### Component 1 Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__ Deleted: Enclosure



# Petroleum Refinery
Emissions Information Collection

General Instructions

NOTE: The final version of this questionnaire will be in electronic format, not in hard copy. The majority of these instructio ns will be incorporated into the Section 114

letter and available on the website.

Please provide the information requested in Components 1-3 and, if applicable, Component 4 for the facility listed in the Section 114 letter you received in the mail. If you received one Section 114 letter for multiple facilities, you must create a separate survey response for each facility. 1



### Use the 20 1 0 calendar year as the base year for all survey responses ( e.g. , 20 1 0 emissions inventory, 20 1 0 throughput, 20 1 0 equipment configurations) unless another year is specified in the instructions ( e.g. , for existing emissions test data).

The following sections ( Component 1) are to be completed by all facilities and returned

to the address noted below by May 31, 2011 :

• Part I – General Facility Information: Provide information on the petroleum refinery at the facility level.

• Part II – Process and Emissions Informatio n: Provide detailed information on the process units and other emissions sources at the petroleum refinery.

• Part III – Incidence Reports: Provide copies of reports filed as a result of specific incidents at the petroleum refinery and information on public complaints.

• Part IV – Cost Information: Provide the age and cost to install and operate control equipment at the petroleum refinery.

• Part V – Emissions Monitoring and Sour ce Test Data: Provide results of all existing emissions data from tests or monitoring conducted on any of the processes or emission points included in Part II, Sections 2 through 17.

The following section (Component 2) is to be completed by all facilities and returned to the address noted below by June 30, 2011:

• Part VI – Emissions Inventory: Provide emissions estimates for the requested process units and other emissions sources at the petroleum refinery.

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

Deleted: Enclosure 2

Deleted: 9

Deleted: 9

Deleted: 9

Deleted: 9

Deleted: Enclosure

Deleted: within 90 days of receipt of your Section

114 letter

Deleted:

Deleted: 16.

Deleted: Crude OilForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 2 The following section (Component 3) is to be completed by all facilities and returned to the address noted below by August 31, 2011:

• Part VII – Distillation Feed Composition Analysis: Conduct an analysis of the composition of the feed to each distillation column at the refinery.

Component 4 (Part VIII), emissions testing

, is to be completed by facilities with process units selected for testing. The Section 114 letter you received directs you to a website where you

can find a list that indicates if a unit at your refine ry has been selected for testing as well as detailed instructions on how the testing must be conducted . For units requiring stack tests, emissions tests (consisting of three runs per test method required) are to be conducted according

to Part VIII for each unit. For fuel gas samples, triplicate grab samples are to be taken for each mix drum associated with a fuel gas system. Follow the instructions in Part VIII for sampling the wastewater treatment system. The results of the emissions tests and other requested analyses

should be returned to EPA by August 31, 2011

. The electronic version of the survey (Parts I, II, III, and IV of this Component 1) can be downloaded from the ICR website ( https://refineryicr .rti.org ). Detailed instructions for each part

follow. NOTE: The final version of this questionnaire will be in electronic format, not in hard copy. The questions are provided in this document merely for convenience during the public comment period.

If you are unable to respond to an item exactly as requested, please explain why you cannot respond and/or provide any information you believe may be related. For example, if you have a special or unique type of process unit and the questions in the section related to that process unit are not relevant to your specific unit, please provide information that would help EPA classify your process unit and account for its existence and operation in potential future rulemaking.

Questions regarding this information request should be directed to Ms. Brenda Shine at (919) 541-3608 or shine.brenda@epa.gov

.



## Confidential Business Information (CBI)

If you believe that providing any specific information to us would reveal a trade secret, or would compromise confidential business informa tion (CBI), please identify this information clearly in your response and submit your response as detailed in the next section. Also, please clearly label any flow diagrams or other attachments submitted with your survey that contain CBI. However, please do not label your entire response as CBI if only a portion includes trade

secrets.

