Component 1

Form Approved __/__/__

OMB Control No. ____-____

Approval Expires __/__/__

Petroleum Refinery
Emissions Information Collection

PART I: GENERAL FACILITY INFORMATION

1. Facility ID number (EPA will provide this number): ______________________

2a. Plant Name (as reported on U.S. DOE/EIA Form-820 (2010), “Annual Refinery Report,” schedule 2, line 1, page 37, question 1):

2b. Does this facility¹ report in EIA-820 the combined processing/production capacities for refining plants that are not contiguously located? Yes No

2c. If Yes, provide the facility IDFacility ID assigned by the Section 114 letter for each non-contiguous facility:

________________________________________________________________________

3. Complete street address of facility (physical location):

4. Provide mailing address if different:

5. Name and title of contact(s) able to answer technical questions about the completed survey:

6. Contact(s) telephone number(s):

and e-mail address(es):

7. Name of legal owner of facility:

8. Name of legal operator of facility, if different from legal owner:

9. Address of ____ legal owner or ____ operator:

10. Dunn and Bradstreet number of your facility:

11. Annual revenue in 2010: $______________________

12. Number of employees at your facility:

13a. Are you part of a larger corporate entity or joint venture? Yes No

13b. If 13a is Yes, is the facility operated under a joint venture partnership? Yes No

If Yes: Provide the name and % ownership of each joint venture partner and provide the number of employees for each joint venture partner with 50% or greater ownership:

Partner name ______________ Percent ownership ______% No. employees ______

Partner name ______________ Percent ownership ______% No. employees ______

Partner name ______________ Percent ownership ______%

If No: Name of parent company:

Number of employees in parent company: ___________________________

Check the statement below that best applies:

The facility is fully independent of the parent organization (independent sources of capital, different Boards of Directors, etc.).

The parent organization provides some financial support.

Operations of the parent organization and this facility are fully integrated (full access to investment capital, same Board of Directors, etc.)

14. Circle all the applicable code numbers that describe the type of refinery:

1 Topping refinery

2 Hydroskimming refinery

3 Upgrading refinery

4 Heavy oil/asphalt refinery

15. Provide the quantity of products produced at the refinery and their relative disposition (transport method) in 2010. Production values should be provided as reported to EIA on form EIA-810 form, except specify aromatics production quantities. Provide the relative disposition of products from readily available information; exact quantity information is not necessary. For products piped directly to an offsite marine vessel tank ship terminal or tank truck terminal that is located near the refinery and is owned, operated, or under common control of the refinery (or its corporate holdings), report the transportation method as tank ship or tank truck, respectively, rather than reporting this quantity as “% shipped by pipeline.” Report under “% shipped by pipeline” all products shipped via general use pipelines (regardless of secondary transportation methods that may be served) or products piped directly to other offsite facilities.

Product/Refinery Output	Cumulative 2010 Production (1,000 bbls)	Disposition of Products by Transport Method
		% used onsite	% shipped by tank ship	% shipped by barge	% shipped by tank truck	% shipped by rail car	% shipped by pipeline
Ethane
Ethylene
Propane
Propylene
Normal Butane
Butylene
Isobutane
Isobutylene
Unfinished Oils – Naphthas and lighter
Unfinished Oils – Kerosene and light gas oils
Unfinished Oils – Heavy gas oils
Unfinished Oils – Residuum
Finished Motor Gasoline - Reformulated
Finished Motor Gasoline - Conventional
Motor Gasoline Blending Components - Reformulated
Motor Gasoline Blending Components - Conventional
Aviation Gasoline – Finished and Blending Components
Special Naphthas (solvents)
Kerosene-type Jet Fuel
Kerosene
Distillate Fuel Oil – 15 ppm sulfur and under
Distillate Fuel Oil – greater than 15 ppm to 500 ppm sulfur
Distillate Fuel Oil – greater than 500 ppm sulfur
Residual Fuel Oil – less than 0.31% sulfur
Residual Fuel Oil – 0.31% to 1.0% sulfur
Residual Fuel Oil – greater than 1% sulfur
Lubricants (total)
Asphalt and Road Oil
Wax
Petroleum Coke – Marketable
Petroleum Coke – Catalyst
Still Gas
Petrochemical Feedstocks – Naphtha <401°F end-point
Petrochemical Feedstocks - Other Oils ≥401°F end-point
Aromatics – Benzene
Aromatics – Toluene
Aromatics – Xylenes (total)
Aromatics – Other than BTX
Other Miscellaneous Products (specify)

16. Report the 2010 process capacities and actual throughput for each process unit by completing the table below. See definitions section for additional descriptions of the terms used. You may need to add “other” process units if your refinery contains significant processing units that are not covered by the processes listed. If 2010 throughputs are not representative of normal operations (e.g., plant idled temporarily for economic reasons, change of ownership, or fire, etc.), add a note describing the reason for the unusual operation and provide an estimate of the expected “normal” 2010 processing rates had these issues not occurred.

When asked for a Unit ID, please use the same identifying number or code that is used in EPA’s 2005 National Scale Air Toxics Assessment (NATA) National Emissions Inventory (NEI) data set (if possible and/or applicable). Instructions for locating the NEI data set for your refinery are located at the ICR website (https://refineryicr.rti.org). If the NEI does not show an entry for a particular unit, or you are not sure what units are included in the NEI data set, use a unique Unit ID for each process unit.

Provide the coordinates (latitude and longitude) of the approximate process unit centroid in North American Datum (NAD) 83 with 6 digits to the right of the decimal point.² (If currently available coordinates have five digits to the right of the decimal point instead of six, those coordinates are acceptable.).

When asked for a Unit ID, use a unique Unit ID for each process unit. When possible, use the same identifier from your permit or emissions inventory.

Unit ID		Process Type1		Unit Throughput Capacity (bbl/cd)2			Unit Actual Through­put (bbl/cd)2	Unit Latitude	Unit Longitude

¹ See list following the last footnote for codes corresponding to unit types. If none of the codes describe your process, enter “99” and specify the type of process.

² Throughput by calendar day × 365 days = annual throughput for 2010.Throughput units are barrels per calendar day (bbl/cd) unless noted otherwise.

For crude distillation through desulfurization units (process type codes 1 through 21), “throughput” is determined in terms of charged liquid material (excluding hydrogen gas inputs).

For catalytic cracking units, include both fresh and recycle feed.

For alkylation through oxygenate plants, coke calcining, and chemical production (process type codes 22 through 4336 and codes 39 through 45), “throughput” is determined in terms of primary product produced (e.g., quantity of alkylate produced in alkylation unit).

For aromatics production, report the total quantity of all aromatics produced from various separation processes after catalytic reforming.

For hydrogen productionplants, throughput units are million standard cubic feet per calendar day (MMcf/cd); use 32°F (0°C) and 1 atmosphere as “standard conditions” for H₂ productionplants.

For sulfur recovery, throughput units are long tons per calendar day (LT/cd). 1 LT = 1.12 short tons. Enter individual SRU trains in this table; you will be asked to identify the sulfur recovery plant for each train in Part II, Section 9.

For loading operations, “throughput” is the quantity of material loaded.

For fuel gas treatment, “throughput” is the quantity of fuel gas input to the unit. Throughput units are million standard cubic feet per calendar day (MMcf/cd); use 60°F (15.56°C) and 1 atmosphere as “standard conditions” for fuel gas treatment.

For fuel blending, “throughput” is the quantity of blended product produced.

For wastewater collection and treatment, systems (WWTS), throughput units are million gallons per day (MMgal/day). If desired, you may report wastewater treatment units used to comply with Benzene Waste Operations NESHAP (40 CFR part 61, subpart FF) “BWON” or sour water treatment units as separate wastewater treatment systemsWWTS, but you are not required to do so.

Code No. Type of Process

1 Atmospheric crude distillation

2 Vacuum distillation

3 Delayed coking

4 Fluid coking (traditional)

5 Flexicoking

6 Visbreaking, other thermal cracking

7 Fluid catalytic cracking unit

8 Non-fluid catalytic cracking unit

9 Catalytic hydrocracking

10 Catalytic reforming unit – continuous regeneration

11 Catalytic reforming unit – cyclic regeneration

12 Catalytic reforming unit – semi-regenerative

13 Fuels solvent deasphalting

14 Desulfurization/ hydrotreating – naphtha/reformer feed

15 Desulfurization/ hydrotreating – gasoline

16 Desulfurization/ hydrotreating – kerosene/jet fuel

17 Desulfurization/ hydrotreating – diesel

18 Desulfurization/ hydrotreating – other distillate

19 Desulfurization/ hydrotreating – residual

20 Desulfurization/ hydrotreating – heavy gas oil

21 Desulfurization/ hydrotreating – other

22 HF alkylation

23 H₂SO₄ alkylation

24 Aromatics production

25 Asphalt production

26 Isomerization – Isobutane

27 Isomerization – Iso C5,C6

28 Lubricants production

29 Petroleum coke storage

30 Hydrogen plant

31 Sulfur recovery unit (SRU)

32 Gas plant/light ends distillation/LPG production unit

33 Oxygenate plant – MTBE

34 Oxygenate plant – ETBE

35 Oxygenate plant – TAME

36 Oxygenate plant – other (specify)

37 Fuel gas treatment

38 Fuel blending

39 Coke calcining

40 Ethylene production

3841 Ethylene dichloride production

3942 Ethylene dibromide production

4043 Propylene production

4144 Acrylonitrile production

4245 Other petrochemical or organic chemical production (specify chemical)

43 Coke calcining

44 50 Product loading – Marine vessel loading/unloading

45 51 Product loading – Truck/tank truck loading/unloading

46 52 Product loading – Rail car loading/unloading

47 53 Product loading – Container/other loading/unloading

48 Fuel gas treatment

49 Fuel blending

5060 Wastewater collection and treatment system (WWTS)

99 Other (specify)

PART II: PROCESS AND EMISSIONS INFORMATION

When asked for a Unit ID in any section of Part II, please use the same identifying number or code that is used in Part I, Question 16.

SECTION 1. ENERGY MANAGEMENT

1. Facility ID number (EPA will provide this number): ________________________

2. Complete Table 1-1 below to provide the total energy use and fuel consumption by the entire refinery in 2010 (as reported to EIA on forms EIA-810 and EIA-820):

TABLE 1-1. 2010 Fuel Consumption

Fuel	Units	Fuel Consumption
Crude Oil1	bbl
LPG	bbl
Distillate Fuel Oil	bbl
Residual Fuel Oil	bbl
Still Gas	bbl
Marketable Coke	bbl
Catalyst Coke	bbl
Natural Gas	MMcf
Coal	Tons (US)
Purchased Electricity	MWh
Purchased Steam	MM lb
Other (solid)	Tons (US)
Other (liquid)	bbl
Other (gas)	MMcf

Abbreviations: bbl = barrels

MMcf = million cubic feet at 60°F and 1 atmosphere

MWh = Megawatt-hours

MM lb = million pounds

¹ Report only the quantity of crude oil consumed as fuel, not the quantity of crude oil fed to the atmospheric crude or vacuum distillation column.

3. Report the total quantity of hydrogen purchased [in million cubic feet at 32°F (0°C) and 1 atmosphere] from off-site (merchant) hydrogen producers. Do not include captive hydrogen production included in Part I; more detail regarding captive hydrogen production units or from hydrogen plants located at, but not under the comment control of, the petroleum refinery. Do not report hydrogen from hydrogen plants owned or under common control of the petroleum refinery in this quantity; more detail regarding hydrogen plants owned or under common control is requested in Part II, Section 10.

4. Does this refinery have a facility energy management plan? Yes No

If Yes: Provide a brief description of the key elements of the plan and key energy reductions that have resulted from the implementation of the plan.

5. Does this refinery generate electricity or steam on-site? Yes No

If Yes: Provide the information requested in Table 1-2 for each electricity- generating, steam generating, or combined heat and power unit. Include energy recovery turbines and waste heat boilers used on process unit exhaust lines.

TABLE 1-2. Electricity and Steam Generation Information

Generation Unit ID

Unit Description1

Primary Fuel2

Secondary Fuel2

Energy Efficiency Measures3

Air preheat use4

Typical air preheat temperature when used (°F)

Is this unit a combined heat and power unit? (Yes/No)Generation Unit Type5

Electricity Generation

Steam Generation

Capacity of Unit (MW)

Disposition of electricity56

Boiler Heat Input Capacity (MMBtu/hr)

Steam Generating Capacity (lb/hr)

Pressure of Steam (psia)

Disposition of steam67

Percent Steam to Blowdown78

Footnotes for Table 1-2:

Abbreviations: MW = megawatts

MMBtu/hr = million British thermal units per hour

lb/hr = pounds per hour

psia = pounds per square inch absolute

¹ For waste heat boiler, list process unit and “waste heat boiler” (e.g., “FCCU waste heat boiler”).

