### Component 1 Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



## Petroleum Refinery Emissions Information Collection

PART I: GENERAL F ACILITY 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 facility 1 

### report in EIA-820 the combined pr ocessing/production capacities for

refining plants that are not contiguously located? Yes No

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

facility: _________________________________________________________________

_________________________________________________________________________

________________________________________________________________________ 3. Complete street address of f acility (physical location): ____________________________

_________________________________________________________________________

_________________________________________________________________________ 4. Provide mailing address if different: ___________________________________________

_________________________________________________________________________

_________________________________________________________________________ 5. Name and title of contact(s) able to answ er technical questions about the completed

survey: __________________________________________________________________

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

and e-mail address(es): _____________________________________________________

7. Name of legal owner of facility: ______________________________________________

_________________________________________________________________________

_________________________________________________________________________

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.Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 2 _________________________________________________________________________ 8. Name of legal operator of facility, if different from legal owner: ____________________

_________________________________________________________________________

_________________________________________________________________________ 9. Address of ____ legal owner or ____ operator: __________________________________

_________________________________________________________________________

_________________________________________________________________________

_________________________________________________________________________ 10. Dun 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 cor porate entity or joint venture? Yes No

13b. If 13a is Yes , is the facility operated under a jo int 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 pa rtner with 50% or greater ownership:

Partner name ______________ Percent ow nership ______% No. employees ______

Partner name ______________ Percent ow nership ______% 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 th e parent organization (independent sources of capital, different Boards of Directors, etc.).

The parent organization provi des some financial support.

Operations of the parent organization an d 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 refineryForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 3 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 availabl e 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 refine ry (or its corporate holdings ), report the transportation method as tank ship or tank truck, respectively, ra ther than reporting this quantity as “% shipped by pipeline.” Report under “% shi pped 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 bbl) 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 underForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 4 Product/Refinery Output Cumulative
2010
Production (1,000 bbl) 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 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 5 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 c overed by the processes listed. If 2010 throughputs are not representa tive of normal operations ( e.g. , plant idled temporarily for economic reasons, change of ownership, or fire , etc.), add a note desc ribing 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, use a unique Unit ID for each process unit. When possible, use the same identifier from your permit or emissions inventory.

Unit ID Process Type 1 Unit Throughput Capacity (bbl/cd) 2 Unit Actual Throughput (bbl/cd) 2

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, incl ude both fresh and recycle feed.
For alkylation through oxygenate plants, coke calcining, and chemical production (process type codes 22 through 36 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 ar omatics produced from various separation processes after

catalytic reforming.
For hydrogen plants, throughput units are million standard cubic feet per calend ar day (MMcf/cd); use 32°F (0°C) and 1

atmosphere as “standard conditions” for H 2 plants.
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 fuel gas treatment, “throughput” is the quantity of fuel ga s 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 loading operations, “throughput” is the quantity of material loaded.
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 se parate WWTS, but you are not required to do so.Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 6 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 H 2 SO 4 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 41 Ethylene dichloride production 42 Ethylene dibromide production 43 Propylene production 44 Acrylonitrile production 45 Other petrochemical or organic chemical production (specify chemical) 50 Product loading – Marine vessel loading 51 Product loading – Truck/tank truck loading 52 Product loading – Rail car loading 53 Product loading – Container/other loading

60 Wastewater collection an d treatment system (WWTS) 99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 7 

### 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 fu el 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 Oil 1 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 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; mo re 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 NoForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 8 If Yes : Provide a brief description of the ke y 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 ener gy recovery turbines
and waste heat boilers used on process unit exhaust lines.

TABLE 1-2. Electricity and Steam Generation InformationGeneration Unit IDUnit Description1Primary Fuel2Secondary Fuel2Energy Efficiency Measures3Air preheat use4Typical air preheat temperaturewhen used (°F)Generation Unit Type5 Electricity
Generation Steam GenerationCapacity of Unit (MW)Disposition of electricity6Boiler Heat Input Capacity(MMBtu/hr)Steam Generating Capacity(lb/hr)Pressure of Steam (psia)Disposition of steam7Percent Steam to Blowdown8



### 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 absoluteForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 9 1 

### For waste heat boiler, list pro cess 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 na tural 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 wi th 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 retu rn condensate (hot water) to boiler) 10 Steam expansion turbines (to recover ener gy 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 descri ptions 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 timeForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 10 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

7 

### 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.

8 

### If the exact percentage is unknown, and you ar e unable to provide a reasonable estimate,

answer “Unknown.”Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



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

TABLE 1-3. Steam Consum ption by Process Unit

Unit ID Steam consumption for the processing unit in 2010 (tons/yr)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 12 

### SECTION 2. PROCESS HEATERS

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 uni t identified in Part I, Question 16.

TABLE 2-1. Process Heater General InformationProcess Heater IDUnit ID for process unit served byprocess heaterProcess heater construction type1Process heater draft type2Is the process heater designed to be cofired? (Yes/No)Rated heat input capacity (MMBtu/hr)Average heat input rate in 2010(MMBtu/hr)Total operating hours in 2010 (hr)Air preheat use3Typical air preheat temperature whenused (°F)Other energy efficiency measures4Primary fuel5Percent of total operating hoursprocess heater fired with primary fuelin 2010Secondary fuel5Percent of total operating hoursprocess heater fired with secondaryfuel in 2010Operating hours while operating lessthan 25% of rated capacity in 2010(hr)Operating hours while operating at 25to 50% of rated capacity in 2010 (hr)Applicable Federal air regulation(s)6If subject to State, local, or Tribal airregulation(s), provide the citation(s)Type of PM controls7Type of SO2controls8Type of NOXcontrols9Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 13 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 effi ciency 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 bur ners (other than soot blowing) 5 Finned or dimpled tubes to increase heat transfer 99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 14 5 