The EPA’s procedures for handling CBI are described in the letter (and enclosures) accompanying this questionnaire. The EPA is likely to follow-up with a request for validation of CBI claims for facilities claiming large amounts of information as trade secret, especially information that is readily reported by other facilities without such claims. Any information EPA subsequently determines to constitute CBI or a trade secret under EPA’s CBI regulations at 40 CFR part 2, subpart B, will be protected pursuan t to those regulations and, for trade secrets, under 18 U.S.C. 1905. If no claim of confidentiality accompanies the information when it is Deleted: type of crude

Deleted: Emissions

Deleted: according to Enclosure 2

Deleted: Enclosure 2

Deleted: Enclosure 2

Deleted: within 6 months of receipt of this questionnaire

Deleted: Enclosure 1) is in Microsoft® Excel

format and

Field Code Changed

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).

Deleted: ¶

Deleted: Mr. Bob Lucas at (919) 541-0884 or lucas.bob@epa.gov orForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 3 received by EPA, it may be made available to the public by EPA without further notice pursuant to EPA regulations at 40 CFR 2.203. Because Clean Air Act (CAA) section 114(c) exempts emission data from claims of confidentiality, the emission data you provide will be made available to the public notwithstanding any claims of confidentiality.



## How to Submit Your Survey Response

If your response to this information collect ion request includes data with a claim of CBI, you should follow the instructions in this secti on to ensure the protection of your data. Please note that if you submit CBI, you should separate your data into two packages, one containing your entire response, including any information claimed as CBI

, and the other containing only

information that you do not claim as CBI (hereafter referred to as “non-CBI”). These two packages should be sent to EPA separately, using two different mailing addresses.

Separating CBI and Non-CBI

As you complete and review your survey response, identify the information you consider CBI. Clearly mark the CBI components as “Confidential” in your electronic survey response. If you are sending attachments, clearly mark the CBI portions of the diagrams/pages ( e.g. , highlight or circle) as such.

Once you have marked the CBI, create a new survey response file that does not include this information. If you have attachments, remove the pages that contain CBI. The resulting files and attachments comprise your non-CBI survey response. Please check carefully to ensure

that there is no CBI in these files. Send thes e files to EPA using one of the methods described under “Submitting Your Non-CBI Response.”

Create a separate CD or DVD containing your entire survey response , including CBI

. Include on the disk any pages of attachments to your survey response containing CBI, with the CBI portions of the diagrams/pages clearly marked ( e.g. , highlighted or circled). Clearly mark the disk with the words “Confidential Business Information.” Send only these CBI files under separate cover to the address provided under “Submitting CBI.”

Submitting Your Non-CBI Response

For the non-CBI portions of your survey response, including non-CBI attachments (and

for survey responses that are entirely non-CBI), use one of the following methods to submit your survey response to EPA:

• Upload your files to the ICR website. Detailed directions for uploading your files are provided on the ICR website ( https://refineryicr .rti.org ).

• E-mail an electronic copy of all requested files to refineryicr@epa.gov

.

• Mail a CD or DVD containing an electronic copy of all requested files to the EPA address shown below. If no electronic copy is available, mail a hard copy of all requested files to the address shown below: Deleted: all other

Deleted:

Deleted: After

Deleted: have completed

Deleted: ed

Deleted: only the CBI portion of

Field Code Changed Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 4 U.S. Environmental Protection Agency Office of Air Quality Planning and Standards Sector Policies and Programs Division U.S. EPA Mailroom (D205-01) Attention: Brenda Shine, Petroleum Refinery Sector Lead

109 T.W. Alexander Drive Research Triangle Park, NC 27711

EPA recommends sending your non-CBI files via Registered U.S. Mail using return receipt requested, Federal Express, or other method for which someone must provide a signature upon receipt.

Submitting CBI

Follow the instructions under “Separating CBI and Non-CBI” to create the portion of your survey response that contains CBI. Send only these CBI files under separate cover to:

U.S. Environmental Protection Agency Office of Air Quality Planning and Standards U.S. EPA Mailroom (C404-02) Attn: Mr. Roberto Morales, Document Control Officer

109 T.W. Alexander Drive Research Triangle Park, NC 27711

For security purposes, EPA highly recommends sending your confidential files to Mr. Morales via Registered U.S. Mail using return receipt requested, Federal Express, or other method for which someone must provide a signature upon receipt.