² Select from the following list of fuels.

Code No. Type of Fuel

0 None (i.e., waste heat only)

1 Natural gas

2 Refinery fuel gas (mixture of natural gas and still gas or process gas)

3 Still gas or process gas only (not mixed with natural gas)

4 Distillate fuel oil

5 Heavy gas oil

6 Low Btu fuel gas from flexicoking unit or other gasification process

7 Coal

8 Wood or other biomass fuel

99 Other (specify)

³ Select the energy efficiency measure(s) used with this unit from the following list. Select all that apply.

Code No. Type of Energy Efficiency Measure

0 None

1 Insulation on boiler

2 Insulation on distribution lines

3 Oxygen monitors used to control/limit excess oxygen

4 Intake air monitors to optimize fuel/air mixtures

5 Combustion air preheat from flue gas

6 Boiler feed water preheat from flue gas

7 Blowdown steam recovery system for low pressure needs

8 Steam trap maintenance

9 Steam condensate return lines (to return condensate (hot water) to boiler)

10 Steam expansion turbines (to recover energy from high pressure steam when steam is needed at lower pressures)

11 Boiler maintenance program to reduce scaling (other than soot blowing)

12 Boiler maintenance program to maintain burners (other than soot blowing)

99 Other (specify)

⁴ Select from the following list of air preheat descriptions the option that best applies for the unit.

Code No. Type of Air Preheat

0 No air preheater is present

1 Air preheater is present, but use less than 20% of the time

2 Air preheater is present and used 20% to 50% of the time

3 Air preheater is present and used more than 50% but less than 90% of the time

4 Air preheater is present and used 90% or more of the time

⁵ Select from the following list of unit types.

Code No. Type of Unit

1 Electricity generating unit

2 Steam generating unit

3 Combined heat and power unit

⁶ Select from the following list of dispositions.

Code No. Type of Electricity Disposition

1 Generated electricity is used only on-site

2 Generated electricity is used only off-site (e.g., sent to grid)

3 Generated electricity is used on-site with excess used off-site or sent to grid

⁷⁶ Select from the following list of dispositions.

Code No. Type of Steam Disposition

1 Generated steam is used only on-site.

2 Generated steam is used only off-site.

3 Generated steam is used on-site with excess used off-site.

⁷⁸ If the exact percentage is unknown, and you are unable to provide a reasonable estimate, answer “Unknown.”

6. Provide the information requested in Table 1-3 for each processing unit listed in Question 16 of Part I (except wastewater treatment systemsWWTS, which are reported in Section 15).

TABLE 1-3. Steam Demand by Process Unit

Unit ID	Average steam demandSteam consumption for the processing unit during normal operation assuming the processing unit is operated at maximum capacity (lb/hr)1in 2010 (tons/yr)

¹ For cyclic processes, such as delayed coking unit, estimate the total steam use over a complete cycle and divide by the cycle time indicative of maximum processing rates.

SECTION 2. PROCESS HEATER DATAHEATERS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide the information requested in Table 2-1 for each process heater at the facility that serves a process unit identified in Part I, Question 16.

TABLE 2-1. Process Heater General Information

Process Heater ID

Unit ID for process unit served by process heater

Process heater construction type1

Process heater draft type2

Is the process heater designed to be e co-fired? (Yes/No)

Rated heat input capacity (MMBtu/hr)

Average heat input rate in 2010 (MMBtu/hr)

Total operating hours in 2010 (hr)

Air preheat use3

Typical air preheat temperature when used (°F)

Other energy efficiency measures4

Primary fuel5

Percent of total operating hours process heater fired with primary fuel in 2010

Secondary fuel5

Percent of total operating hours process heater fired with secondary fuel in 2010

Operating hours while operating less than 25% of rated capacity in 2010(hr)

Operating hours in turndownwhile operating at 25 to 50% of rated capacity in 2010 (hr)

Applicable Federal air regulation(s)6

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Type of PM controls7

Type of SO2 controls8

Type of NOX controls9

Footnotes for Table 2-1:

¹ Select from the following list of process heater construction types.

Code No. Type of Construction

1 Vertical cylinder

2 Cabin or box

99 Other (specify)

² Select from the following list of process heater draft types.

Code No. Type of Draft

1 Natural draft

2 Induced draft (exhaust-side fan only), upward firing

3 Induced draft (exhaust-side fan only), downward firing

4 Forced draft (combustion air-side fan only)

5 Balanced draft (both air- and exhaust-side fans), but no air preheater

6 Balanced draft (both air- and exhaust-side fans) with air preheater

99 Other (specify)

³ For air preheat use, enter the appropriate code number the option that best describes the air preheat use: .

Code No. Type of Air Preheat

0 No air preheater is present

1 Air preheater is present, but use less than 20% of the time

2 Air preheater is present and used 20% to 50% of the time

3 Air preheater is present and used more than 50% but less than 90% of the time

4 Air preheater is present and used 90% or more of the time

⁴ Select from the following list of energy efficiency measures (other than air preheat).

Code No. Type of Energy Efficiency Measure

0 None

1 Oxygen monitors used to control/limit excess oxygen

2 Intake air monitors to optimize fuel/air mixtures

3 Maintenance program to reduce scaling (other than soot blowing)

4 Maintenance program to maintain burners (other than soot blowing)

5 Finned or dimpled tubes to increase heat transfer

99 Other (specify)

⁵ Select from the following list of fuels.

Code No. Fuel Type

1 Natural gas

2 Refinery fuel gas (mixture of natural gas and still gas or process gas)

3 Still gas or process gas only (not mixed with natural gas)

4 Distillate fuel oil

5 Heavy gas oil

6 Low Btu fuel gas from flexicoking unit or other gasification process

99 Other (specify)

⁶ Select the Federal air regulation(s) to which the process heater is subject from the following list of regulations. Select all that apply, but include only regulations to which the process heater is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the process heater is subject).

Code No. Federal Air Regulation

0 None

1 Refinery NSPS (40 CFR part 60, subpart J)

2 Refinery NSPS (40 CFR part 60, subpart Ja)

3 CAA section 112(g) and section 112(j) (40 CFR part 63, subpart B)

99 Other (specify)

⁷ Select from the following list of PM controls; list all that apply.

Code No. Type of PM Control

0 None

11 Fabric/cartridge filter (“baghouse”)

12 Venturi/wet scrubber

13 Electrostatic precipitator (ESP)

14 Wet ESP

96 Management practice or work practice to reduce PM (specify)

99 Other (specify)

⁸ Select from the following list of SO₂ controls; list all that apply.

Code No. Type of SO₂ Control

0 None

21 H₂S limit in fuel gas

22 TRS limit in fuel gas

23 Low sulfur distillate or low sulfur heavy gas oil

24 Wet scrubber/flue gas desulfurization

25 Spray dryer absorber

97 Management practice or work practice to reduce SO₂ (specify)

99 Other (specify)

⁹ Select from the following list of NO_X controls; list all that apply.

Code No. Type of NO_X Control

0 None

31 (External) flue gas recirculation

32 Staged air low NO_X burner

33 Staged fuel low NO_X burner

34 Ultra low NO_X burner (high fraction staged fuel) (ULNB)

35 “Next generation” low NO_X burner (ULNB with internal gas recirculation)

36 Selective non-catalytic reduction (SNCR)

37 Selective catalytic reduction (SCR)

98 Management practice or work practice to reduce NO_X (specify)

99 Other (specify)

SECTION 3. EQUIPMENT LEAKS

1. Facility ID number (EPA will provide this number): ______________________

2. Do you own or have ready access to an optical or thermal imaging device for detecting equipment leaks? Yes No

If Yes:

a. Provide the manufacturer and model number: ____________________________

b. How do you most often use the imaging device to detect equipment leaks?

1 To comply with the alternative work practice for monitoring equipment for leaks (40 CFR 63.11(c) and 40 CFR 60.18(g))

2 To check for leaks on a fairly routine basis (e.g., leaks that Method 21 monitoring may have missed, leaks from equipment not required to be monitored)

3 To find leaks following non-routine operations (e.g., pressure integrity checks prior to startup)

4 Other

3. Complete Table 3-1 for each process unit listed in Part I, Question 16 (except wastewater treatmentWWTS). The total equipment counts should be the total number of pieces of equipment in a process unit, not necessarily only those currently being monitored. Do not count pieces of equipment that are in vacuum service. You may provide reasonable estimates of equipment counts from existing information if the requested equipment counts are not directly available as requested in Table 3-1 for each process unit as defined in this ICR.

TABLE 3-1. Equipment and Leak Detection Information for Process Units

Unit ID

Applicable Federal air regulation(s)1

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Average methane concentration in process fluid that contacts equipment in gas service throughout the process

Is the average methane concentration based on sampling and analysis results or estimated (e.g., based on process knowledge)?

For each of the following types of equipment, provide:

PumpsPump Seals

Valves

Flanges

Flanges & Connectors

Open-ended lines3

Com­pres­sorsCom­pres­sor Seals

Hatches Gas Sampling Connections

Sight glassesLiquid Sampling Connections

Gages

Diaphragms

Other4

Light liquid2

Heavy liquid2

Gas2

Light liquid2

Heavy liquid2

Gas2

LightGas and light liquid2

Heavy liquid2

Gas2

Light liquid2

Heavy liquid2

Number of Pieces of Equipment

Number of Pieces of Equipment Monitored5

Monitoring Frequency6

Leak Definition (ppmv)7

Number of Pieces of Equipment

Number of Pieces of Equipment Monitored5

Monitoring Frequency6

Leak Definition (ppmv)7

Footnotes for Table 3-1:

¹ Select the Federal air regulation(s) to which the process unit is subject from the following list of regulations. Select all that apply, but include only regulations for equipment leaks to which the process unit is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the process unit is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGG)

4 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGGa)

5 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VV)

6 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VVa)

7 HON (40 CFR part 63, subpart H) existing source requirements

8 HON (40 CFR part 63, subpart H) new source requirements

9 MON (40 CFR part 63, subpart FFFF) existing source requirements

10 MON (40 CFR part 63, subpart FFFF) new source requirements

11 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements

12 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements

13 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements

14 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements

99 Other (specify)

² Use the definitions of “gas service,” “light liquid service,” and “heavy liquid service” in the regulation to which your process unit is subject, if applicable. See the list of definitions for this ICR for definitions of these terms to use if your process unit is not subject to a regulation that includes definitions of these terms.

³ The information requested for open-ended lines refers to leakage from the open-end of a pipe or valve(e.g., downstream of a secondary valve) or from a cap on the pipe and not to leakage from the associated valve packing or body flanges.

⁴ Other equipment includes any other fugitive emissions source not already provided that is monitored similar to equipment. Specify the types of fugitive emission sources.

⁵ Do not include difficult-to-monitor equipment in this count.

⁶ Select from the following list of monitoring frequencies the option that best describes the frequency at which the majority of the equipment are monitored for the process unit, type of equipment, and type of service. (For “other,” if you specified multiple types of fugitive emission sources and they have different monitoring frequencies, select the shortest monitoring interval for such sources.)

Code No. Monitoring Frequency

0 None (unit/system not monitored for leaks)

1 No set interval (use only for sensory monitoring)

2 Less than annually

3 Annually

4 Semiannually

5 Quarterly

6 Monthly

7 Biweekly

8 Weekly or more frequently

⁷ Select from the following list of leak definitions the monitored concentration above which repairs are required (or routinely performed) for the process unit, type of equipment, and type of service. (For “other,” if you specified multiple types of fugitive emission sources and they have different leak definitions, select the lowest leak definition for such sources.)

Code No. Leak Definition

0 None (unit/system not monitored for leaks)

1 Detection by sensory monitoring

2 10,000 ppmv

3 5,000 ppmv

4 2,000 ppmv

5 1,000 ppmv

6 500 ppmv

7 Less than 500 ppmv

4. Complete Table 3-2 for each fuel gas and natural gas system at the facility. The equipment counts should be the total number of pieces of equipment the fuel gas and natural gas system at the facility (without double counting equipment included in Table 3-1). You may provide reasonable estimates of equipment counts from existing information if the requested equipment counts are not directly available as requested for each fuel gas and natural gas system.

TABLE 3-2. Equipment and Leak Detection Information for Fuel Gas and Natural Gas Systems

Unit ID

Applicable Federal air regulation(s)1

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Average methane concentration in process fluid that contacts equipment in gas service throughout the process

Is the average methane concentration based on sampling and analysis results or estimated (e.g., based on process knowledge)?