### Select from the following list of fuels.

Code No. Fuel Type 1 Natural gas 2 Refinery fuel gas (mixture of na tural 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 applic ability of the regulation ( i.e. , do not select re gulations that are referenced from the regulation(s) to which the process he ater 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 SO 2 

### controls; list all that apply.

Code No. Type of SO 2 Control

0 None

21 H 2 S 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 SO 2 (specify) 99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 15 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 16 SECTION 3. EQUIPMENT LEAKS

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

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

If Yes :

a. Provide the manufactur er and model number: ____________________________

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

1 To comply with the alternative work pr actice 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 list ed in Part I, Question 16 (except WWTS). 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.Form Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/201417TABLE 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 (ppmv) Is the average methane concentration based on sampling and analysis results or estimated (e.g., based on process knowledge)?For each of the following typesof equipment, provide:PumpSeals ValvesFlanges &Connectors Open-ended lines 3 Compressor Seals Gas Sampling Connections Liquid Sampling Connections Other 4

Light liquid 2 Heavy liquid 2 Gas 2 Light liquid 2 Heavy liquid 2 Gas and light liquid 2 Heavy liquid 2Number of Pieces ofEquipmentNumber of Pieces ofEquipment Monitored5Monitoring Frequency6Leak Definition (ppmv)7Number of Pieces ofEquipmentNumber of Pieces ofEquipment Monitored5Monitoring Frequency6Leak Definition (ppmv)7Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 18 Footnotes for Table 3-1:

1 

### Select the Federal air regulati on(s) to which the process unit is subject from the following list

of regulations. Select all that apply, but incl ude only regulations for e quipment 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 regula tion(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, subpa rt 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 li st 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 ope n-ended lines refers to leakag e from the open-end of a pipe

( 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-mon itor equipment in this count.Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 19 6 

### Select from the following list of monitoring fr equencies the option that best describes the

frequency at which the majority of the equipmen t are monitored for the process unit, type of equipment, and type of service. (For “other ,” if you specified multip le types of fugitive emission sources and they have different monitori ng 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 onl y 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 defini tions the monitored con centration above which

repairs are required (or routinely performed) for th e process unit, type of equipment, and type of service. (For “other,” if you specified multip le 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 f acility (without double counting equipment included in Table 3-1). You may provide reasonable estimat es of equipment counts from existing information if the requested equipment counts are not directly availa ble as requested for each fuel gas and natural gas system.Form Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/201420TABLE 3-2. Equipment and LeakDetection Information for Fuel Gas and Natural Gas SystemsUnitIDApplicableFederal airregulation(s)1If subject toState, local, orTribal airregulation(s),provide thecitation(s)Averagemethaneconcentration inprocess fluidthat contactsequipment ingas servicethroughout theprocess (ppmv)Is the averagemethaneconcentrationbased on samplingand analysisresults orestimated (e.g.,based on processknowledge)?For each of the following types ofequipment, provide:Valves inGasService2CompressorSealsNumber of Pieces of EquipmentNumber of Pieces of Equipment Monitored3Monitoring Frequency4Leak Definition (ppmv)5Number of Pieces of EquipmentNumber of Pieces of Equipment Monitored3Monitoring Frequency4Leak Definition (ppmv)5Number of Pieces of EquipmentNumber of Pieces of Equipment Monitored3Monitoring Frequency4Leak Definition (ppmv)5Number of Pieces of EquipmentNumber of Pieces of Equipment Monitored3Monitoring Frequency4Leak Definition (ppmv)5Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 21 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. Se lect all that apply, but includ e 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 th at 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 definition of “gas service” in the regula tion to which the fuel gas or natural gas system

is subject, if applicable. See the list of defin itions for this ICR for a definition of this term to use if the fuel gas or natural gas system is not subject to a regulation that includes a definition
of this term.

3 

### Do not include difficult-to-mon itor equipment in this count.

4 

### Select from the following list of monitoring freque ncies the option that best applies for the fuel

gas or natural gas system, type of equipment, and type of service.

Code No. Monitoring Frequency 0 None (unit/system not monitored for leaks) 1 No set interval (use onl y for sensory monitoring) 2 Less than annually 3 Annually 4 Semiannually 5 Quarterly 6 Monthly 7 Biweekly 8 Weekly or more frequentlyForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 22 5 

### Select from the following list of leak defini tions the monitored con centration above which

repairs are required (or routinely performed) for the fuel gas or natural gas system, type of equipment, and type of service.

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 ppmvForm Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/2014235. Provide the information requestedin Table 3-3 regarding pressure relief devices (PRD) on eachprocess unit listed in Part I,Question 16 (except WWTS).TABLE 3-3. Pressure Relief Devices

Unit ID Total number of PRDNumber of PRDrouted to fuel gassystem or controldevice Atmospheric PRDGas Liquid Gas Liquid

Number of PRD Type of controls 1 Number of PRD Type of controls 1 Number of PRD Number equipped with rupture disk or other non-reclosing deviceMethod 21PeriodicMonitoring Monitoring of Releases Number of PRD Number equipped with rupture disk or other non-reclosing deviceMethod 21PeriodicMonitoring Monitoring of Releases

Number of PRD Monitoring Frequency 2 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 Frequency 2 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 systemForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 24 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 mon itoring frequencies the op tion that best applies

for the process unit, type of equi pment, and type of service. Select “0” if none of the other options apply.