DO NOT ELECTRONICALLY TRANSMIT CONFIDENTIAL BUSINESS

INFORMATION TO EPA. E-mail and facsimil e are not secure forms of communication and

should never be used to transmit CBI.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 5 

### ABBREVIATIONS

20 lb/ton coke burn-off SO 2 

### emissions limit in 40 CFR part 60, subpart J, of 9.8 kg/Mg (20 lb/ton) coke burn-off (40 CFR 60.104(b)(2))

50/25 ppmv SO 2 

### limit SO 2 

### emissions limit in 40 CFR part 60, subpart Ja of 50 ppmv SO 2 

### , dry basis corrected to 0 percent excess air, on a 7-day rolling average basis and 25 ppmv, dry basis corrected to 0 percent excess air, on a 365-day rolling average basis (40 CFR 60.102a(b)(3))

acfm actual cubic feet per minute

APCD air pollution control device

As arsenic

ASTM American Society of Testing and Materials

bbl barrels

bbl/cd barrels per calendar day

bbl/sd barrels per stream day

bbl/yr barrels per year

BOD biological oxygen demand

BQ benzene quantity

Btu/lb British thermal units per pound

BWON Benzene Waste Operations NESHAP (40 CFR part 61, subpart FF)

CAA Clean Air Act

CAS Chemical Abstracts Service

CBI confidential business information

CCU catalytic cracking unit

CEMS continuous emission monitoring system

CERCLA Comprehensive Environmental Response, Compensation, and Liability

Act

CFR Code of Federal Regulations

CO carbon monoxide

COD chemical oxygen demand

COS carbonyl sulfide

CRU catalytic reforming unit

DCU delayed coking unit

DIAL Differential Absorption Light Detection and Ranging

DMEA dimethylethanolamine

E-cat equilibrium catalyst

EPA U.S. Environmental Protection AgencyForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 6 ESP electrostatic precipitators

ETBE ethyl tert-butyl ether

F/M ratio food to microorganism ratio

FCU fluid coking unit

ft feet

gal/day gallons per day

gal/min gallons per minute

H 2 

### S hydrogen sulfide

H 2 

### SO 4 

### sulfuric acid

HAP hazardous air pollutants

HF hydrogen fluoride

Hg mercury

hr hours

hr/yr hours per year

ICR information collection request

ID identification number or code

Iso C5,C6 isopentane (aka 2-methylbutane), isohexane (aka 2-methylpentane)

Lat/Long latitude and longitude

lb/ft 3 

### pounds per cubic foot

lb/hr pounds per hour

lb/ton pounds per ton

LDAR leak detection and repair

LPG liquefied petroleum gas

LT/cd long tons per calendar day

MACT Maximum Achievable Control Technology

MCRC maximum Claus recovery/conversion

Mg/yr megagrams per year

MLSS mixed liquor suspended solids

MLVSS mixed liquor volatile suspended solids

MM lb million pounds

MMBtu/hr million British thermal units per hour

MMcf million cubic feet

MMcf/cd million cubic feet per calendar day

MMgal/day million gallons per day

MTBE methyl tert-butyl ether

MW megawatts

MWh megawatt-hoursForm Approved __/__/__ OMB Control No. ____-____

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### 7 NAD North American Datum

NESHAP national emissions standards for hazardous air pollutants

Ni nickel

No. number

NO X 

### oxides of nitrogen

NSPS new source performance standards

OVA organic vapor analyzer

PM particulate matter

ppmv parts per million by volume

ppmw parts per million by weight

PSA pressure swing absorption

PRD pressure relief device

psi pounds per square inch

psia pounds per square inch absolute

psig pounds per square inch gauge

QA quality assurance

QC quality control

regen. regeneration

SCC Source Classification Code

scfm standard cubic feet per minute

SCOT Shell Claus Off-gas Treating

SCR selective catalytic reduction

Se selenium

SNCR selective non-catalytic reduction

SO 2 

### sulfur dioxide

SOF Solar Occultation Flux

SRU sulfur recovery unit

STERPP storage tank emission reduction partnership program (72 FR 19891)