For each of the following types of equipment, provide:

Pumps

Valves in Gas Service2

FlangesCom­pres­sor Seals

Connectors

Open-ended lines3

Com­pres­sors

Hatches

Sight glasses

Gages

Diaphragms

Other4

Light liquid2

Heavy liquid2

Gas2

Light liquid2

Heavy liquid2

Gas2

Light liquid2

Heavy liquid2

Gas2

Light liquid2

Heavy liquid2

Number of Pieces of Equipment

Number of Pieces of Equipment Monitored53

Monitoring Frequency64

Leak Definition (ppmv)75

Number of Pieces of Equipment

Number of Pieces of Equipment Monitored53

Monitoring Frequency64

Leak Definition (ppmv)75

Number of Pieces of Equipment

Number of Pieces of Equipment Monitored3

Monitoring Frequency4

Leak Definition (ppmv)5

Number of Pieces of Equipment

Number of Pieces of Equipment Monitored3

Monitoring Frequency4

Leak Definition (ppmv)5

Footnotes for Table 3-2:

¹ Select the Federal air regulation to which the fuel gas or natural gas system is subject from the following list of regulations. Select all that apply, but include only regulations for equipment leaks to which the fuel gas or natural gas system is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the fuel gas or natural gas system is subject).

Code No. Federal Air Regulation

0 None

1 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGG)

2 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGGa)

3 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VV)

4 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VVa)

99 Other (specify)

² Use the definitions of “gas service,” “light liquid service,” and “heavy liquid service” in the regulation to which your process unit is subject, if applicable. See the list of definitions for this ICR for definitionsa definition of these termsthis term to use if your process unit is not subject to a regulation that includes definitionsa definition of these termsthis term.

³ The information requested for open-ended lines refers to leakage from the open-end of a pipe or valve and not to leakage from the associated valve packing or body flanges.

⁴ Other equipment includes any other fugitive emissions source not already provided that is monitored similar to equipment. Specify the types of fugitive emission sources.

⁵³ Do not include difficult-to-monitor equipment in this count.

⁶⁴ Select from the following list of monitoring frequencies the option that best applies for the fuel gas or natural gas system, type of equipment, and type of service. (For “other,” if you specified multiple types of fugitive emission sources and they have different monitoring frequencies, select the shortest monitoring interval for such sources.)

Code No. Monitoring Frequency

0 None (unit/system not monitored for leaks)

1 No set interval (use only for sensory monitoring)

2 Less than annually

3 Annually

4 Semiannually

5 Quarterly

6 Monthly

7 Biweekly

8 Weekly or more frequently

⁷⁵ Select from the following list of leak definitions the monitored concentration above which repairs are required (or routinely performed) for the process unit, type of equipment, and type of service. (For “other,” if you specified multiple types of fugitive emission sources and they have different leak definitions, select the lowest leak definition for such sources.)

Code No. Leak Definition

0 None (unit/system not monitored for leaks)

1 Detection by sensory monitoring

2 10,000 ppmv

3 5,000 ppmv

4 2,000 ppmv

5 1,000 ppmv

6 500 ppmv

7 Less than 500 ppmv

5. Provide the information requested in Table 3-3 regarding pressure relief devices (PRD) on each process unit listed in Part I, Question 16 (except wastewater treatment) and for each fuel gas and natural gas system at the facility.WWTS).

TABLE 3-3. Pressure Relief Devices

Unit ID, Fuel Gas System ID, or Natural Gas System ID

Total number of PRD

Number of PRD routed to fuel gas system or control device

Atmospheric PRD

Gas

Liquid

Gas

Liquid

Number of PRD

Type of controls1

Number of PRD

Type of controls1

Number of PRD

Number equipped with rupture disk or second valveother non-reclosing device

Method 21 Periodic Monitoring for Leaks

Monitoring of Releases

Number of PRD

Number equipped with rupture disk or second valveother non-reclosing device

Method 21 Periodic Monitoring for Leaks

Monitoring of Releases

Number of PRD

Monitoring Frequency2

Leak Definition (ppmv)3

Number of PRD monitored using a system designed to measure the duration of a release and/or the quantity of compounds released

Describe your monitoring system

Number of PRD

Monitoring Frequency2

Leak Definition (ppmv)3

Number of PRD monitored using a system designed to measure the duration of a release and/or the quantity of compounds released

Describe your monitoring system

Footnotes for Table 3-3:

¹ Select from the following list of controls. List all that apply to PRD in the process unit, fuel gas system, or natural gas system.

Code No. Type of Control

0 None

50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

55 Flare

61 Routed to fuel gas system

95 Management practice or work practice for VOC reduction (specify)

99 Other (specify)

² Select from the following list of Method 21 monitoring frequencies the option that best applies for the process unit, type of equipment, and type of service. Select “0” if the PRD are not monitored regularly on a set schedule (i.e., they are only monitored after a release to confirm that there are no detectable emissions).

Code No. Monitoring Frequency

0 None (unit/system not monitored for leaks using Method 21 (but may be monitored using sensory methods))

1 Less than annually

2 Annually

3 Semiannually

4 Quarterly

5 Monthly

6 Biweekly

7 Weekly or more frequently

8 Only after releases

³ Select from the following list of leak definitions the monitored concentration above which repairs are required (or routinely performed) for the process unit and type of service. Select “0” if the PRD are not monitored regularly on a set schedule (i.e., they are only monitored after a release to confirm that there are no detectable emissions).

Code No. Leak Definition

0 None (unit/system not monitored for leaks using Method 21 (but may be monitored using sensory methods))

1 10,000 ppmv

2 5,000 ppmv

3 2,000 ppmv

4 1,000 ppmv

5 500 ppmv

6 Less than 500 ppmv

SECTION 4. STORAGE TANKS

1. Facility ID number (EPA will provide this number): ______________________

2. Does the facility receive unstabilized crude oil? Yes No

If Yes, provide the following information:

a. The quantity of unstabilized crude oil received in 2010: ______________ bbls

b. The pressure at which the unstabilized crude oil is received: __________ psia

3. Does the facility receive use methane to blanket any storage tanks? Yes No

If Yes, provide the quantity of methane used for storage tank blanketing:

____________________ MMscf at 60 °F and 1 atmosphere

4. Please provide information requested in Table 4-1 for each storage tank at the facility. that has a capacity greater than 10,000 gal and holds liquid material (including wastewater) with a maximum true vapor pressure greater than 0.1 psi.

TABLE 4-1. Storage Tank General Information

Tank ID

Type of stored liquid1

Maximum true vapor pressure of hydrocarbons in stored liquid in 2010 (psi)

Temperature at which maximum true vapor pressure was calculated (°F)

Type of tank/controls2

Diameter (ft)

Height (ft)

Maximum liquid height (ft)

Total throughput for all materials stored in the tank in 2010 (bbl)

Is the tank a “drain-dry” tank? (Yes/No)

Applicable Federal air regulation(s)3

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Year in which the tank was last degassed

Type of control for last degassing event4

Was the tank cleaned during last degassing event? (Yes/No)

Year in which you anticipate the next degassing event5

For tanks with EFR or IFR

Type of primary rim seal6

Type of secondary rim seal7

Minimum height of floating roof above the floor at the shell when landed

Number of times floating roof landed in 2010

Number of times the tank was emptied after roof landed in 2010

Footnotes for Table 4-1:

¹ Report the type of liquid stored (or crude oil received) in the tank for the predominant use of the tank. Select from the following list of liquid types.

Code No. Type of Stored Liquid

1 Unstabilized crude oil

2 Stabilized crude oil

3 Ethane

4 Ethylene

5 Propane

6 Propylene

7 Normal Butane

8 Butylene

9 Isobutane

10 Isobutylene

11 Unfinished Oils – Naphthas and lighter

12 Unfinished Oils – Kerosene and light gas oils

13 Unfinished Oils – Heavy gas oils

14 Unfinished Oils – Residuum

15 Finished Motor Gasoline - Reformulated

16 Finished Motor Gasoline - Conventional

17 Motor Gasoline Blending Components - Reformulated

18 Motor Gasoline Blending Components - Conventional

19 Aviation Gasoline – Finished and Blending Components

20 Special Naphthas (solvents)

21 Kerosene-type Jet Fuel

22 Kerosene

23 Distillate Fuel Oil – 15 ppm sulfur and under

24 Distillate Fuel Oil – greater than 15 ppm to 500 ppm sulfur

25 Distillate Fuel Oil – greater than 500 ppm sulfur

26 Residual Fuel Oil – less than 0.31% sulfur

27 Residual Fuel Oil – 0.31% to 1.0% sulfur

28 Residual Fuel Oil – greater than 1% sulfur

29 Lubricants (total)

30 Asphalt and Road Oil

31 Wax

32 Still Gas

33 Petrochemical Feedstocks – Naphtha <401°F end-point

34 Petrochemical Feedstocks - Other Oils ≥401°F end-point

35 Aromatics – Benzene

36 Aromatics – Toluene

37 Aromatics – Xylenes (total)

38 Aromatics – Other than BTX

40 Sour water

41 Slop oil

42 Other wastewater

99 Other (specify)

² Report the type of tank and controls. Select from the following list of tank types and controls. See the list of definitions for this ICR for details on what is considered a controlled guidepole.

Code No. Type of Tank/Control

1 Fixed roof tank vented to atmosphere

2 Fixed roof tank vented to control device

3 Fixed roof tank using vapor balancing

4 External floating roof, slotted guidepoles

5 External floating roof with solid guidepoles

6 External floating roof, controlled guidepoles

7 Internal floating roof, slotted guidepoles

8 Internal floating roof with solid guidepoles

9 Internal floating roof, controlled guidepoles

10 External floating roof with geodesic dome roof

11 Horizontal tank

12 Pressurized/sphere tank

99 Other (specify)

³ Select the Federal air regulation(s) to which the storage vessel is subject from the following list of regulations. Select all that apply, but include only regulations to which the storage vessel is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the storage vessel is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT (40 CFR part 63, subpart CC) new source requirements

3 HON (40 CFR part 63, subpart H) existing source requirements

4 HON (40 CFR part 63, subpart H) new source requirements

5 NSPS for Storage Vessels (40 CFR part 60, subpart K)

6 NSPS for Storage Vessels (40 CFR part 60, subpart Ka)

7 NSPS for Storage Vessels (40 CFR part 60, subpart Kb)

8 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements

9 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements

10 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements

11 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements

99 Other (specify)

⁴ Report the type of control used for the most recent degassing event. Select from the following list of controls.

Code No. Type of Degassing Control

0 None; tank vented to atmosphere while being degassed

54 Portable internal combustion engine

55 Portable thermal oxidizer

56 Portable condensation system

57 Permanent onsite control device

99 Other (specify)

⁵ Select the year in which you anticipate the next degassing event.

Code No. Year

0 2010

1 2011

2 2012

3 2013

4 2014

5 2015

6 2016

7 2017

8 2018

9 2019

10 2020 or later

⁶ Select the type of primary rim seal.

Code No. Type of Rim Seal

0 None

1 Vapor-mounted seal; flexible wiper type

2 Vapor-mounted seal; resilient-filled type

3 Liquid-mounted seal

4 Mechanical-shoe seal

⁷ Select the type of secondary rim seal.

Code No. Type of Rim Seal

0 None

1 Rim-mounted seal (if primary rim seal is mechanical-shoe seal)

2 Shoe-mounted seal (if primary rim seal is mechanical-shoe seal)

3 Vapor-mounted seal; flexible wiper type

SECTION 5. CATALYTIC CRACKING UNITS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 5-1 for each catalytic cracking unit (CCU) at the facility.

TABLE 5-21. Catalytic Cracking Unit Information

Unit ID for CCU

Fresh Feed Capacity (bbl/cd)

Recycle /Resid Capacity (bbl/cd)

Percent of CCU Feed that is Hydrotreated (%)

Typical Coke Burn Rate at Capacity (tons/cd)

Type of CCU (fluid, thermal, or other)

Type of CCU Regenerator (complete, partial, or variable)

Is there a CO boiler ofor other combustion device after CCU regenerator (Yes/No)?

Applicable Federal air regulation(s)1

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

2010 Weighted Average Sulfur Concentration in Combined Feed (wt%)

2010 Weighted Average Nickel Concentration in Combined Feed (wt%)

2010 Weighted Average Vanadium Concentration in Combined Feed (wt%)

Type of PM controls2

Type of SO2 controls3

Type of NOX controls4

Footnotes for Table 5-21:

¹ Select the Federal air regulation(s) to which the CCU is subject from the following list of regulations. Select all that apply, but include only regulations to which the CCU is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the CCU is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements

2 Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart J)

4 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

² Select from the following list of PM controls; list all that apply.

Code No. Type of PM Control

0 None

11 Fabric/cartridge filter (“baghouse”)

12 Venturi/wet scrubber

13 Electrostatic precipitator (ESP)

14 Wet ESP

15 Tertiary cyclone

96 Management practice or work practice to reduce PM (specify)

99 Other (specify)

³ Select from the following list of SO₂ controls; list all that apply.

