6) 

Net DHOUP Actual 

Emissions Increase 

(Add four lines above) 

 

PSD Significance Level 40 40 40 25 15 100 7 10 10 

(1) Sum of actual emissions for units using actual-to-projected actual test (FGREFINEFLARES) plus actual 

emissions for units using actual-to-potential test (FGDHOUPANNUAL) 

(2) Includes emission increases for several projects in contemporaneous period. 

(3) Excludes contemporaneous increases embedded in the line item for DHOUP Actual Emissions, 

including the 2005 expansion (see footnote 2). 

(4) Netting analysis was not required for hydrogen sulfide or total reduced sulfur compounds. 

(5) The creditable decreases for VOC include 46 tons per year due to controlling emissions from 29 

pressure relief valves to atmosphere in the LPG Tank Farm that are included in the “Detroit HOUP” line 

in the table in section E above. 

(6) Other emissions increases and decreases occurring during the contemporaneous period (after issuance 

of the Permit to Install for the DHOUP but before startup of the DHOUP).