TAB total annual benzene

TAME tert-amyl methyl ether

THC total hydrocarbons

TOC total organic compounds

tons/cd tons per calendar day

tons/yr tons per year

TRS total reduced sulfur

U.S. DOE/EIA U.S. Department of Energy, Energy Information Administration

ULNB ultra low NO X 

### burner (high fraction staged fuel)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 8 UV ultraviolet

VOC volatile organic compounds

wt% weight percent

WWTS wastewater collection and treatment system

WWTU wastewater collection or treatment unit

°F degrees Fahrenheit

% percentForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 9 

### PART I: GENERAL FACILITY INFORMATION

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

2a . Plant Name (as reported on U.S. DOE/EIA Form-820 (20 1 0), “Annual Refinery Report,” schedule 2, line 1, page 37, question 1):

_________________________________________________________________________

_________________________________________________________________________

_________________________________________________________________________
2b . Does this facility 3 

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

refining plants that are not contiguously located? Yes No

2c . If Yes , provide the facility ID for each non-contiguous facility: _____________________

_________________________________________________________________________

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

_________________________________________________________________________

_________________________________________________________________________

4 . Provide mailing address if different: ___________________________________________

_________________________________________________________________________

_________________________________________________________________________

5 . Name and title of contact(s) able to 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: ______________________________________________

_________________________________________________________________________

_________________________________________________________________________

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

_________________________________________________________________________

3 For purposes of this information request, “facility” is de fined 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 a nd under common ownership or common control. Deleted: 1. Name of legal owner of facility 2 : ¶ ¶ ¶ ¶

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

¶ ¶

3. Address of ____ legal owner or ____ operator:

¶ ¶ ¶ ¶

4a

Deleted: 9

Deleted: 4b

Deleted: 4c

Deleted: name and location

Deleted: 4d. If Yes , you must complete a separate survey response for each non-contiguous facility. Indicate the name of the facility for which the remainder of this survey response applies. ¶

__________________________________________ ______________________________¶

5

Deleted: 6

Deleted: 7

Deleted: 8Form Approved __/__/__ OMB Control No. ____-____

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

_________________________________________________________________________

_________________________________________________________________________

_________________________________________________________________________
10. Dunn and Bradstreet number of your facility: ___________________________________

11 . Annual revenue in 20 1 0: $______________________

12 . Number of employees at your facility: _________________________________________

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

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

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

Partner name ______________ Percent ownership ______% No. employees ______

Partner name ______________ Percent ownership ______% No. employees ______

Partner name ______________ Percent ownership ______%



### If No : Name of parent company: _____________________________________________

Number of employees in parent company: ___________________________

Check the statement below that best applies:

The facility is fully independent of th e parent organization (independent sources of capital, different Boar ds of Directors, etc.).

The parent organization provides some financial support.

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



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

1 Topping refinery

2 Hydroskimming refinery

3 Upgrading refinery

4 Heavy oil/asphalt refinery



### 15. Provide the quantity of products produced at the refinery and their relative disposition (transport method) in 2010. Production values should be provided as reported to EIA on form EIA-810 form, except specify aromatics production quantities. Provide the relative disposition of products from readily availabl e information; exact quantity information is not necessary. For products piped directly to an offsite marine vesse l tank ship terminal Deleted: 10

Deleted: 9

Deleted:

Deleted: 11

Deleted: 12a

Deleted: 12b

Deleted: Corporate crude oil processing capacity:

(bbl/stream day) ¶

12c. If Yes, check

Deleted: 13. Circle all applicable code number(s)

for the final

Deleted: facility:¶

1 LPG¶

2 Automotive gasoline¶

3 Aviation fuels¶

4 No. 2 diesel fuel ¶

5 No. 4 diesel fuel (heavy fuel oil)¶

6 No. 6 diesel fuel (marine diesel/bunker C)¶

7 Lubricating/motor oil¶

8 Asphalt¶

9 Petroleum coke¶

10 Sulfur ¶

11 Ethylene¶

12 Aromatics (specify):

__________________________________________ _____ ¶

13 Other petrochemicals (specify): ______________________________________ ¶

14 Other (specify):

__________________________________________ _________¶ ¶Form Approved __/__/__ OMB Control No. ____-____

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### 11 or tank truck terminal that is located near the refinery and is owned, operated, or under common control of the refinery (or its corporate holdings), report the transportation method as tank ship or tank truck, respectively, rather than reporting this quantity as “% shipped by pipeline.” Report under “% shipped by pipeline” all products shipped via general use pipelines (regardless of secondary transportation methods that may be served) or products piped directly to other offsite facilities.