Code No. Type of SO₂ Control

0 None

24 Wet scrubber/flue gas desulfurization

25 Spray dryer absorber

26 DeSOx catalyst, meeting 50/25 ppmv SO₂ limit

27 DeSOx catalyst, meeting 20 lb/ton coke burn-off, but not 50/25 ppmv SO₂ limit

28 Low sulfur feed (0.3 wt% or less) feed

97 Management practice or work practice to reduce SO₂ (specify)

99 Other (specify)

⁴ Select from the following list of NO_X controls; list all that apply.

Code No. Type of NO_X Control

0 None

32 Staged air low NO_X burner in CO boiler or other post-combustion device

33 Staged fuel low NO_X burner in CO boiler or other post-combustion device

34 Ultra low NO_X burner (high fraction staged fuel) (ULNB) in CO boiler or other post-combustion device

35 “Next generation” low NO_X burner (ULNB with internal gas recirculation)) in CO boiler or other post-combustion device

36 Selective non-catalytic reduction (SNCR)

37 Selective catalytic reduction (SCR)

39 High-efficiency regenerator

40 Low NO_X combustion additives to replace Pt-based combustion additives

41 Other low NO_X catalyst additives

42 LoTOX® scrubber

98 Management practice or work practice to reduce NO_X (specify)

99 Other (specify)

3. If the facility has metal concentration for E-cat and/or fines, provide annual average values for each CCU at the facility in the Table 5-2 below.

TABLE 5-2. E-Cat and CCU Fines Metal Concentration

Unit ID for CCU

Particle Type

Concentration (parts per million by weight, ppmw)

Antimony

Arsenic

Beryllium

Cadmium

Chromium

Cobalt

Lead

Manganese

Mercury

Nickel

Selenium

Vanadium

E-cat

Fines

E-cat

Fines

E-cat

Fines

E-cat

Fines

SECTION 6. FLUID COKING UNITS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 6-1 for each fluid coking unit (FCU) at the facility.

TABLE 6-1. Fluid Coking Unit Information

Unit ID for FCU

Feed Capacity (bbl/cd)

Type of FCU (traditional or flexicoker)

Applicable Federal air regulation(s)1

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

If traditional coker

If flexicoker

Coke Production Capacity (tons/cd)

Typical Coke Burn Rate at Capacity (tons/cd)

Is there a CO boiler or other combustion device after FCU regenerator (Yes/No)?

Type of PM controls2

Type of SO2 controls3

Type of NOX controls4

Produced Coke Handling Controls and Disposition5

Low Btu gas production rate at capacity (scfm)

Low Btu gas sulfur removal technique6

FCU dust/ash quantity produced (tons/cd)

FCU dust/ash handling/disposal method7

Footnotes for Table 6-1:

¹ Select the Federal regulation(s) to which the FCU is subject from the following list of regulations. Select all that apply, but include only regulations to which the FCU is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the FCU is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

² Select from the following list of PM controls; list all that apply.

Code No. Type of PM Control

0 None

11 Fabric/cartridge filter (“baghouse”)

12 Venturi/wet scrubber

13 Electrostatic precipitator (ESP)

14 Wet ESP

15 Tertiary cyclone

96 Management practice or work practice to reduce PM (specify)

99 Other (specify)

³ Select from the following list of SO₂ controls; list all that apply.

Code No. Type of SO₂ Control

0 None

24 Wet scrubber/flue gas desulfurization

25 Spray dryer absorber

28 Low sulfur feed (0.3 wt% or less) feed

97 Management practice or work practice to reduce SO₂ (specify)

99 Other (specify)

⁴ Select from the following list of NO_X controls; list all that apply.

Code No. Type of NO_X Control

0 None

32 Staged air low NO_X burner in CO boiler or other post-combustion device

33 Staged fuel low NO_X burner in CO boiler or other post-combustion device

34 Ultra low NO_X burner (high fraction staged fuel) (ULNB) in CO boiler or other post-combustion device

35 “Next generation” low NO_X burner (ULNB with internal gas recirculation)) in CO boiler or other post-combustion device

36 Selective non-catalytic reduction (SNCR)

37 Selective catalytic reduction (SCR)

39 High-efficiency regenerator

40 Low NO_X combustion additives to replace Pt-based combustion additives

41 Other low NO_X catalyst additives

42 LoTOX® scrubber

98 Management practice or work practice to reduce NO_X (specify)

99 Other (specify)

⁵ Select from the following list the combination that best describes the coke handling and disposition method. For example, select 5E if you use the coke on-site in coke calciner and you use an enclosed conveyor to a storage bin with walls (wind breaks) and you wet the coke to suppress fugitive dust emissions.

Code No.	Disposition	Code Letter	Storage/Handling Method
1	Shipped off-site to coke calciner	A	Enclosed conveyer to silo for loading/processing
2	Shipped off-site to be used as fuel	B	Open conveyer to silo for loading/processing
3	Shipped off-site: some to coke calciner and some as fuel	C	Enclosed conveyer to open storage pile or bin, wind break only
4	Shipped off-site: other or unknown use	D	Enclosed conveyer to open storage pile or bin, wetting only
5	Processed in on-site coke calciner	E	Enclosed conveyer to open storage pile or bin, wind break and wetting
6	Used on-site as fuel	F	Open conveyance to open storage pile or bin, wind break only
7	Some used on-site as fuel, remainder sent off-site to coke calciner	G	Open conveyance to open storage pile or bin, wetting only
8	Some used on-site as fuel, remainder sent off-site for use as fuel	H	Open conveyance to open storage pile or bin, wind break and wetting
99	Other (specify)	Z	Other (specify)

⁶ Select from the following list of low Btu gas sulfur controls.

Code No. Low Btu Gas Sulfur Control

0 None

1 Conventional amine scrubber (e.g., MEA, MDEA)

2 Sterically-hindered amine scrubber (e.g., Flexsorb®)

3 Selexol®

4 Rectisol®

5 COS hydrolysis + conventional amine scrubber

6 COS hydrolysis + sterically-hindered amine scrubber

7 COS hydrolysis + Selexol®

8 COS hydrolysis + Rectisol®

9 Sulfinol®

98 Management practice or work practice (specify)

99 Other (specify)

⁷ Select from the following list the method that best describes the flexicoking dust/ash handling and disposal method.

Code No. Flexicoking Dust/Ash Handling and Disposal Methods

1 Used on-site as fuel

2 Disposed of in on-site landfill

3 Disposed of in off-site landfill

4 Shipped off-site for use as fuel

5 Shipped off-site for metals recovery

99 Other (specify)

SECTION 7. DELAYED COKING UNITS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 7-1 for each delayed coking unit (DCU) at the facility. For purposes of this information collection, a DCU consists of all drums connected to a single fractionator and the fractionator.

TABLE 7-1. Delayed Coking Unit Operating Information

Unit ID for DCU

Feed Capacity (bbl/cd)

Coke Production Capacity (tons/cd)

Type of Coke Produced1

Number of Coke Drums

Height of Single Coke Drum (ft)

Diameter of Single Coke Drum (ft)

Typical Coke Drum Outage (ft)

Typical Coke Drum Pressure When First Vented to Atmosphere (psig)

Typical Coke Drum Temperature at Top of Drum When First Vented to Atmosphere (°F)

Typical Water Height in Coke Drum When First Vented to Atmosphere (ft)

Typical Cycle Time

Quench Water

Applicable Federal air regulation(s)7

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Complete Coke Drum Cycle Time (hr)2

Coke Drum Feed Cycle Time (hr)

Coke Drum Steam Purge Time (hr)

Coke Drum Water Quenching Time (hr)

Coke Drum Depressurization Vent Time (hr)

Coke Drum Coke Cutting Time (hr)

Coke Drum Preheat/Standby Time (hr)

Water Quenching Cycle Description3

Typical Quench Water Flow Rate during Quenching Cycle (gal/min)

Average Quench Water Make-up Rate (gal/day)

Purged Steam Blowdown System Description4

Quench Water Disposition5

Cutting Water Source and Storage/Handling6

Footnotes for Table 7-1:

¹ Select from the following list of produced coke types.

Code No. Quench Water Source

1 Needle coke, anode grade

2 Needle coke, fuel grade

3 Sponge coke, anode grade

4 Sponge coke, fuel grade

5 Shot coke, anode grade

6 Shot coke, fuel grade

99 Other (specify)

² Complete coke drum cycle time is from the start of one feed cycle to the start of the next feed cycle for a single drum and should equal feed time + steam time + cooling time + venting time + cutting time + preheat/standby time.

³ Select from the following list of water quenching cycle descriptions.

Code No. Quench Water Source

1 Use “tap” water (i.e., water purchased directly from utility or drinking water)

2 Use process or recycled blowdown water

3 Use recycled cutting water with “tap” water make-up

4 Use recycled cutting water with process or blowdown water make-up

5 Use treated water from sour water stripper

6 Use treated water from wastewater treatment systemWWTS

99 Other (specify)

⁴ Select from the following list of blowdown system descriptions used to manage the steam exhausted during the steam purge and water quench cycles (prior to venting the vessel to atmosphere).

Code No.	Condensed Water Disposition	Code Letter	Uncondensed Vapor Disposition When Not Sent Directly to DCU Fractionator
1	Sent to wastewater treatment systemWWTS	A	Not applicable; uncondensed vapors are always sent to DCU fractionator
2	Sent to sour water stripper	B	Uncondensed vapors are sent to dedicated DCU flare
3	Used to make steam	C	Uncondensed vapors are sent to flare gas header system to general facility flare
4	Recycled to unit and used as quench water	D	Uncondensed vapors are sent to flare gas recovery system
5	Used as coke cutting water	E	Uncondensed vapors are always sent directly to process heater or boiler
6	Used as general process water	F	Uncondensed vapors are always sent directly to amine treatment unit or fuel gas system
99	Other (specify)	G	Uncondensed vapors are controlled by oil scrubber or lean oil absorber prior to venting to atmosphere
		H	Uncondensed vapors are vented directly to atmosphere
		Z	Other (specify)

⁵ Select from the following list of quench water disposition (referring to water drained from the drum after the vessel is vented to the atmosphere).

Code No. Quench Water Disposition

1 Sent to wastewater treatment systemWWTS

2 Sent to sour water stripper

3 Used to make steam

4 Recycled to unit and used as quench water

5 Used as coke cutting water

6 Used as general process water

99 Other (specify)

⁶ Select from the following list of cutting water source and storage/handling method combinations.

Code No.	Cutting Water Source	Code Letter	Cutting Water Storage/Handling
1	Use “tap” water	A	Uncovered gravity settling pond
2	Use process or blowdown water	B	Covered gravity settling pond/tank
3	Use recycled cutting water with “tap” water make-up	C	Mechanical filtration (e.g., centrifugal, filter press) to open storage tank or pond
4	Use recycled cutting water with process or blowdown water make-up	D	Mechanical filtration (e.g., centrifugal, filter press) to covered storage tank or pond
5	Use treated water from sour water stripper	E	Directed to sour water stripper
6	Use treated water from wastewater treatment systemWWTS	F	Directed to wastewater treatment systemWWTS
99	Other (specify)	Z	Other (specify)

⁷ Select the Federal air regulation(s) to which the DCU is subject from the following list of regulations. Select all that apply, but include only regulations to which the DCU is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the DCU is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

3. Provide typical and maximum feed composition in Table 7-2 for each DCU at the facility. You may list Unit ID numbers for multiple DCU in a single column if the DCU have similar feed compositions. If the DCU at the facility have different feed compositions, provide the typical and maximum feed compositions separately for each set of similar DCU.

TABLE 7-2. Delayed Coking Unit Feed Information

Feed Source	DCU ID(s): ____________		DCU ID(s): ____________
	Typical % Feed1	Maximum % Feed2	Typical % Feed1	Maximum % Feed2
Atmospheric towerdistillation column bottoms
Heavy gas oil
Vacuum towerdistillation column bottoms
Other residual gas oil
Recovered materials
- Recovered oil (e.g., slop oil)
- Sludges from crude oil storage tanks
- Sludges from other storage tanks
- Biosolids from wastewater treatment systemWWTS
- Other sludges from wastewater treatment systemWWTS
Other (specify): ____________

Footnotes for Table 7-2:

¹ Typical or average feed composition for DCU. The sum of all values in this column should be 100%.

² Maximum percent of each feed source that can be used in the DCU. The sum of all values in this column is expected to exceed 100%.

SECTION 8. CATALYTIC REFORMING UNITS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 8-1 for each catalytic reforming unit (CRU) at the facility.