Code No. Monitoring Frequency 0 None (unit/system not monitored for leaks using Method 21 (but ma y 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 defini tions the monitored con centration above which

repairs are required (or routinely performed) for th e 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 ma y 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 ppmvForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 25 SECTION 4. STORAGE TANKS

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

2. Does the facility receive uns tabilized crude oil? Yes No

If Yes , provide the following information:

a. The quantity of unstabilized cr ude oil received in 2010: ______________ bbl

b. The pressure at which the unstabilize d crude oil is rece ived: __________ psia

3. Does the facility 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 (i ncluding wastewater) with a maximum true vapor pre ssure greater th an 0.1 psi.Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 26 TABLE 4-1. Storage Tank General InformationTank IDType of stored liquid1Maximum true vapor pressure ofhydrocarbons in stored liquid in 2010 (psi)Temperature at which maximum true vaporpressure was calculated (°F)Type of tank/controls2Diameter (ft)Height (ft)Maximum liquid height (ft)Total throughput for all materials stored inthe tank in 2010 (bbl)Is the tank a “drain-dry” tank? (Yes/No)Applicable Federal air regulation(s)3If subject to State, local, or Tribal airregulation(s), provide the citation(s)Year in which the tank was last degassedType of control for last degassing event4Was the tank cleaned during last degassingevent? (Yes/No)Year in which you anticipate the nextdegassing event5 For tanks with EFR or
IFRType of primary rim seal6Type of secondary rim seal7Minimum height of floating roof abovethe floor at the shell when landedNumber of times floating roof landedin 2010Number of times the tank was emptiedafter roof landed in 2010Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 27 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 th an 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 28 2 

### Report the type of tank and cont rols. Select from the following list of tank types and controls.

See the list of definitions for this ICR for deta ils 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 guidepole 5 External floating roof with solid guidepole 6 External floating roof, controlled guidepole 7 Internal floating roof, slotted guidepole 8 Internal floating roof with solid guidepole 9 Internal floating roof, controlled guidepole 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 applic ability of the regulation ( i.e. , do not select re gulations 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 29 4 

### Report the type of control used for the most r ecent degassing event. Select from the following

list of controls.

Code No. Type of Degassing Control 0 None; tank vented to atmo sphere 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 an ticipate 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 typeForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 30 SECTION 5. CATALYTIC CRACKING UNITS

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

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

TABLE 5-1. Catalytic Cracking Unit InformationUnit ID for CCUFresh Feed Capacity (bbl/cd)Recycle /Resid Capacity (bbl/cd)Percent of CCU Feed that isHydrotreated (%)Typical Coke Burn Rate atCapacity (tons/cd)Type of CCU (fluid, thermal, orother)Type of CCU Regenerator(complete, partial, or variable)Is there a CO boiler or othercombustion device after CCUregenerator (Yes/No)?Applicable Federal airregulation(s)1If subject to State, local, orTribal air regulation(s), providethe citation(s)2010 Weighted Average SulfurConcentration in CombinedFeed (wt%)2010 Weighted Average NickelConcentration in CombinedFeed (wt%)2010 Weighted AverageVanadium Concentration inCombined Feed (wt%)Type of PM controls2Type of SO2controls3Type of NOXcontrols4



### Footnotes for Table 5-1:

1 

### Select the Federal air regulati on(s) to which the CCU is subj ect from the following list of

regulations. Select all that a pply, 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, su bpart 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 31 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 SO 2 

### controls; list all that apply.

Code No. Type of SO 2 Control

0 None 24 Wet scrubber/flue gas desulfurization 25 Spray dryer absorber 26 DeSOx catalyst, meeting 50/25 ppmv SO 2 limit 27 DeSOx catalyst, meeting 20 lb/ton c oke burn-off, but not 50/25 ppmv SO 2 limit 28 Low sulfur feed (0.3 wt% or less) 97 Management practice or work practice to reduce SO 2 (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 postcombustion 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 32 3. If the facility has metal concentration fo r 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 ConcentrationUnit ID for CCUParticle Type Concentration (parts per million by weight, ppmw)AntimonyArsenicBerylliumCadmiumChromiumCobaltLeadManganeseMercuryNickelSeleniumVanadium

E-cat

Fines

E-cat

Fines

E-cat

Fines

E-cat

FinesForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 33 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 Coki ng Unit InformationUnit ID for FCUFeed Capacity (bbl/cd)Type of FCU (traditional orflexicoker)Applicable Federal air regulation(s)1If subject to State, local, or Tribal airregulation(s), provide the citation(s) If traditional coker If flexicokerCoke Production Capacity(tons/cd)Typical Coke Burn Rate atCapacity (tons/cd)Is there a CO boiler or othercombustion device after FCUregenerator (Yes/No)?Type of PM controls2Type of SO2controls3Type of NOXcontrols4Produced Coke HandlingControls and Disposition5Low Btu gas production rate atcapacity (scfm)Low Btu gas sulfur removaltechnique6FCU dust/ash quantityproduced (tons/cd)FCU dust/ash handling/disposalmethod7



### Footnotes for Table 6-1:

1 

### Select the Federal regulation(s) to which th e FCU is subject from the following list of

regulations. Select all that a pply, 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 34 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 SO 2 

### controls; list all that apply.

Code No. Type of SO 2 Control

0 None 24 Wet scrubber/flue gas desulfurization 25 Spray dryer absorber 28 Low sulfur feed (0.3 wt% or less) 97 Management practice or work practice to reduce SO 2 (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 postcombustion 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 35 5 

### Select from the following list the combinati on 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 fu el 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 En closed 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 36 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 37 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 informa tion collection, a DCU consists of all drums connected to a single fractiona tor and the fractionator.