Product/Refinery Output Cumulative

2010

Production (1,000 bbls) Disposition of Products by Transport Method

% used

onsite % shipped by tank

ship % shipped

by barge % shipped by tank

truck % shipped by rail

car % shipped

by pipeline



### Ethane
Ethylene

Propane
Propylene

Normal Butane
Butylene

Isobutane
Isobutylene
Unfinished Oils – Naphthas and lighter

Unfinished Oils – Kerosene and light gas oils
Unfinished Oils – Heavy gas

oils

Unfinished Oils – Residuum

Finished Motor Gasoline -

Reformulated

Finished Motor Gasoline -

Conventional
Motor Gasoline Blending Components - Reformulated
Motor Gasoline Blending Components - Conventional

Aviation Gasoline – Finished and Blending Components
Special Naphthas (solvents)
Kerosene-type Jet Fuel

Kerosene
Distillate Fuel Oil – 15 ppm

sulfur and under
Distillate Fuel Oil – greater than 15 ppm to 500 ppm

sulfur
Distillate Fuel Oil – greater than 500 ppm sulfurForm Approved __/__/__ OMB Control No. ____-____

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### 12 Product/Refinery Output Cumulative

2010

Production (1,000 bbls) Disposition of Products by Transport Method

% used

onsite % shipped by tank

ship % shipped

by barge % shipped by tank

truck % shipped by rail

car % shipped

by pipeline



### 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

ProductsForm Approved __/__/__ OMB Control No. ____-____

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

rates had these issues not occurred.

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

Provide the coordinates (latitude and longit ude) of the approximate process unit centroid in North American Datum (NAD) 83 with 6 di gits to the right of the decimal point. d 

### (If currently available coordinates have five digits to the right of the decimal point instead of six, those coordinates are acceptable.).

d Latitude measure in decimal degrees of the angular distance on a meridian north or south of the equator. Positive (+) data point for North America. Example: +78.123456. For point sources, this represents the center of the source; for fugitive sources, this is the southwest corner if the fugi tive angle is zero or the western most corner if the fugitive angle is greater than zero. Longitude measure in decimal degrees of the angular distance on a meridian east or west of the prime meridian. Negative (-) data point for North America. Example: -123.234561. For point sources this represents the center of the source; for fugitive sources, this is the southwest corner if the fugitive angle is zero, or the western most corner if the fugitive angle is greater than zero. Deleted: Attachment 1 to this enclosure is a copy

of the

Deleted: for each of your refineries (if available) for your reference. When asked for a Unit ID in Questions 15 and 16, please use the same identifying

number or code that is used in the NEI data set

Deleted: Processin g Unit ... [1]

Deleted: (See instructions to Part II, Annex A for additional details on latitude and longitude format.)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 14 Unit

ID Process Type 1 

### Unit Throughput

Capacity (bbl/cd) 2 

### Unit ActualThroughput (bbl/cd) 2 

### Unit

Latitude Unit Longitude

1 See list following the last footnote for codes corresponding to un it 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 (e xcluding hydrogen gas inputs).

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

For alkylation through coke calcining (process type codes 22 through 43), “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 production, thro ughput units are million standard cubic feet per calendar day (MMcf/cd); use 32°F (0°C) and 1 atmosphere as “standard conditions” for H 2 production.

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 th e sulfur recovery plant for each train in Part II, Section 9.

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

For fuel gas treatment, “throughput” is the quantity of fuel gas input to the unit. Throughput units are million standard

cubic feet per calendar day (MMcf/cd); use 60°F (15.56°C) and 1 atmosphere as “standard conditions” for fuel gas

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

For wastewater treatment, throughput units are million gallons per day (MMgal/day). If desired, you may report

wastewater treatment units used to comply with Benzen e Waste Operations NESHAP (40 CFR part 61, subpart FF) “BWON” or sour water treatment units as separate wastew ater treatment systems, but you are not required to do so. Inserted Cells Deleted: 1