TABLE 8-1. Catalytic Reforming Unit Information

Unit ID for CRU

Feed Capacity (bbl/cd)

Operating Pressure (psig)

Hydrogen Production Rate (purified basis) (MMscf/cd at 0°C and 1 atm)

Type of CRU Regeneration (continuous, cyclic, or semi‑regenerative)

Applicable Federal air regulation(s)1

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Average Annual Regeneration Frequency (cyclic and semi-regen units; regeneration cycles/year)2

Average Annual Regeneration Time (hours/year)2

Depressurization /Purge Cycle Vent Disposition/control3

Purge Process Type4

Coke Burn-off Cycle Vent Disposition/control5

Coke Burn-off Cycle Duration per Cycle

Rejuvenation Cycle Vent Disposition/control6

Reduction or Activation Cycle Vent Disposition/control7

Chloriding Agent8

Footnotes for Table 8-1:

¹ Select the Federal air regulation(s) to which the CRU is subject from the following list of regulations. Select all that apply, but include only regulations to which the CRU is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the CRU is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements

2 Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements

99 Other (specify)

² If the unit does not regenerate catalyst at least once a year, estimate the number of cycles based on the interval between cycles. If the interval between cycles varies, you may use the interval between the two most recent cycles. For example, if regeneration occurs once every two years, then the number of cycles per year would be 1 cycle ÷ 2 years = 0.5 cycles per year. The number of hours per year may be estimated by multiplying an average number of hours per cycle by the calculated number of cycles per year.

³ Select from the following list of purge controls.

Code No. Type of Depressurization/Purge Disposition or Control

0 Directly to the atmosphere

1 To fuel gas system, then atmosphere

2 To fuel gas system, then flare, then atmosphere

3 To flare, then atmosphere

4 To process heater or boiler, then atmosphere

95 Management practice or work practice to reduce VOC (specify)

99 Other (specify)

⁴ Select from the following list of purge processes.

Code No. Type of Purge Process

1 Purge by sequential pressurizing/purging with nitrogen

2 Purge using nitrogen and vacuum pump

3 Purge by sequential pressurizing/purging with methane

4 Purge using methane and vacuum pump

99 Other (specify)

⁵ Select from the following list of coke burn-off controls.

Code No. Type of Coke Burn-off Control

1 None

2 Caustic spray injection

3 Packed-bed wet scrubber

4 Tray tower wet scrubber

5 Chlorsorb^TM

94 Management practice or work practice to reduce HCl or chlorine releases (specify)

95 Management practice or work practice to reduce VOC (specify)

96 Management practice or work practice to reduce PM (specify)

99 Other (specify)

⁶ Select from the following list of rejuvenation controls.

Code No. Type of Rejuvenation Controls

0 Directly to the atmosphere

1 To fuel gas system, then atmosphere

2 To fuel gas system, then flare, then atmosphere

3 To flare, then atmosphere

4 To process heater or boiler, then atmosphere

94 Management practice or work practice to reduce HCl or chlorine releases (specify)

95 Management practice or work practice to reduce VOC (specify)

99 Other (specify)

⁷ Select from the following list of reduction or activation controls.

Code No. Type of Reduction or Activation Controls

0 Directly to the atmosphere

1 To fuel gas system, then atmosphere

2 To fuel gas system, then flare, then atmosphere

3 To flare, then atmosphere

4 To process heater or boiler, then atmosphere

94 Management practice or work practice to reduce HCl or chlorine releases (specify)

95 Management practice or work practice to reduce VOC (specify)

99 Other (specify)

⁸ Select from the following list of chloriding agents.

Code No. Type of Chloriding Agent

1 Perchloroethylene

2 Trichloroethene

99 Other (specify)

SECTION 9. SULFUR RECOVERY UNITS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 9-1 for each sulfur recovery unit (SRU) at the facility.

TABLE 9-1. Sulfur Recovery Unit Information

Unit ID for SRU	Sulfur, Sulfur Cake, or H2SO4 Production Capacity (long tons of sulfur/cd)	Type of SRU1	Sulfur Recovery Plant (SRP) ID2	Applicable Federal air regulation(s)3	If subject to State, local, or Tribal air regulation(s), provide the citation(s)	Type of Tail Gas Treatment Unit4	Controls for Primary Sulfur Pit Controls	Primary Sulfur Pit Maintenance Time in 2010 (hr/yr)	SRU Back-up Controls/Reduction Measures5

Footnotes for Table 9-1:

¹ Select from the following list of sulfur recovery units.

Code No. Type of Sulfur Recovery Unit

1 2-stage Claus

2 3-stage Claus

3 4-stage Claus

4 SuperClausSUPERCLAUS®

5 EuroClausEUROCLAUS®

6 SubDewPoint MCRC-SuperClausMCRC^TM-SUPERCLAUS®

7 LoCatLo-Cat®

8 Caustic scrubber

9 Sulfuric acid plant

99 Other (specify)

² For purposes of this collection, multiple SRU are considered part of a single SRP when the units share the same source of sour gas. Sulfur recovery units that receive source gas from completely segregated sour gas treatment systems are considered part of separate SRP.

³ Select the Federal air regulation(s) to which the SRU is subject from the following list of regulations. Select all that apply, but include only regulations to which the SRU is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the SRU is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements

2 Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart J)

4 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

⁴ Select from the following list of tail gas treatment processes used during normal operation of the unit. List all that apply.

Code No. Type of Tail Gas Treatment Unit

0 None

1 Incinerator

2 Flare

3 SCOT unit

4 Beavon/amine

5 Beavon/Stretford®

6 Cansolv®

7 LoCatLo-Cat®

8 Wellman-Lord

99 Other (specify)

⁵ Select from the following list of SRU back-up measures.

Code No. Type of SRU Back-up Control

0 None

1 Dedicated SRU flare

2 General plant flare

3 Divert to other SRU

4 Sulfur shedding (reduce production of high sulfur fuel gas)

98 Management practice or work practice (specify)

99 Other (specify)

SECTION 10. HYDROGEN PLANT VENTS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 10-1 for each hydrogen plant at or under common control of the facility.

TABLE 10-1. Hydrogen Plant and Vent Information

Unit ID for Hydrogen Plant	Hydrogen Production Capacity (purified basis) (MMscf/cd at 0°C and 1 atm)	Type of Hydrogen Production Unit1	Applicable Federal air regulation(s)2	If subject to State, local, or Tribal air regulation(s), provide the citation(s)	Hydrogen Purification Method Used3	Type of Feedstock Used4	Steam Generation Rate (lb/hr)	PSA Purge/Off Gas Flow Rate (scfm)	PSA Purge/Off Gas Disposition5	Reformer Deaerator Vent Flow Rate (scfm)	Other Atmospheric Vent (Yes/No)? (If yes, report in Table 11-1)

Footnotes for Table 10-1:

¹ Select from the following list of hydrogen production units.

Code No. Type of Hydrogen Production Unit

1 Steam-methane reforming

2 Partial oxidation

3 Electrolysis

4 Gasification

99 Other (specify)

² Select the Federal air regulation(s) to which the hydrogen plant is subject from the following list of regulations. Select all that apply, but include only regulations to which the hydrogen plant is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the hydrogen plant is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

99 Other (specify)

³ Select from the following list of hydrogen purification processes.

Code No. Type of Hydrogen Purification Process

1 Pressure-swing adsorption

2 Membrane separation

3 Cryogenic separation

99 Other (specify)

⁴ Select from the following list of feedstocks.

Code No. Type of Hydrogen Production Unit Feedstock

1 Methane

2 Refinery fuel gas

3 Refinery fuel gas augmented with additional methane

99 Other (specify)

⁵ Select from the following list of dispositions for the PSA Purge/Off Gas.

Code No. Disposition of the PSA Purge/Off Gas

1 Used as fuel in the reformer furnace

2 Used as fuel elsewhere in the refinery

3 Sent to flare

4 Vented to atmosphere

99 Other (specify)

SECTION 11. OTHER ATMOSPHERIC VENTS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 11-1 for each “other atmospheric vent” at the facility. “Other atmospheric vents” include any continuous or intermittent process vents located at the facility and under common control other than those vents specifically covered in Sections 5 through 10 of this part (Part II), vents associated with process heater or boiler exhausts, and wastewater vents. “Other atmospheric vents” include distillation towercolumn vents; blowdown systems vents, knock-out pot vents, vacuum ejectors (hot well vents), analyzer vents as well as vents from Merox^TM treatment systems, fuel gas treatment units (if any), catalytic hydrocracking units (if any), asphalt blowing stills, and coke calcining units. The focus of this section is primarily on vents directed directly to the atmosphere during normal operation, and vents recycled to process units, vents directed to a fuel gas system, or vents directed to a flare are not considered “other atmospheric vents”. Also, “other atmospheric vents” do not include pressure relief vents where venting occurs only during upset, startup, or shutdown events or vents associated with storage tanks.

TABLE 11-1. Other Atmospheric Vent Information

Atmospheric Vent ID	Type of Atmospheric Vent1	Unit ID (if applicable) with which the Vent is Associated2	Applicable Federal air regulation(s)3	If subject to State, local, or Tribal air regulation(s), provide the citation(s)	Atmospheric Vent Operating Hours4	Atmospheric Vent Controls5

Footnotes for Table 11-1:

¹ Select from the following list of processes and equipment the option that best describes the type of unit or equipment associated with this vent.

Code No. Type of Other Atmospheric Vent

1 Atmospheric crude distillation column/reflux condenser vent

2 Catalytic cracking unit distillation column/reflux condenser vent

3 Catalytic hydrocracking unit distillation column/reflux condenser vent

4 Catalytic reforming unit distillation column/reflux condenser vent

5 Coking unit distillation column/reflux condenser vent

6 Other distillation column/reflux condenser vent

7 Vacuum distillation column vacuum system exhaust vent

8 Hot well vent/vacuum jet exhaust

9 Other vacuum system exhaust

10 Drier regeneration vent

11 Coke calcining vent

12 Asphalt blowing still vent

13 Blow down system vent

14 Knock-out pot vent

15 Analyzer vent

16 Process tank (including surge control vessels, bottoms receivers, etc.)

99 Other (specify)

² Enter the Unit ID associated with the vent only if the vent is associated with only one process unit. If the vent is in general use or used by multiple process units, leave this question blank. (Any further detail you wish to provide may be included in the “Notes” to this form.

³ Select the Federal air regulation(s) to which the “other atmospheric vent” is subject from the following list of regulations. Select all that apply, but include only regulations to which the vent is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the vent is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 Refinery NSPS (40 CFR part 60, subpart J)

4 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

⁴ Select from the following list of operating scenarios.

Code No. Type of Operation

1 Continuous (operates whenever the process is operating)

2 Intermittent; 4,000 hours per year or more

3 Intermittent; 2,000 hours or more but less than 4,000 hours per year

4 Intermittent; 1,000 hours or more but less than 2,000 hours per year

5 Intermittent; less than 1,000 hours per year

⁵ Select from the following list of control devices. List all that apply.

Code No. Type of Control Device

0 None

11 Fabric/cartridge filter (“baghouse”)

12 Venturi/wet scrubber

13 Electrostatic precipitator (ESP)

14 Wet ESP

24 Wet scrubber/flue gas desulfurization

36 Selective non-catalytic reduction (SNCR)

37 Selective catalytic reduction (SCR)

50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

95 Management practice or work practice to reduce VOC (specify)

96 Management practice or work practice to reduce PM (specify)

97 Management practice or work practice to reduce SO₂ (specify)

98 Management practice or work practice to reduce NO_X (specify)

99 Other (specify)

SECTION 12. FLARES

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 12-1 for each flare at the facility.

TABLE 12-1. Flare Information

Flare ID Number or Description

If the flare is dedicated to one processing unit, enter the Unit ID

Flare Diameter (ft)

Flare release height (ft)

Flare Location (Latitude)

Flare Location (Longitude)

Type of Flare1

Flare Assist Type2

Target Assist Ratio (if applicable)

Type of Flare Pilot or Ignition System3

Applicable Federal air regulation(s)4

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Typical Lower Heating Value of Waste Gas (Btu/scf @ 60°F)

Flare Operating Hours5

Flare Management Plan6

Flare Reduction Measures7

Footnotes for Table 12-1:

¹ Select from the following list of flares.

Code No. Type of Flare

1 Elevated flare

2 Elevated flare, pressure assisted

3 Ground level flare

4 Ground level flare, pressure assisted

99 Other (specify)

² Select from the following list of flare assist types.

Code No. Flare Assist Types

1 Unassisted

2 Steam assisted

3 Air assisted

99 Other (specify)

³ Select from the following list of flare pilot or ignition systems.

Code No. Type of Flare Pilot or Ignition System

1 Continuous pilot flame

2 Spark ignition, every minute regardless of flow

3 Spark ignition, triggered by flow sensor/monitor

99 Other (specify)

⁴ Select the Federal air regulation(s) to which the flare is subject from the following list of regulations. Select all that apply, but include only regulations to which the flare is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the flare is subject).

Code No. Federal Air Regulation

0 None

1 General Provisions (40 CFR part 60, subpart A)

2 General Provisions (40 CFR part 63, subpart A)

3 Refinery NSPS (40 CFR part 60, subpart J)

4 Refinery NSPS (40 CFR part 60, subpart Ja)

99 Other (specify)

⁵ Select from the following list of operating scenarios the option that best describes the operation of the flare.