TABLE 7-1. Delayed Coking Unit Operating InformationUnit ID for DCUFeed Capacity (bbl/cd)Coke Production Capacity (tons/cd)Type of Coke Produced1Number of Coke DrumsHeight of Single Coke Drum (ft)Diameter of Single Coke Drum (ft)Typical Coke Drum Outage (ft)Typical Coke Drum Pressure When First Vented toAtmosphere (psig)Typical Coke Drum Temperature at Top of DrumWhen First Vented to Atmosphere (°F)Typical Water Height in Coke Drum When FirstVented to Atmosphere (ft) Typical Cycle Time Quench WaterApplicable Federal air regulation(s)7If subject to State, local,or Tribal air regulation(s),provide the citation(s)Complete Coke Drum Cycle Time (hr)2Coke 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 Description3Typical Quench Water Flow Rate duringQuenching Cycle (gal/min)Average Quench Water Make-up Rate (gal/day)Purged Steam BlowdownSystem Description4Quench Water Disposition5Cutting Water Sourceand Storage/Handling6Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 38 Footnotes for Table 7-1:

1 

### Select from the following lis t 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 wa ter quenching cycl e descriptions.

Code No. Quench Water Source 1 Use “tap” water ( i.e. , water purchased directly fro m 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 WWTS 99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 39 4 

### Select from the following list of blowdown syst em descriptions used to manage the steam

exhausted during the steam purge and water quenc h 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 WWTS 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 Unconden sed 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 di sposition (referring to water drained from the

drum after the vessel is vent ed to the atmosphere).

Code No. Quench Water Disposition

1 Sent to WWTS 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 40 6 

### Select from the following list of cutti ng 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 WWTS F Directed to WWTS
99 Other (specify) Z Other (specify)

7 

### Select the Federal air regulati on(s) to which the DCU is subj ect from the following list of

regulations. Select all that a pply, 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 41 3. Provide typical and maximum feed com position 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 maximu m 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
% Feed 1 Maximum
% Feed 2 Typical
% Feed 1 Maximum
% Feed 2

Atmospheric distillation column bottoms

Heavy gas oil

Vacuum distillation 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 WWTS

- Other sludges from WWTS

Other (specify): ____________



### Footnotes for Table 7-2:

1 

### Typical or average feed composition for DCU. Th e sum of all values in this column should be

100%.

2 

### Maximum percent of each feed sour ce that can be used in the DC U. The sum of all values in

this column is expected to exceed 100%.Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 42 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 InformationUnit ID for CRUFeed Capacity (bbl/cd)Operating Pressure (psig)Hydrogen Production Rate (purifiedbasis) (MMcf/cd at 0°C and 1 atm)Applicable Federal air regulation(s)1If subject to State, local, or Tribalair regulation(s), provide thecitation(s)Average Annual RegenerationFrequency (cyclic and semi-regenunits; regeneration cycles/year)2Average Annual Regeneration Time(hours/year)2Depressurization /Purge Cycle VentDisposition/control3Purge Process Type4Coke Burn-off Cycle VentDisposition/control5Coke Burn-off Cycle Duration perCycleRejuvenation Cycle VentDisposition/control6Reduction or Activation Cycle VentDisposition/control7Chloriding Agent8Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 43 Footnotes for Table 8-1:

1 

### Select the Federal air regulati on(s) to which the CRU is subj ect from the following list of

regulations. Select all that a pply, 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, su bpart 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 ca talyst 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 regenerati on occurs once every two years, then the number of cycles pe r year would be 1 cycle ÷ 2 ye ars = 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 numb er 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 pressuri zing/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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 44 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 45 SECTION 9. SULFUR RECOVERY UNITS

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

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

TABLE 9-1. Sulfur Recovery Unit InformationUnit ID for SRUSulfur, Sulfur Cake, or H2SO4Production Capacity (LT/cd)Type of SRU1Sulfur Recovery Plant (SRP) ID2Applicable Federal airregulation(s)3If subject to State, local, orTribal air regulation(s), providethe citation(s)Type of Tail Gas TreatmentUnit4Controls for Primary Sulfur PitPrimary Sulfur Pit MaintenanceTime in 2010 (hr/yr)SRU Back-upControls/Reduction Measures5Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 46 Footnotes for Table 9-1:

1 

### Select from the following lis t of sulfur recovery units.

Code No. Type of Sulfur Recovery Unit 1 2-stage Claus 2 3-stage Claus 3 4-stage Claus

4 SUPERCLAUS®

5 EUROCLAUS®
6 SubDewPoint MCRC TM -SUPERCLAUS®

7 Lo-Cat®
8 Caustic scrubber 9 Sulfuric acid plant 99 Other (specify)

2 

### For purposes of this collection, multiple SRU ar e considered part of a single SRP when the

units share the same source of sour gas. Sulf ur recovery units that receive source gas from completely segregated sour gas treatment syst ems are considered part of separate SRP.

3 

### Select the Federal air regulat ion(s) to which the SRU is s ubject from the following list of

regulations. Select all that a pply, 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, su bpart 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 tr eatment 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 Lo-Cat®
8 Wellman-Lord 99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 47 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 48 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 InformationUnit ID for Hydrogen PlantHydrogen Production Capacity(purified basis)(MMcf/cd at0°C and 1 atm)Type of Hydrogen ProductionUnit1Applicable Federal airregulation(s)2If subject to State, local, orTribal air regulation(s),provide the citation(s)Hydrogen Purification MethodUsed3Type of Feedstock Used4Steam Generation Rate (lb/hr)PSA Purge/Off Gas Flow Rate(scfm)PSA Purge/Off GasDisposition5Reformer Deaerator Vent FlowRate (scfm)Other Atmospheric Vent(Yes/No)? (If yes, report inTable 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 49 2 

### Select the Federal air regulat ion(s) to which the hydrogen plan t 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 50 SECTION 11. OTHER ATMOSPHERIC VENTS