Deleted: 3

Deleted: 4

Deleted: Processing Unit

Deleted: Lat

Deleted: Long

Deleted: Lat

Deleted: Long

Deleted: Lat Deleted: Lon g

Deleted Cells

Deleted: Lat

Deleted Cells Deleted: Lon g

Deleted Cells

Deleted: Atmospheric crude distillation

Deleted: Vacuum distillation

Deleted: Delayed coking

Deleted: Fluid coking (traditional)

Deleted: Flexicoking

Deleted: Visbreaking, other thermal cracking

Deleted: Fluid catalytic cracking unit

Deleted: Non-fluid catalytic cracking unit

Deleted: Catalytic hydrocracking

Deleted: Catalytic reforming unit – continuous

regen.

Deleted: Catalytic reforming unit – cyclic regeneration

Deleted: Catalytic reforming unit – semiregenerative

Deleted: Fuels solvent deasphalting

Deleted: Desulfurization/ hydrotreat – naphtha/CRU feed

Deleted: Desulfurization/ hydrotreat – gasoline

Deleted: Desulfurization/ hydrotreat – kerosene/ jet fuel

Deleted: Desulfurization/ hydrotreat – diesel

Deleted: Desulfurization/ hydrotreat – other

distillate

Deleted: Desulfurization/ hydrotreat – residual

Deleted: Desulfurization/ hydrotreat – heavy gas

oil

Deleted: Desulfurization/ hydrotreat – other ... [2]Form Approved __/__/__ OMB Control No. ____-____

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### 15 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/ hydrotreat – naphtha/reformer feed 15 Desulfurization/ hydrotreat – gasoline 16 Desulfurization/ hydrotreat – kerosene/jet fuel 17 Desulfurization/ hydrotreat – diesel 18 Desulfurization/ hydrotreat – other distillate 19 Desulfurization/ hydrotreat – residual 20 Desulfurization/ hydrotreat – heavy gas oil 21 Desulfurization/ hydrotreat – 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 Ethylene production 38 Ethylene dichloride production 39 Ethylene dibromide production 40 Propylene production 41 Acrylonitrile production 42 Other petrochemical or organic chemical production (specify chemical) 43 Coke calcining 44 Marine vessel loading/unloading 45 Truck/tank truck loading/unloading 46 Rail car loading/unloading 47 Container/other loading/unloading 48 Fuel gas treatment 49 Fuel blending
50 Wastewater treatment system 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

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### 16 

### 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 pr o vi de this number ): ________________________

2. Complete Table 1-1 below to provide the total energy use and fuel consumption by the

entire refinery in 2010 (as reported to EIA on forms EIA-810 and EIA-820):

TABLE 1-1. 20 1 0 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 purcha sed [in million cubic feet at 32°F (0°C) and 1 atmosphere] from off-site (merchant) hydrogen producers. Do not include captive hydrogen production included in Part I; more detail regarding captive hydrogen production units is requested in Part II, Section 10.

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

If Yes : Provide a brief description of the key elements of the plan and key energy reductions that have resulted from the implementation of the plan. Deleted: As noted in Part I, Attachment 1 to this enclosure is a copy of the EPA’s 2005 NATA NEI data set for your refinery (if available) for your

reference.

Deleted: the NEI data set (if possible and/or applicable). If the NEI does not show an entry for a particular unit, or you are not sure what units are included in the NEI data set, use a unique Unit ID for each process unit throughout Part II

Deleted: c

Deleted: response

Deleted: 2009:

Deleted: 9

Deleted: MMcf

Deleted: Petroleum

Deleted: Tons (US)

Deleted: Tons (US)

Deleted: 3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 17 5 . Does this refinery generate electricity or steam on-site? Yes No

If Yes : Provide the information requested in Table 1-2 for each electricity-generating

, steam generating, or combined heat and power unit. Include energy recovery turbines

and waste heat boilers used on process unit exhaust lines.