Code No. Type of Operation

1 Combusts flare gas 4,000 hours per year or more

2 Combusts flare gas 2,000 hours or more but less than 4,000 hours per year

3 Combusts flare gas1,000 hours or more but less than 2,000 hours per year

4 Combusts flare gas less than 1,000 hours per year

5 Combusts flare gas only during startup or shutdown

6 Combusts flare gas only during upsets

7 Combusts flare gas only during startup, shutdown, or upsets

⁶ Select from the following list of components of flare management plans the option that best describes the scope of the flare management for the flare; list all that apply.

Code No. Components of Flare Management Plan

0 Not applicable. Do not have a flare management plan for minimizing flaring from this flare.

1 Simplified P&ID (process and instrument diagram) of flare gas header system

2 Description of streams from process units that can be directed to the flare

3 Procedures to reduce start-up and shutdown releases to the flare

4 Operational procedures for specific process units to reduce releases to the flare during normal process operations

5 Procedures to reduce/minimize purge or sweep gas use

56 Procedure to conduct a root cause and corrective action analysis for flare events exceeding a set SO₂ emission level

67 Procedures to conduct root cause and corrective action analysis for flare events exceeding a set flow rate level

7 Procedures for monitoring flow of gas to the flare

8 Procedures for monitoring flow of gas to the flare

9 Procedures for monitoring Btu of flared gas

910 Procedures for monitoring sulfur content of flared gas

99 Other (specify)

⁷ Select from the following list of flare reduction measures that are specifically used to reduce emissions from the flare. List all that apply.

Code No. Type of Control Device

1 Amine treatment of the flare gas (include only amine treatment used specifically to reduce SO₂ emissions from the flare, not amine treatment systems used for the fuel gas system)

2 Flare gas recovery system, but not designed to recover 100 percent of flare gas during normal operations

3 Flare gas recovery system designed to recover 100 percent of flare gas during normal operations

4 Root cause and corrective action analysis for flare events exceeding a set SO₂ emission level

5 Root cause and corrective action analysis for flare events exceeding a set flow rate level

95 Other management practice or work practice to reduce VOC (specify)

96 Other management practice or work practice to reduce PM (specify)

97 Other management practice or work practice to reduce SO₂ (specify)

98 Other management practice or work practice to reduce NO_X (specify)

99 Other (specify)

SECTION 13. FUEL GAS TREATMENT UNITS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 13-1 for each fuel gas treatment unit at the facility.

TABLE 13-1. Fuel Gas Sulfur Treatment Unit Information

Fuel Gas Treatment Unit ID

Unit ID for each process unit that generates If the fuel Gas treated in the gas treatment unit is dedicated to one process unit, enter the Unit ID for the dedicated process unit

Does this treatment unit receive gas from a coking unit? (Yes/No)

Type of sulfur removal technique(s) used1

Fuel gas flow rate at treatment unit capacity (scfm)

Average fuel gas flow rate into the treatment unit (scfm)

Estimated operating hours in 2010

Types of sulfur compounds in the untreated fuel gas2

Estimated annual average H2S concentration in treated fuel gas exiting the treatment unit (ppmv)

Estimated annual average total sulfur concentration in the treated fuel gas exiting the treatment unit (ppmv)

Applicable SO2 federal air regulation(s) for combustion units that burn the fuel gas3

If subject to State, local, or Tribal air regulation(s),) for SO2 from combustion units that burn the fuel gas, provide the citation(s)

Are there any atmospheric vents in the system (Yes/No)? (If yes, report in Table 11-1)

Footnotes for Table 13-1:

¹ Select from the following list of sulfur removal techniques; list all that apply.

Code No. Type of Sulfur Removal Technique

1 Absorption using MDEA solvent

2 Absorption using MEA solvent

3 Absorption using DEA solvent

4 Absorption using DIPA solvent

5 Absorption using DGA solvent

6 Absorption using blend of amine(s) and TG-10 solvent

7 Flexsorb® process

8 Selexol® process

9 Rectisol® process

10 Sulfinol® process

11 Merox^TM process

12 COS hydrolysis

13 Hot potassium carbonate

14 LoCatLo-Cat®

15 Caustic scrubber

16 Sodium hydrosulfide (NaSH) production process

99 Other (specify)

² Select from the following list of sulfur containing compounds; list all that apply.

Code No. Type of Sulfur Containing Compound

1 Hydrogen sulfide (H₂S)

2 Carbonyl sulfide (COS)

3 Carbon disulfide (CS₂)

4 Mercaptans

5 Thioethers

99 Other (specify)

³ Select the Federal regulation(s) for SO₂ to which the fuel gas combustion units are subject from the following list of regulations. Select all that apply, but include only regulations to which the fuel gas combustion units are subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the combustion units are subject).

Code No. Federal Air Regulation for the Fuel Gas Combustion Units

0 None

1 Refinery NSPS (40 CFR part 60, subpart J)

2 Refinery NSPS (40 CFR part 60, subpart Ja)

3 Steam Generation NSPS (40 CFR part 60, subpart D)

4 Steam Generation NSPS (40 CFR part 60, subpart Db)

5 Steam Generation NSPS (40 CFR part 60, subpart Dc)

99 Other (specify)

SECTION 14. HEAT EXCHANGE (COOLING WATER) SYSTEMS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide information requested in Table 14-1 for each heat exchange (HE) system at the facility.

TABLE 14-1. Cooling Water System Information

HE System ID Number or Description

Unit IDs for Process Units Serviced by Cooling Water System

Cooling Water System Operation – Fluid Pressure1

Cooling Water System VOC/HAP Concentration2

Type of Cooling Water System3

Applicable Federal air regulation(s)4

If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Cooling Water Flow/ Recirculation Rate (gal/min)

Water Make-up Rate (gal/min)

Gas or Chemical Additive/Disinfection Method5

Gas or Chemical Addition Rate Value

Gas or Chemical Addition Rate Units (volume or mass per time)

Chemical Addition Location

Footnotes for Table 14-1:

¹ Select from the following list of cooling water system operations.

Code No. Type of Cooling Water System Operation – Fluid Pressure

1 Services only heat exchangers in which the maximum process fluid pressure is lower than the minimum water pressure

2 Services at least one heat exchanger in which the maximum process fluid pressure is higher than the minimum water pressure

² Select from the following list of descriptions of the cooling water system VOC and HAP concentrations.

Code No. Cooling Water System VOC/HAP Concentration

1 Services only heat exchangers in which the process fluid contains less than 5 wt% VOC and less than 5 wt% organic HAP

2 Services at least one heat exchanger in which the process fluid contains at least 5 wt% VOC but no heat exchangers with 5 wt% or more organic HAP

3 Services at least one heat exchanger in which the process fluid contains at least 5 wt% organic HAP

³ Select from the following list of types of cooling water systems.

Code No. Type of Cooling Water System

1 Once-through cooling water system

2 Natural draft cooling tower

3 Induced draft cooling tower (fans at outlet)

4 Forced draft cooling tower (fans for inlet air)

99 Other (specify)

⁴ Select the Federal air regulation(s) to which the cooling water system is subject from the following list of regulations. Select all that apply, but include only regulations to which the cooling water system is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the cooling water system is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 HON (40 CFR part 63, subpart H) existing source requirements

4 HON (40 CFR part 63, subpart H) new source requirements

99 Other (specify)

⁵ Select from the following list of chemical additives.

Code No. Type of Chemical Additive/Disinfection Method

1 Chlorine from gas cylinders

2 Sodium hypochlorite

3 Calcium hypochlorite

4 Chloramine

5 Ozonation

6 UV disinfection

99 Other (specify)

SECTION 15. WASTEWATER COLLECTION AND TREATMENT

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide the following information for the facility.

a. What is the daily average wastewater treatment systemWWTS flow rate (orfor all WWTS at the facility (or average discharge rate if wastewater is treated off-site)?

b. What iswas the Total Annual Benzene (TAB) quantity for the facility in 2010?

c. Indicate the Benzene Waste Operations NESHAP (BWON) (40 CFR part 61, subpart FF) compliance option selected by the facility.

1 2 Mg/yr

2 6 BQ

3 Not applicable because original TAB < 10 Mg/yr

4 Other (specify)

3. Please provide the following information about wastewater generated from tank drawdowns:

a. Estimated quantity of wastewater generated via tank draw downs in 2010?: ___ gallons

b. Quantity of benzene in wastewater generated via tank draw downs in 2010?: ___ lbs

c. Average VOC content of wastewater generated via tank draw downs in 2010?: ___ ppmw

4. Complete Table 15-1 to indicate the wastewater treatment processes used for each wastewater treatment systemWWTS (identified in Part 1, Question 16) at the facility and the applicable air regulations for each selected unit.

TABLE 15-1. Wastewater Treatment Processes

Wastewater Treatment and Collection System ID	Type of Wastewater Treatment Process1	For Steam and Sour Water Strippers, also Provide Average Steam Usage Rates in 2010 (lb/hr)	Applicable Federal air regulation(s)2	If subject to State, local, or Tribal air regulation(s), provide the citation(s)

Footnotes for Table 15-1:

¹ Select from the following list of wastewater treatment processes.

Code No. Wastewater Treatment Process

0 None (no on-site wastewater treatment unitsprocesses present at facility)

1 Benzene/VOC steam stripper

2 Oil-water separator

3 Dissolved air/gas flotation

4 Equalization basin/tank

5 Neutralization basin/tank

6 Activated-sludge biological treatment unit

7 Aerated surface impoundment

8 Non-aerated surface impoundment

9 Anaerobic sludge digester

10 Aerobic sludge digester

11 Other biological treatment unit (trickling filter, rotating biological contactor)

12 Primary clarifier

13 Secondary clarifier

14 Sour water stripper

² Select the Federal air regulation(s) to which the selected wastewater treatment unitprocess is subject from the following list of regulations. Select all that apply, but include only regulations to which the wastewater treatment unitprocess is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the wastewater treatment unitprocess is subject).

Code No. Compliance ApplicabilityFederal Air Regulation

0 The unit is not subject to any air standards.

1 The unit is subject to 0 None

1 BWON (40 CFR part 61, subpart FF)), but exempted from control requirements.

2 The unit is subject to BWON (40 CFR part 61, subpart FF) control requirements.

3 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

4 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

5 HON (40 CFR part 63, subpart H) existing source requirements

6 HON (40 CFR part 63, subpart H) new source requirements

7 Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)

99 Other (specify)

5. Please provide the information requested in Table 15-2 for each process unit that routinely generates wastewater. Please provide your best estimate based on available information; no additional testing is required to complete this request.

TABLE 15-2. Wastewater Generation Information

Process Unit ID	Average wastewater generation rate (gallons/operating day)	Average benzene concentration (ppmw)	Average concentration of organic HAP (ppmw)	Average VOC concentration (ppmw)

6. Please provide information requested in Table 15-3 for each “wastewater vent” at the facility. “Wastewater vents” include atmospheric vents associated with wastewater drain systems (including junction box vents) and gases purged from covered wastewater treatment systemsWWTS.

TABLE 15-3. Wastewater Vent Information

Atmospheric Vent ID	Description of Atmospheric Vent1	Applicable Federal air regulation(s)2	If subject to State, local, or Tribal air regulation(s), provide the citation(s)	Atmospheric Vent Operating Hours3	Atmospheric Vent Controls4

Footnotes for Table 15-3:

¹ Select from the following list of wastewater vents the option that best describes this vent.

Code No. Type of Unit/Equipment Associated with Vent

1 Drain system vent (including junction box vents)

2 Vent from wastewater treatment unitWWTU

99 Other (specify)

² Select the Federal air regulation(s) to which the selected wastewater vent is subject from the following list of regulations. Select all that apply, but include only regulations to which the wastewater vent is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the wastewater treatment unitvent is subject).

Code No. Compliance ApplicabilityFederal Air Regulation

0 The vent is not subject to any air standards.

1 The vent is subject to 0 None

1 BWON (40 CFR part 61, subpart FF)), but exempted from control requirements.

2 The vent is subject to BWON (40 CFR part 61, subpart FF) control requirements.

3 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements

4 Refinery MACT (40 CFR part 63, subpart CC) new source requirements

5 HON (40 CFR part 63, subpart H) existing source requirements

6 HON (40 CFR part 63, subpart H) new source requirements

7 Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)

99 Other (specify)

³ Select from the following list of operating scenarios.

Code No. Type of Operation

1 Continuous (operates whenever the wastewater treatment process is operating)

2 Intermittent; 4,000 hours per year or more

3 Intermittent; 2,000 hours or more but less than 4,000 hours per year

4 Intermittent; 1,000 hours or more but less than 2,000 hours per year

5 Intermittent; less than 1,000 hours per year

⁴ Select from the following list of control devices. List all that apply.