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

2. Please provide information requested in Tabl e 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 thos e vents specifically covered in Sections 5 through 10 of this part (Part II), vents asso ciated with process heater or boiler exhausts, and wastewater ve nts. “Other atmospheric vents” include distillation column vents; blowdown systems vents, knock-out pot vents, vacuum ejectors (hot well vents), analyzer vent s as well as vents from Merox TM 

### treatment systems, fuel gas treatment units (if any), catalytic hydrocra cking units (if any), asphalt blowing stills, and coke calcining units. The focus of this se ction is primarily on ve nts directed directly to the atmosphere during normal operation, a nd vents recycled to process units, vents directed to a fuel gas system, or vents dire cted to a flare are not considered “other atmospheric vents.” Also, “oth er atmospheric vents” do not in clude pressure relief vents where venting occurs only during upset, star tup, or shutdown events or vents associated with storage tanks.

TABLE 11-1. Other Atmospheric Vent InformationAtmospheric VentIDType ofAtmospheric Vent1Unit ID (ifapplicable) withwhich the Vent isAssociated2Applicable Federalair regulation(s)3If subject to State,local, or Tribal airregulation(s),provide thecitation(s)Atmospheric VentOperating Hours4Atmospheric VentControls5Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 51 Footnotes for Table 11-1:

1 

### Select from the following list of processes and e quipment the option that be st describes the type

of unit or equipment associated with this vent.

Code No. Type of Ot her Atmospheric Vent 1 Atmospheric crude distillation column/reflux condenser vent 2 Catalytic cracking unit distillati on column/reflux condenser vent 3 Catalytic hydrocracking unit distilla tion column/reflux condenser vent 4 Catalytic reforming unit distillati on 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 genera l 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 regulati on(s) to which the “other atmos pheric vent” is subject from the

following list of regulations. Se lect all that apply, but includ e 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 regulatio n(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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 52 4 

### Select from the following list of operating scenarios.

Code No. Type of Operation 1 Continuous (operates whenev er 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 cont rol 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 SO 2 (specify) 98 Management practice or work practice to reduce NO X (specify) 99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 53 SECTION 12. FLARES

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

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

TABLE 12-1. Flare InformationFlare ID or DescriptionIf the flare is dedicated toone processing unit, enterthe Unit IDFlare Diameter (ft)Flare release height (ft)Flare Location (Latitude)Flare Location (Longitude)Type of Flare1Flare Assist Type2Target Assist Ratio (ifapplicable)Type of Flare Pilot orIgnition System3Applicable Federal airregulation(s)4If subject to State, local, orTribal air regulation(s),provide the citation(s)Typical Lower HeatingValue of Waste Gas(Btu/scf @ 60°F)Flare Operating Hours5Flare Management Plan6Flare Reduction Measures7Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 54 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 regulati on(s) to which the flare is subject from the following list of

regulations. Select all that a pply, 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 55 5 

### Select from the following list of operating scenar ios 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 manageme nt for the flare; list all that apply.

Code No. Components of Flare Management Plan 0 Not applicable. Do not have a flare manage ment 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

6 Procedure to conduct a root cause and corr ective action analysis for flare events exceeding a set SO 2 emission level

7 Procedures to conduct root cause and correctiv e action analysis for flare events exceeding
a set flow rate level 8 Procedures for monitoring flow of gas to the flare 9 Procedures for monitoring Btu of flared gas 10 Procedures for monitoring sulfur content of flared gas 99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 56 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 SO 2 emissions from the flare, not amine tr eatment 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 SO 2 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 SO 2 (specify) 98 Other management practice or work practice to reduce NO X (specify) 99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 57 SECTION 13. FUEL GAS TREATMENT UNITS

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

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

TABLE 13-1. Fuel Gas Sulfur Treatment Unit InformationFuel Gas Treatment Unit IDIf the fuel gas treatment unit is dedicated toone process unit, enter the Unit ID for thededicated process unitDoes this treatment unit receive gas from acoking unit? (Yes/No)Type of sulfur removal technique(s) used1Fuel gas flow rate at treatment unit capacity(scfm)Average fuel gas flow rate into the treatmentunit (scfm)Estimated operating hours in 2010Types of sulfur compounds in the untreatedfuel gas2Estimated annual average H2S concentrationin treated fuel gas exiting the treatment unit(ppmv)Estimated annual average total sulfurconcentration in the treated fuel gas exitingthe treatment unit (ppmv)Applicable SO2federal air regulation(s) forcombustion units that burn the fuel gas3If subject to State, local, or Tribal airregulation(s) for SO2from combustion unitsthat 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 58 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 Lo-Cat®
15 Caustic scrubber 16 Sodium hydrosulfide (NaSH) production process 99 Other (specify)

2 

### Select from the following list of sulfur-c ontaining compounds; list all that apply.

Code No. Type of Sulfur Containing Compound 1 Hydrogen sulfide (H 2 S) 2 Carbonyl sulfide (COS) 3 Carbon disulfide (CS 2 ) 4 Mercaptans
5 Thioethers 99 Other (specify)

3 

### Select the Federal regulation(s) for SO 2 

### to which the fuel gas combustion units are subject from

the following list of regulations. Select all that apply, but include only re gulations to which the fuel gas combustion units are subject accordi ng to the applicability of the regulation ( i.e. , do not select regulations th at are referenced from the regulatio n(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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 59 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 InformationHE System ID orDescriptionUnit IDs for Process UnitsServiced by Cooling WaterSystemCooling Water SystemOperation – Fluid Pressure1Cooling Water SystemVOC/HAP Concentration2Type of Cooling WaterSystem3Applicable Federal airregulation(s)4If subject to State, local, orTribal air regulation(s),provide the citation(s)Cooling Water Flow/Recirculation Rate(gal/min)Water Make-up Rate(gal/min)Gas or ChemicalAdditive/DisinfectionMethod5Gas or Chemical AdditionRate ValueGas or Chemical AdditionRate Units (volume or massper time)Chemical AdditionLocationForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 60 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 descripti ons of the cooling water system VOC and HAP

concentrations.