TABLE 1-2. Electricity and Steam Generation InformationrationUnDescriptPrimary Fuel2Secondary Fuel2Energy EfficiencyMeasures3Air preheat use4Typical air preheattemperature when used (°F)Is this unit a combined heatand power unit? (Yes/No) Electricity

Generation Steam GenerationCapacity of Unit(MW)Disposition ofelectricity5Boiler Heat InputCapacity (MMBtu/hr)Steam GeneratingCapacity (lb/hr)Pressure of Steam(psia)Disposition ofsteam6Percent Steam toBlowdown7



### Footnotes for Table 1-2:

Abbreviations: MW = megawatts

MMBtu/hr = million British thermal units per hour

lb/hr = pounds per hour

psia = pounds per square inch absolute

1 

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

boiler”). Deleted: Unit ID Number

Merged Cells

Deleted: Unit Descri p tion

Merged Cells Deleted: Primar y Fue l Deleted: Secondar y Fuel Inserted Cells

Inserted Cells

Deleted: electricit y 1 Inserted Cells

Deleted: Abbreviation: MW = megawatts¶

1 For disposition of electricity, enter appropriate code number as follows: ¶ Enter “1” if generated electricity is used only on-site. ¶ Enter “2” if generated electricity is used only off-site ( e.g. , sent to grid).¶ Enter “3” if generated electricity is used on-site with excess used off-site or sent to grid.¶ ¶

4. Does this refinery generate steam onsite? Yes No ¶

If Yes : Provide the information requested in Table 1-3 for each steam-generating unit. ¶ TABLE 1-3. Steam Generation Information¶

Unit ID ... [3]Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 18 2 

### Select from the following list of fuels.

Code No. Type of Fuel

1 Natural gas 2 Refinery fuel gas (mixture of natural gas and still gas or process gas) 3 Still gas or process gas only (not mixed with natural gas)

4 Distillate fuel oil 5 Heavy gas oil 6 Low Btu fuel gas from flexicoking un it or other gasification process

7 Coal

8 Wood or other biomass fuel 99 Other (specify)

3 

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

.

Code No. Type of Energy Efficiency Measure

0 None

1 Insulation on boiler

2 Insulation on distribution lines
3 Oxygen monitors used to control/limit excess oxygen

4 Intake air monitors to optimize fuel/air mixtures

5 Combustion air preheat from flue gas

6 Boiler feed water preheat from flue gas

7 Blowdown steam recovery system for low pressure needs 8 Steam trap maintenance

9 Steam condensate return lines (to return condensate (hot water) to boiler) 10 Steam expansion turbines (to recover energy from high pressure steam when steam is needed at lower pressures) 11 Boiler maintenance program to reduce scaling (other than soot blowing) 12 Boiler maintenance program to mainta in burners (other than soot blowing) 99 Other (specify )

4 

### Select from the following list of air preheat descriptions the opt ion that best applies for the unit.

Code No. Type of Air Preheat 0 No air preheater is present 1 Air preheater is present, but use less than 20% of the time 2 Air preheater is present and used 20% to 50% of the time 3 Air preheater is present and used more than 50% but less than 90% of the time 4 Air preheater is present and used 90% or more of the time

5 

### Select from the following list of 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 Deleted: For disposition of steam, enter appropriate code number as follows: ¶

Enter “

Deleted: ” if generated steam is used

Deleted: on-site.

Deleted: Enter “2” if generated steam is used only off-site.¶ Enter “3” if generated steam is used on-site with excess used off-site.¶

Deleted: Enter

Deleted: code number for each

Deleted: steam-generating

Deleted: ;

Deleted: :

Deleted: and intake

Deleted: and limit excess oxygen

Deleted: 4

Deleted: 5

Deleted: 6

Deleted: 7 Boiler maintenance program (to reduce scaling; maintain burners)¶

Deleted: program

Deleted: )__________________Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 19 6 

### 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.

7 

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

answer “Unknown.”Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 20 6 . Provide the information requested in Table 1- 3 for each processing unit listed in Question

16 of Part I (except wastewater treatment systems, which are reported in Section 15 ).