Code No. Type of Control Device

0 None

1 Water seal (e.g., for a junction box vent)

50 Thermal or catalytic incinerator/oxidizer

51 Condenser

53 Single carbon adsorber canister

54 Two carbon adsorber canisters in series

95 Management practice or work practice to reduce VOC (specify)

99 Other (specify)

SECTION 16. PRODUCT LOADING OPERATIONS

1. Facility ID number (EPA will provide this number): ______________________

2. Please provide the following information regarding products transported by marine vessels (tank ships and barges).

a. Select the option that best describes the marine vessel loading operations that are associated with the refinery’s shipments via marine vessels (as reported in Question 15 of Part I of this ICR).

0 None. There are no shipments made via marine vessels

1 Marine vessel loading operations are contiguous with the refinery.

2 Marine vessel loading operations are conducted on-shore but are not contiguous with the refinery.

3 Marine vessel loading operations are conducted off-shore (i.e., more than 0.5 miles from the coast).

b. For the marine vessel loading operations associated with the refinery’s shipments, are there vessels or barges loaded that contain non-segregated ballast water?

Yes No

c. If Yes, is non-segregated ballasting water (from either on-site or off-site marine vessel loading operations) treated in the refinery’s wastewater treatment plantWWTS?

Yes No

3. Please provide the following information regarding products transported by tank truck or rail car.

a. Select the option that best describes the tank truck loading operations that are associated with the refinery’s shipments via tank truck (as reported in Question 15 of Part I of this ICR).

0 None. There are no shipments made via tank truck

1 Tank truck loading operations are conducted on-site (i.e., considered part of the refinery facility).

2 Tank truck loading operations are conducted off-site (not part of the contiguous refinery facility).

b. Select the option that best describes the rail car operations that are associated with the refinery’s shipments via rail truck (as reported in Question 15 of Part I of this ICR).

0 None. There are no shipments made via rail car

1 Rail car loading operations are conducted on-site (i.e., considered part of the refinery facility).

2 Rail car loading operations are conducted off-site (not part of the contiguous refinery facility).

4. Please provide the information requested in Table 16-1 for each fixed location product loading operation (e.g., dock, loading rack) at the facility (i.e., those considered part of the refinery facility).

TABLE 16-1. Product Loading Information

Unit ID for loading operation	Type of vessel loaded1	Capacity loading throughput (gal/yr)	Applicable Federal air regulation(s)2	If subject to State, local, or Tribal air regulation(s), provide the citation(s)	Typical annual operating hours (hr/yr)	Does the facility or parent company own the vessels being loaded? (Yes/No)	Type of control device or control technique3

Footnotes for Table 16-1:

¹ Select from the following list of vessels. List all that apply.

Code No. Type of Vessel

1 Tank ship

2 Barge

3 Truck/tank truck

4 Rail car

5 Containers with capacity less than 250 gallons

6 Containers with capacity from 250 gallons to less than 1,000 gallons

7 Containers with capacity from 1,000 gallons to less than 20,000 gallons

8 Containers with capacity greater than or equal to 20,000 gallons

99 Other (specify)

² Select the Federal air regulation(s) to which the loading/unloading location operation is subject from the following list of regulations. Select all that apply, but include only regulations to which the loading/unloading location operation is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the loading/unloading location operation is subject).

Code No. Federal Air Regulation

0 None

1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements

2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 HON (40 CFR part 63, subpart H) existing source requirements

4 HON (40 CFR part 63, subpart H) new source requirements

5 Gasoline Loading NSPS (40 CFR part 60, subpart XX)

6 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements

7 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements

8 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements

9 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements

99 Other (specify)

³ Select from the following list of control devices and techniques; list all that apply.

Code No. Type of Control

0 None

50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

55 Flare

80 Submerged loading

82 Bottom loading

83 Vapor balancing system

95 Other management practice or work practice to reduce VOC (specify)

99 Other (specify)

SECTION 17. SOLID WASTE MANAGEMENT

1. Facility ID number (EPA will provide this number): ______________________

2. Describe any pollution prevention methods used to reduce the quantity of solid waste disposed of on-site and the percent and/or quantity of waste reduced (e.g., reduced sludge disposal from tank cleanings by 80% by recycling oily sludges to delayed coking unit).

3. Please provide information requested in Table 17-1 for each active landfill, land application unit, waste pile, or composting operation at the facility.

TABLE 17-1. Solid Waste Management Unit Information

Solid Waste Management ID Number	Type of Solid Waste Management Unit1	Description of Waste Managed in Unit	Area of Solid Waste Management Unit (m2)	Capacity of Solid Waste Management Unit (m3)	Applicable Federal air regulation(s)2	If subject to State, local, or Tribal air regulation(s), provide the citation(s)	Waste Application or Disposal Rate (m3/yr)	Bulk Density of Waste Applied or Disposed (g/cm3)	Pretreatment or Control Methods Used3

Footnotes for Table 17-1:

¹ Select from the following list of solid waste management system types.

Code No. Type of Solid Waste Management Unit

1 Hazardous waste (RCRA Subtitle C) landfill

2 Industrial waste (RCRA Subtitle D) landfill

3 Land application unit

4 Waste pile

5 Composting operation

² Select the Federal air regulation(s) to which the solid waste management unit is subject from the following list of regulations. Select all that apply, but include only regulations to which the solid waste management unit is subject according to the applicability of the regulation (i.e., do not select regulations that are referenced from the regulation(s) to which the solid waste management unit is subject).

Code No. Federal Air Regulation

0 None

99 Other (specify)

³ Select from the following list of solid waste pretreatment or control methods. List all that apply.

Code No. Type of Pretreatment or Control Method

1 Dewatering

2 Fixation (solidification/stabilization)

3 Steam stripping

4 Water for dust suppression

5 Oil for dust suppression

6 Foam for dust suppression

7 Leachate collection

8 Landfill gas collection

99 Other (specify)

PART III. INCIDENCE REPORTSNON-ROUTINE EMISSIONS

1. Complete the following table for each non-routine emissions event during 2010 where the emissions exceeded normal emissions, normal controls were bypassed, or the effectiveness of the normal controls was reduced.

Date of release	Type of release (startup/shutdown; equipment or component malfunction)	Description of release event	Process units associated with the release	Duration of the release event (hours)	Pollutant name	Pollutant CAS No. or Pollutant Code	Quantity of pollutant released (lb)	Quantity determination method (measured or calculated)

2. Complete the following table for each flare, air emission, or odor complaint received in 2010.

Date of complaint	Complainant name	Complainant contact information	Substance of complaint

PART IV. COST DATA (Optional)

For any air pollution control devices (APCD),Cost data for air pollution control devices (APCD), process changes, equipment changes/upgrades, and management or work practices implemented within the last 5 years are optionally requested. While you are not required to complete this part, EPA highly recommends that you provide available cost data so that we can more accurately determine the compliance costs of control alternatives that may be assessed during the review of the refinery emission standards.

For any APCD, process changes, equipment changes/upgrades, and management or work practices implemented within the last 5 years for which you have readily available cost information, please provide those costs as described in this part. Include only process changes, equipment changes/upgrades, and management or work practices implemented to reduce emissions. Do not include projects needed to meet environmentally driven product specifications (e.g., low sulfur diesel projects, ethanol blending projects, and gasoline reformulation projects to remove MTBE). If you wish to provide more detail than requested in Table 2 (e.g., you wish to itemize total capital costs), you may provide your information in a separate spreadsheet. If you know an approximate cost for a control technique but do not have the level of detail requested in the tables, please provide the approximate cost and your best estimate of which of the components in the appropriate table were factored into that approximate cost (in lieu of completing the applicable table for that control technique).

If any of the data requested in this part is considered CBI, follow the instructions in the section “Submitting CBI” under the heading “How to Submit Your Survey Response” in the introduction to this enclosure.

1. Please complete Table 1 for any new APCD installed in the last 5 years on any of the process units or other emissions sources described in Part II for which you have readily available information. The EPA is particularly interested in costs of the following APCD:

• Electrostatic precipitators

• Wet scrubbers

• Baghouses

• SCR/SNCR for NO_X control

• Steam strippers

• Carbon adsorbers

• Thermal/catalytic oxidizers

• Flares

2. Please complete Table 2 for any process changes or equipment changes/upgrades performed in the last 5 years to any of the process units or other emissions sources described in Part II for which you have readily available information. The EPA is particularly interested in costs of the following process changes or equipment changes/upgrades:

• Installation of low/ultra-low NO_X burners

• Installation of air preheat for process heaters/boilers

• Catalyst additives for SO_X control from FCCU

• Combustion promoters or catalyst additives for NO_X control from FCCU

• Amine treatment systems

• Floating roofs, rim seals, and fittings seals on storage vessels

• Installation of geodesic dome for external floating roof tank

• Installation of guidepole sleeves/wipers or other tank fitting gaskets

3. Please provide any readily available costs for other techniques used at your refinery to reduce emissions of any pollutant. EPA is particularly interested in techniques that are not already included in Federal regulations. Provide as much detail in your cost estimate as possible (e.g., unit ID for the unit from which emissions are reduced, amount of time needed to complete the technique (labor costs), cost of any equipment needed on a temporary basis, cost of any monitoring devices needed to indicate when action is needed or to measure progress). Types of techniques that EPA is particularly interested in include:

• Use of a portable or temporary control device (e.g., for degassing of storage tanks)

• Monitoring devices (e.g., monitors that record the duration and quantity of compounds released from a PRD)

• Pollution prevention techniques

• Energy management programs identified in Part II, Section 1

• Other management practices or work practices that you identified in Part II

Table 1. Cost Data for APCD¹APCD (Optional)¹

APCD ID

Unit ID associated with this APCD

APCD Type2

APCD Size3

New or retrofit APCD?4

Year of APCD installation

Expected APCD equipment life (yrs)

Demolition Cost ofcost for previous APCD, if any ($)

CAPITAL COSTS

ANNUAL OPERATING COSTS10

Base year for capital costs

Purchased equipment costs ($)5

Installation costs ($)8

Total Installed Cost of APCD9

Base year for operating costs

Operating labor ($)

Maintenance labor ($)

Utilities ($)

Waste disposal ($)

Supplies and parts13

Monitoring, recordkeeping, & reporting ($/yr)

Other annual costs (itemize)14

Total annual operating & maintenance cost 15

Primary equipment ( $)6

Auxiliary equipment ($)7

Instrumentation and monitors ($)

Sales tax and freight ($)

Total purchased equipment costs ($)

Electricity

Water

Steam

Natural gas

Liquid chemicals

Solid chemicals

Compressed Air

Other (specify)

Total utilities cost ($/yr)12

Description of most significant part

Number of years between replacement

Replacement cost (with installation) ($)

hr/yr

$/yr

hr/yr

$/yr

kWh/yr

$/kWh

gal/yr

$/gal

lb/yr

$/lb

scf/yr

$/scf

gal/yr

$/gal

lb/yr

$/lb

scf/yr

$/scf

amt/yr11

$/amt

amt/yr11

$/yr

1

2

3

¹ Columns that are sums of other columns are shaded gray. If you do not have the all detail requested but you do have an estimate for a subtotal, enter the subtotal in the appropriate shaded column and provide as much detail or explanation as you have available.

² See list following the last footnote for codes corresponding to APCD types.

³ Provide the numerical value as well as the units (e.g. scfm).

⁴ If the APCD was installed at the time the process unit or emission source was constructed, enter “New.” If the APCD was installed after the process unit or emission source began operation, enter “Retrofit.”

⁵ Sum of equipment, auxiliary equipment, instrumentation/monitors, sales tax, and freight.

⁶ Primary equipment is the APCD itself. Examples include SCR with catalyst, carbon adsorber with carbon, packed scrubber tower with packing, fabric filter with bags, ESP, and steam stripper column with nozzles, manholes, and trays.

⁷ Examples of auxiliary equipment include fans, pumps, motors, duct work, stacks, flame arrestors, and condensers and decanters for steam strippers.

⁸ Include all installation costs (e.g., foundations, supports, handling/erection, electrical, piping, insulation for ductwork and piping, painting, engineering, construction and field expenses, contractor fees, start-up, and testing.

⁹ Sum of purchased equipment cost and installation cost.

¹⁰ Provide operating costs for the last 12 month period (calendar or fiscal year) for which the refinery has data.

¹¹ Specify units.

¹² For each utility that applies to this APCD, multiply the consumption rate (the first column for that utility) by the unit cost (the second column for that utility) to get the annual cost for each utility. Add the individual utility annual costs to get the total utilities cost.

¹³ Include the most significant item of the major supplies and replacement parts; examples include catalyst for SCR and catalytic incinerators, bags for fabric filters, and carbon for carbon adsorbers.

¹⁴ An example might be catalyst regeneration. Note that this question is not asking for costs of maintenance materials, capital recovery, overhead, administration, property taxes, and insurance because EPA will estimate these costs as a function of other costs.