Code No. Cooling Water System VOC/HAP Concentration 1 Services only heat exchangers in which th e 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 regulati on(s) to which the cooling water system is subject from the

following list of regulations. Se lect all that apply, but includ e 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 refe renced 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 61 5 

### Select from the following lis t 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 62 SECTION 15. WASTEWATER COLLECTION AND TREATMENT

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

2. Please provide the following info rmation for the facility.

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

b. What was the Total Annual Benzene (T AB) quantity for the facility in 2010?

c. Indicate the Benzene Wa ste 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 informati on about wastewater generated from tank
drawdowns:

a. Estimated quantity of wastewater gene rated via tank draw downs in 2010: ___ gallons

b. Quantity of benzene in wastewater gene rated via tank draw downs in 2010: ___ lb

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

4. Complete Table 15-1 to i ndicate the wastewater treatme nt processes used for each WWTS (identified in Part 1, Question 16) at th e facility and the appl icable air regulations
for each selected unit.Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 63 TABLE 15-1. Wastewater Treatment Processes

Wastewater
Treatment and Collection System
ID Type of
Wastewater
Treatment

Process 1 For Steam and Sour Water Strippers, also provide the total of the average steam usage rates for each stripper of this type in 2010 (lb/hr) 2 Applicable
Federal air regulation(s) 3 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 treat ment processes 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 

### For example, if you have two sour water stripp ers, add the average st eam usage rate in pounds

per hour in 2010 for the first sour water stripper to the average steam usage rate in pounds per hour in 2010 for the second sour water stripper and report the resulting sum in this column.

3 

### Select the Federal air regulati on(s) to which the selected wastewater treatment process is

subject from the following list of regulations . Select all that apply, but include only regulations to which the wastewat er treatment process is subject according to the applicabilityForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 64 of the regulation ( i.e. , do not select regulations that are referenced from the regulation(s) to which the wastewater treatment process is subject).

Code No. Federal Air Regulation

0 None 1 BWON (40 CFR part 61, subpart FF), but exempt from control requirements 2 BWON (40 CFR part 61, subpart FF) 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 pr ovide your best estima te based on available information; no additional testing is required to comple te 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 associ ated with wastewater drain systems (including junction box vents) and gases purged from covered WWTS.Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 65 TABLE 15-3. Wastewater Vent Information

Atmospheric
Vent ID Description
of Atmospheric
Vent 1 Applicable
Federal air regulation(s) 2 If subject to State, local, or Tribal air regulation(s),

provide the citation(s) Atmospheric Vent Operating
Hours 3 Atmospheric
Vent
Controls 4



### Footnotes for Table 15-3:

1 

### Select from the following list of wastewater ve nts 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 unit 99 Other (specify)

2 

### Select the Federal air regulation( s) to which the selected wastewater vent is subject from the

following list of regulations. Se lect all that apply, but includ e 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 regulatio n(s) to which the wastew ater vent is subject).

Code No. Federal Air Regulation

0 None 1 BWON (40 CFR part 61, subpart FF), but exempt from control requirements 2 BWON (40 CFR part 61, subpart FF) 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 66 3 

### Select from the following list of operating scenarios.

Code No. Type of Operation 1 Continuous (operates whenever the wa stewater 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 cont rol 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)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 67 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 be st describes the marine vesse l loading operations that are associated with the refinery’s shipments via marine vessels (as repor ted 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 conducte d 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 asso ciated 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 WWTS?

Yes No

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

a. Select the option that best describes the tank truck loading op erations that are associated with the refinery’s shipments via tank truck (as reported in Qu estion 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 o ff-site (not part of th e contiguous refinery facility). 

### b. Select the option that best de scribes the rail car operations that are associated with the refinery’s shipments via rail truck (as repor ted in Question 15 of Pa rt I of this ICR).Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 68 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-s ite (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 InformationUnit ID for loading operationType of vessel loaded1Capacity loading throughput(gal/yr)Applicable Federal airregulation(s)2If subject to State, local, orTribal air regulation(s),provide the citation(s)Typical annual operatinghours (hr/yr)Does the facility or parentcompany own the vessels beingloaded? (Yes/No)Type of control device orcontrol technique3Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 69 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 regulati on(s) to which the loading operati on is subject from the following

list of regulations. Select all that apply, but include only regulations to which the loading operation is subject according to the applicability of the regulation ( i.e. , do not select regulations that are referenced from the regulatio n(s) to which the loading 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 de vices and techniques; li st 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)Form Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/201470PART III. NON-ROUTINE EMISSIONSComplete the following table for each non-routine emissions event during 2010 where the emissions exceeded normal emissions, normalcontrols were bypassed, or the effectiveness of the normal controls was reduced.Date ofreleaseType of release(startup/shutdown;equipment or componentmalfunction)Description of releaseeventProcessunitsassociatedwith thereleaseDurationof thereleaseevent(hours)PollutantnamePollutantCAS No.orPollutantCodeQuantityofpollutantreleased(lb)Quantitydeterminationmethod(measured orcalculated)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 71 

### PART IV. COST DATA (Optional)

Cost data for air pollution control devices (APCD), pr ocess changes, equipment changes/upgrades, and management or work prac tices 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 asse ssed 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 pr ojects, ethanol blending projects, and gasoline reformulation projects to remove MTBE). If you wish to provide more de tail 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 cont rol technique but do not have the level of detail requested in the tables, pl ease provide the approximate cost and your best estimate of which of the components in the appropri ate table were factored into that approximate cost (in lieu of completing the applicab le table for that control technique).