¹⁵ Sum of annual costs for operating labor; maintenance labor; utilities; waste disposal; major supplies and replacement parts that are needed once per year or more frequently; monitoring, recordkeeping, and reporting; and any other items included under “other annual costs.”

Code No. Type of APCD

1 Amine treatment (e.g., installation of new amine treatment unit)

2 Caustic spray injection

3 Packed-bed wet scrubber

4 Tray tower wet scrubber

5 Chlorsorb^TM

11 Fabric/cartridge filter (“baghouse”)

12 Venturi/wet scrubber

13 Electrostatic precipitator (ESP)

14 Wet ESP

15 Tertiary cyclone

24 Wet scrubber/flue gas desulfurization

25 Spray dryer absorber

36 Selective non-catalytic reduction (SNCR)

37 Selective catalytic reduction (SCR)

42 LoTOX® scrubber

50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

53 Single carbon adsorber canister

54 Two carbon adsorber canisters in series

55 Flare

56 Portable internal combustion engine

57 Portable thermal oxidizer

58 Portable condensation system

59 Permanent onsite control device for storage tanks

60 Flare gas recovery

83 Vapor balancing system

99 Other (specify)

Table 2. Cost Data for Process and Equipment Changes (Optional)

Unit ID	Process or equipment change type1	Process or equipment change description2	Year of process or equipment change	Number of days process shut down in order to make the change (days of lost production)3	Total capital cost, $4	Change in total annual operating cost, $/yr5	Emission reductions achieved (if quantified)6

¹ See list following the last footnote for codes corresponding to process or equipment changes. If none of the codes describe your process or equipment change, enter “99” and specify the type of process or equipment change.

² Describe the process or equipment change. Be as descriptive as possible. For example, for installation of low NO_X or ultra low NO_X burners for a process heater, note the number of new burners, their sizes, and the fuel options (e.g., fuel gas, oil).

³ Enter number of days of lost production required to implement the process or equipment change. If the change occurred during scheduled downtime that would have occurred regardless of the process or equipment change, then do not include the scheduled downtime. Only the days of lost production that can be specifically attributed to the process or equipment change are of interest.

⁴ Please distinguish between one-time capital and annual operating costs where appropriate. If a breakdown of the specific capital or annual cost items is available, please provide as a separate attachment.

⁵ Provide changes in annual operating costs (if estimated). Otherwise, leave blank. Include annual operating costs that are an increase to prior operating costs (e.g., additional operating costs due to installation of low NO_X burners). If the process or equipment change resulted in decreased annual operating costs, then indicate the cost decrease as a negative number.

⁶ Describe the air pollutants affected and emissions reduction achieved. Indicate the basis for emissions reduction reported (e.g., air emissions testing before and after modification). You may provide this information as a separate attachment to your response if you wish.

Code No. Type of Process or Equipment Change

1 Amine treatment (change in existing amine treatment system operation)

21 H₂S limit in fuel gas

22 TRS limit in fuel gas

23 Low sulfur distillate or heavy gas oil

26 DeSOx catalyst, meeting 50/25 ppmv SO₂ limit

27 DeSOx catalyst, meeting 20 lb/ton coke burn-off, but not 50/25 ppmv SO₂ limit

28 Low sulfur feed (0.3 wt% or less) feed

31 (External) flue gas recirculation

32 Staged air low NO_X burner

33 Staged fuel low NO_X burner

34 Ultra low NO_X burner (high fraction staged fuel) (ULNB)

35 “Next generation” low NO_X burner (ULNB with internal gas recirculation)

39 High-efficiency regenerator

40 Low NO_X combustion additives to replace Pt-based combustion additives

41 Other low NO_X catalyst additives

70 Water seal

71 Fixed seal

72 Hard piping

80 Submerged loading (i.e., loading from the top of the vessel; the fill pipe extends almost to the bottom of the vessel such that it is below the liquid level during most of the filling)

82 Bottom loading

99 Other (specify)

PART V. EMISSIONS MONITORING AND SOURCE TEST DATA

In this section, emissions test data are requested. Please satisfy this request as completely as possible from existing information. No additional monitoring or emission testing is required by your company to respond to the data request in this section. FourFive types of existing emissions data are requested: 1) source test data, 2) qualified CEMS data, 3) qualified CMS data, 4) biological treatment units data, and 45) ambient or remote sensing data. The emissions test data collected will provide valuable information on current emissions levels and will allow EPA to consider variability in emissions from refinery to refinery (and over time for a given emission unit and pollutant) in reviewing and setting emission standards. When submitting test data, EPA is requesting full test reports with field and lab data sheets and example calculations, not just summary reports.

If any of the data requested in this part is considered CBI, follow the instructions in the section “Submitting CBI” under the heading “How to Submit Your Survey Response” in the introduction to this enclosure.

1. Source Tests: Provide any existing emissions test reports from emissions tests conducted on any of the processes or emission points included in Part II, Sections 35 through 1716 and for boilers included in Table 1-2 (of Part II) on or after January 1, 2005. Electronic (pdf) or hard copies are acceptable. Include the summary portion of the report and any appendices showing run-by-run test parameters, method detection limits, laboratory data, production data, example calculations, etc. If you have multiple tests for one pollutant from one process unit, submit only the most recent tests for that pollutant and process unit. (We are only requesting a maximum of the three most recent tests per unit for one pollutant, but you may submit more than threeone test, particularly if additional tests reflect the effect of different operating conditions or equipment configurations.)

In addition, complete the source test log shown in Attachment 1below for each source test you submit. (Electronic copies of this table can be downloaded from the ICR website (https://refineryicr.rti.org).) Note that the information requested in the summary table includes:

(A(A) test number (use any unique identifier you choose for each test)

(B) APCD type (if not clear from the test report),

(BC) a description of how the configuration of the emission unit, combustion controls, collection system, or APCD has changed since the test was conducted, if applicable,

(CD) any notes specific to that emissions test (optional), and

(DE) how often you are required to test the emission unit (optional).

2. Qualified CEMS Data: Provide qualified CEMS data for PM, CO, NO_X, SO₂, O₂, and THC CEMS on any of the processes or emission points included in Part II, Sections 25 through 17.16 and for boilers included in Table 1-2 (of Part II). Report daily averages for each day in 2010 using the Microsoft® Excel CEMS Daily Template; an example template is shown in Attachment 2. The Excel templates are specific to each pollutant and type of unit, and each template is designed to accommodate data from one CEMS (including oxygen data). Electronic copies of the template can be downloaded from available on the ICR website (https://refineryicr.rti.org). A separate Excel CEMS Daily Template should be completed for each pollutant and type of unit.

Qualified CEMS data include: data from a PM CEMS that meets Performance Specification 11 or 15; data from a CO CEMS that meets Performance Specification 4; data from a SO₂ and/or NO_X CEMS that meets Performance Specification 2; data from a THC CEMS that meets Performance Specification 8A; or data from any CEMS meeting the accuracy and ongoing QA/QC requirements of 40 CFR part 60, Appendix F. Use only qualified CEMS data and determine the daily averages using by averaging the hourly CEMS values for each hour for which qualified CEMS data are available. If there are no qualified CEMS data for any hour in a given day, report “ND” (no data) for that daily average.

In addition, complete the log shown below for each set of CEMS data you submit. (Electronic copies of this table can be downloaded from the ICR website (https://refineryicr.rti.org).) Note that the information requested in the summary table includes:

(A) ID number for the set of CEMS data (use a unique identifier for each set of data; each identifier should include the pollutant monitored) and

(B) APCD type.

You may complete other fields in the log if you wish to provide additional data.

3. Qualified CMS Data: Provide qualified CMS data for H₂S, reduced sulfur, total reduced sulfur, hydrocarbon, and Btu CMS on fuel gas or flare gas lines. Only CMS data listed in the previous sentence are requested; no other type of CMS data are requested. Report daily averages for each day in 2010 using the Microsoft® Excel CMS Daily Template; an example template is shown in Attachment 2. The Excel templates are specific to each pollutant and type of unit, and each template is designed to accommodate data from one CMS. Electronic copies of the template can be downloaded from available on the ICR website (https://refineryicr.rti.org). A separate Excel CMS Daily Template should be completed for each pollutant and type of unit.

Qualified CMS data include: data from a H₂S CMS that meets Performance Specification 7; data from a reduced sulfur or total reduced sulfur CMS that meets Performance Specification 7; data from a hydrocarbon or Btu CMS (gas composition monitor) that meets Performance Specification 5; data from any CMS meeting the accuracy and ongoing QA/QC requirements of 40 CFR part 60, Appendix F; or data from any CMS for that has been calibrated per the manufacturer’s specifications within the past 12 months and is operated and maintained (including on-going QA/QC requirements) according to the manufacturer’s specifications. Use only qualified CMS data and determine the daily averages using by averaging the hourly CMS values for each hour for which qualified CMS data are available. If there are no qualified CMS data for any hour in a given day, report “ND” (no data) for that daily average.

In addition, complete the log shown below for each set of CMS data you submit. (Electronic copies of this table can be downloaded from the ICR website (https://refineryicr.rti.org).) Note that the information requested in the summary table includes:

(A) ID number for the set of CMS data (use a unique identifier for each set of data; each identifier should include the parameter monitored) and

(B) APCD type.

You may complete other fields in the log if you wish to provide additional data.

4. Biological treatment unit: If you performed a biodegradation rate test or a complete mixing test on a biological treatment unit on or after January 1, 2000, provide a complete copy of the test report. (See the guidance provided on the ICR website (https://refineryicr.rti.org) for more information about biodegradation rate tests and complete mixing tests.)

5. Ambient and remote sensing: If you conducted ambient air monitoring or conducted a DIAL, SOF, or similar test at or around your facility on or after January 1, 2000, provide a complete copy of the test report for these studies.

6. Equipment leak correlations: If you developed site-specific correlations for equipment leaks at your facility and you use those correlations to estimate emissions from equipment leaks, provide a complete copy of the report or other documentation describing the testing and development of the correlations.

Attachment 1 Log of Source Tests Provided

PART V. LOG OF SOURCE TESTS AND MONITORING DATA PROVIDED

Test Number1or Monitoring Data ID1	Unit ID(s)	If the APCD type(s) is not clear from the test report, enter the APCD type(s)	Configuration changes2	OPTIONAL: Process testing notes3	OPTIONAL: How often are you required to perform testing of this emission unit for the pollutants listed?	OPTIONAL: Approximate cost per test, $

¹ Assign a testunique ID or number to each test report, CEMS data set, or CMS data set that you provide so that EPA can match your responses in this log to the correct test report. or monitoring data. For CEMS data and CMS data, the identifier should include the pollutant or other parameter being monitored.

² If the configuration of the emission unit, combustion controls, collection system, or APCD changed since the test was conducted, describe the changes. If there are no configuration changes, enter “N/A”

³ Use this column for notes or if helpful to specify the emission points tested (e.g., for equipment with multiple emission points, where only selected emission points/vents were tested)

Attachment 2. Example CEMS Table

NO_X CEMS DATA

Emission Unit ID:

CEMS Date (mm/dd/ yyyy)	Daily production/ throughput rate (value)1	Daily production/ throughput rate (units)	1-day average emission value for NOX (as measured by the CEMS)	Unit of measure recorded by CEMS	O2 content (%)	Moisture content (%)	Data average affected by a startup, shutdown, or other event?1	OPTIONAL: Emission value (ppmvd @ 7% O2)	OPTIONAL: 1-day average emission value for NOX in other units
									1-day average emission value for NOX, corrected for %O2 (value)	1-day average emission value for NOX, (units)	% O2 correction (by volume, dry basis)
01/01/2010
01/02/2010
01/03/2010
01/04/2010
01/05/2010
01/06/2010
01/07/2010
01/08/2010
……
12/25/2010
12/26/2010
12/27/2010
12/28/2010
12/29/2010
12/30/2010
12/31/2010

¹ Provide the process production rate, heat input rate, coke burn-off rate or other normalizing factor appropriate for the type of process.

² If no, leave blank. If yes, respond “startup,” “shutdown,” or “event”; if you respond “event” please include a brief description of the event.

1 For purposes of this information request, “facility” is defined as any stationary source or group of stationary sources located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control.

2Latitude measure in decimal degrees of the angular distance on a meridian north or south of the equator. Positive (+) data point for North America. Example: +78.123456. For point sources, this represents the center of the source; for fugitive sources, this is the southwest corner if the fugitive angle is zero or the western most corner if the fugitive angle is greater than zero. Longitude measure in decimal degrees of the angular distance on a meridian east or west of the prime meridian. Negative (-) data point for North America. Example: -123.234561. For point sources this represents the center of the source; for fugitive sources, this is the southwest corner if the fugitive angle is zero, or the western most corner if the fugitive angle is greater than zero.

4