If any of the data requested in th is part is considered CBI, follow the instructions in the section “Submitting CBI” under the heading “How to Submit Your Survey Response” in the instructions for this ICR on the ICR website ( https://refineryicr.rti.org ).

1. Please complete Table 1 for any new APCD in stalled in the last 5 years on any of the process units or other emissions sources desc ribed in Part II for which you have readily available information. The EPA is particul arly 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 proce ss changes or equipment changes/upgrades performed in the last 5 year s to any of the process units or other emissions sources described in Part II for which you have r eadily available information. The EPA isForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 72 particularly interested in costs of th e 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 fo r external floating roof tank

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

3. Please provide any readily available costs fo r other techniques used at your refinery to reduce emissions of any pollutant. EPA is part icularly interested in techniques that are not already included in Federal regulations. Pr ovide 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 tec hnique (labor costs), cost of any equipment needed on a temporary basis, cost of any monitoring device s needed to indicate when action is needed or to measure progress). Types of technique s 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 th e duration and quantity of compounds released from a PRD)

• Pollution prevention techniques

• Energy management programs identi fied in Part II, Section 1

• Other management practices or work pr actices that you iden tified in Part IIForm Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/201473Table 1. Cost Data for APCD (Optional)1

APCD ID Unit ID associated with this APCD APCD Type 2 APCD Size 3 New or retrofit APCD? 4 Year of APCD installation Expected APCD equipment life (yrs) Demolition cost for previous APCD, if any ($)CAPITAL COSTSANNUAL OPERATING COSTS10

Base year for capital costsPurchasedequipmentcosts ($)5 Installation costs ($) 8 Total Installed Cost of APCD 9 Base year for operating costs Operating labor ($) Maintenance labor ($)Utilities ($) Waste disposal ($)Suppliesandparts13 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 e quipment 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/yr 11 $/amt amt/yr 11 $/yr 1 2 31Columns 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 thesubtotal in the appropriateshaded column and provide as much detail or explanation as you have available.2See list following the last footnote for codes corresponding to APCD types.3Provide the numerical value as well as the units (e.g.scfm).4If the APCD was installed at the time the process unit or emissionsource was constructed, enter “New.” If the APCD was installed after the process unitor emission source beganoperation, enter “Retrofit.”Form Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/2014745Sum of equipment, auxiliary equipment, instrumentation/monitors, sales tax, and freight.6Primary equipment is the APCD itself.Examples include SCR with catalyst, carbonadsorber with carbon, packed scrubber towerwith packing, fabric filter with bags, ESP, andsteam stripper column withnozzles, manholes, and trays.7Examples of auxiliary equipment include fans, pumps, motors,duct work, stacks, flame arrestors, and condensers and decantersfor steam strippers.8Include all installation costs (e.g., foundations, supports, handling/erection, electrical, piping, insulation for ductworkand piping, painting,engineering, construction and fieldexpenses, contractor fees, start-up, and testing.9Sum of purchased equipment cost and installation cost.10Provide operating costs for the last 12 month period (calendar or fiscal year) for which the refinery has data.11Specify units.12For 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 costfor each utility. Add the individual utility annual costs toget the total utilities cost.13Include the most significant item of the major supplies and replacement parts; examples include catalyst for SCR and catalyticincinerators, bags for fabric filters, and carbon forcarbon adsorbers.14An example might be catalyst regeneration. Note that this question is not asking for costs ofmaintenance materials, capitalrecovery, overhead, administration, property taxes, andinsurance because EPA will estimate these costs as a function of other costs.15Sum 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 anyother items included under “other annual costs.”Form Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/201475Code No. Type of APCD1 Amine treatment (e.g., installation of new amine treatment unit)2 Caustic spray injection3 Packed-bed wet scrubber4 Tray tower wet scrubber5 ChlorsorbTM11 Fabric/cartridge filter (“baghouse”)12 Venturi/wet scrubber13 Electrostatic precipitator (ESP)14 Wet ESP15 Tertiary cyclone24 Wet scrubber/flue gas desulfurization25 Spray dryer absorber36 Selective non-catalytic reduction (SNCR)37 Selective catalytic reduction (SCR)42 LoTOX® scrubber50 Thermal or catalytic incinerator/oxidizer51 Condenser52 Carbon adsorber53 Single carbon adsorber canister54 Two carbon adsorber canisters in series55 Flare56 Portable internal combustion engine57 Portable thermal oxidizer58 Portable condensation system59 Permanent onsite control device for storage tanks60 Flare gas recovery83 Vapor balancing system99 Other (specify)Form Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/201476Table 2. Cost Data for Process and Equipment Changes (Optional)Unit IDProcess orequipmentchange type1Process orequipmentchangedescription2Year of processor equipmentchangeNumber of daysprocess shutdown in order tomake the change(days of lostproduction)3Total capitalcost, $4Change in totalannualoperating cost,$/yr5Emissionreductionsachieved (ifquantified)61See 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 specifythe type of process or equipment change.2Describe the process or equipment change. Be as descriptive as possible. For example, for installation of low NOXor ultra low NOXburners for a process heater, note the number ofnew burners, their sizes,and the fuel options (e.g., fuel gas, oil).3Enter number of days of lost productionrequired to implement the process or equipment change. If the change occurred duringscheduled downtime thatwould have occurredregardless of the process or equipment change, then do not includethe scheduled downtime. Only the days of lost production that can be specifically attributed to the process orequipment change are of interest.4Please 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 aseparate attachment.5Provide changes in annual operating costs (if estimated). Otherwise, leave blank. Include annual operating costs that are anincrease to prior operating costs (e.g., additionaloperating costs due to installation of low NOXburners). If the process or equipment change resulted in decreased annual operating costs, thenindicate the cost decrease asanegative number.6Describe the air pollutants affected and emissions reduction achieved.Indicate the basis for emissions reduction reported (e.g., air emissions testing beforeand after modification).You may provide this information as a separate attachment toyour response if you wish.Form Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/201477Code No. Type of Process or Equipment Change1 Amine treatment (change in existing amine treatment system operation)21 H2S limit in fuel gas22 TRS limit in fuel gas23 Low sulfur distillate or heavy gas oil26 DeSOx catalyst, meeting 50/25 ppmv SO2limit27 DeSOx catalyst, meeting 20 lb/ton coke burn-off, but not 50/25 ppmv SO2limit28 Low sulfur feed (0.3 wt% or less)31 (External) flue gas recirculation32 Staged air low NOXburner33 Staged fuel low NOXburner34 Ultra low NOXburner (high fraction staged fuel) (ULNB)35 “Next generation” low NOXburner (ULNB with internal gas recirculation)39 High-efficiency regenerator40 Low NOXcombustion additives to replace Pt-based combustion additives41 Other low NOXcatalyst additives70 Water seal71 Fixed seal72 Hard piping80 Submerged fill loading82 Bottom loading99 Other (specify)Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 78 

### PART V. EMISSIONS MONITORI NG AND SOURCE TEST DATA

In this section, emissions test data are requeste d. Please satisfy this request as completely as possible from existing information. No additiona l monitoring or emission testing is required by your company to respond to the data request in this section. Five type s of existing emissions data are requested: 1) source test data, 2) qualified CEMS data, 3) qualified CMS data, 4) biological treatment units data, a nd 5) ambient or remote sensing data. The emissions test data collected will provide valuable information on cu rrent 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 emi ssion standards. When submitting test data, EPA is requesting full test reports with field and la b data sheets and example calculations, not just summary reports.

If any of the data requested in th is part is considered CBI, follow the instructions in the section “Submitting CBI” under the heading “How to Submit Your Survey Response” in the instructions for this ICR on the ICR website ( https://refineryicr.rti.org ).

1. Source Tests : Provide any existing emissions test reports from emissions tests conducted on any of the processes or emission points incl uded in Part II, Sections 5 through 16 and for boilers included in Table 1-2 (of Part I I) 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 paramete rs, 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 recen t test for that pollutant and process unit. (We are only requesting the most recent te st per unit for one pollutant, but you may submit more than one test, particularly if additional tests reflect the effect of different operating conditions or equipment configurations.)

In addition, complete the source test log s hown below 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) test number (use any unique identifier you choose for each test)

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

(C) a description of how the configuration of the emissi on unit, combustion controls, collection system, or APCD has cha nged since the test was conducted, if applicable,

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

(E) how often you are required to te st the emission unit (optional).

2. Qualified CEMS Data : Provide qualified CEMS data for PM, CO, NO X 

### , SO 2 

### , and THC CEMS on any of the processes or emission poi nts included in Part II, Sections 5 through 16 and for boilers included in Table 1-2 (of Pa rt II). Report daily averages for each day in 2010 using the Microsoft® Excel CEMS Daily Template available on the ICR websiteForm Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



### 79 ( 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 fr om a PM CEMS that meets Performance Specification 11 or 15; data from a CO CEMS that meets Performance Specification 4;
data from a SO 2 

### and/or NO X 

### CEMS that meets Performance Specification 2; data from a THC CEMS that meets Performance Specificat ion 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 th e daily averages using by averaging the hourly CEMS values for each hour for which quali fied 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 fo r 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 fiel ds in the log if you wish to provide additional data.

3. Qualified CMS Data : Provide qualified CMS data for H 2 

### S, reduced sulfur, total reduced sulfur, hydrocarbon, and Btu CMS on fuel gas or fl are gas lines. Only CMS data listed in the previous sentence are requested; no othe r type of CMS data are requested. Report daily averages for each day in 2010 using the Microsoft® Excel CMS Daily Template 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 H 2 

### S 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 Specifica tion 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 th e manufacturer’s specifi cations 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 availabl e. 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:Form Approved 03/28/2011
OMB Control No. 2060-0657 Approval Expires 03/31/2014



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

(B) APCD type.

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

4. Biological treatment unit : If you performed a biodegrada tion 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 ai r 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 co rrelations to estimate emissions from equipment leaks, provide a complete copy of the report or other documentation describing the testing and deve lopment of the correlations.Form Approved 03/28/2011OMB Control No. 2060-0657Approval Expires 03/31/201481PART V. LOG OF SOURCE TESTSAND MONITORING DATA PROVIDEDTest orMonitoringData ID1UnitID(s)If the APCD type(s) is notclear from the test report,enter the APCD type(s)Configurationchanges2OPTIONAL:Process testingnotes3OPTIONAL: How often are yourequired to perform testing of thisemission unit for the pollutants listed?OPTIONAL:Approximatecost per test, $1Assign a unique ID or number to each testreport, CEMS data set, or CMS data set thatyou provide so that EPA can match your responses in this log to the correct test report ormonitoring data. For CEMS data and CMS data, the identifier should include the pollutant or other parameter being monitored.2If the configuration of the emission unit,combustion controls, collection system, orAPCD changed sincethe test was conducted, describe the changes. If there are no configurationchanges, enter “N/A”3Use this column for notes or if helpful to specify the emission points tested (e.g., for equipment with multiple emission points, whereonly selected emission points/vents were tested)