TABLE 1- 3 . Steam Demand by Process Unit

Unit

ID Average steam

demand for the processing unit during normal

operation assuming the processing unit is operated at

maximum capacity (lb/hr) 1

1 

### For cyclic processes, such as delayed coking unit, estimate the total steam use over a complete cycle

and divide by the cycle time indicative of maximum processing rates. Deleted: 5

Deleted: 4

Deleted: Questions 14 and 15

Deleted: 4

Deleted: and Process Heater Capacity

Deleted: Processin g Unit T yp e 1

Deleted Cells Deleted: Steam

Deleted: at capacity Deleted: Total number of p rocess heaters

Deleted Cells Deleted: Cumulative rated heat capacity of

p rocess heaters for p rocess unit (MMBtu/hr)

Deleted Cells Deleted: Number of process heaters with air preheat

Deleted Cells Deleted: Cumulative rated heat capacity of process heaters with air preheat for process unit (MMBtu/hr)

Deleted Cells

Deleted: 

### ¶ ... [4]Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 21 

### SECTION 2. PROCESS HEATER DATA

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

.

TABLE 2-1. Process Heater General InformationProcess Heater IDUnit ID for processunit served byprocess heaterProcess heater construction type1Process heater draft type2Is the process heater designed to be eco-fired?(Yes/No)Rated heatinputcapacity (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 operatinghoursprocess heaterfiredwith primary fuelin2010Secondary fuel5Percent of total operating hoursprocess heater fired with secondaryfuel in 2010Operating hours in turndown in 2010(hr)ApplicableFederalairregulation(s)6If subject to State, local, or Tribalairregulation(s), provide the citation(s)Type of PM controls7Type of SO2controls8Type of NOXcontrols9 Deleted: c

Deleted: response

Deleted: 3. For each process heater listed in Table 2-1, also provide annual PM, SO 2 , NO X , CO, VOC, and HAP emission estimates (tons/yr) following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part. ¶

Deleted: Process

Deleted: 1

Deleted: 2 Deleted: 3 Deleted: Primary fuel 4

Deleted: Secondar y fuel 4

Deleted Cells

Deleted: 9 Deleted:

Deleted: 9 Inserted Cells Inserted Cells

Inserted Cells

Inserted Cells Deleted: O p eratin g Deleted: while coDeleted: 2009 (hr) Inserted Cells Inserted Cells

Deleted:

Deleted: 9 Deleted: If subject to

Deleted: ), p rovide the citation(s) Deleted:

Deleted:

Deleted: 5 Deleted:

Deleted: 6 Deleted:

Deleted: 7

Deleted: 

### ¶ ... [5]Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 22 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 exha ust-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 e fficiency measures (other than air preheat).

Code No. Type of Energy Efficiency Measure

0 None 1 Oxygen monitors used to control/limit excess oxygen 2 Intake air monitors to optimize fuel/air mixtures 3 Maintenance program to reduce scaling (other than soot blowing) 4 Maintenance program to maintain burners (other than soot blowing) 5 Finned or dimpled tubes to increase heat transfer 99 Other (specify) Deleted: 1 Select the process units served by the process heater from the following list.¶

Code No. Type of Process Unit¶

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/ hydrotreat – naphtha/reformer feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet fuel¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – 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 plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

99 Other (specify)¶ ¶

2

Deleted: 3

Deleted: blast

Deleted: /air preheat

Deleted: )Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 23 5 

### Select from the following list of fuels.

Code No. Fuel Type 1 Natural gas 2 Refinery fuel gas (mixture of natural gas and still gas or process gas)

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

4 Distillate fuel oil

5 Heavy gas oil 6 Low Btu fuel gas from flexicoking un it or other gasification process 99 Other (specify)

6 

### Select the Federal air regulation(s) to which the process heater is subject from the following list

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

Code No. Federal Air Regulation

0 None 1 Refinery NSPS (40 CFR part 60, subpart J) 2 Refinery NSPS (40 CFR part 60, subpart Ja) 3 CAA section 112(g) and section 112(j) (40 CFR part 63, subpart B) 99 Other (specify)

7 

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

Code No. Type of PM Control

0 None 11 Fabric/cartridge filter (“baghouse”)

12 Venturi/wet scrubber 13 Electrostatic precipitator (ESP)

14 Wet ESP

96 Management practice or work practice to reduce PM (specify) 99 Other (specify)

8 

### Select from the following list of 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) Deleted: 4

Deleted: 5

Deleted: 98

Deleted: 6

Deleted: 98Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 24 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 inte rnal 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) Deleted: 7Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 25 SECTION 3. EQUIPMENT LEAKS

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

If Yes :

a. Provide the manufacturer and model number: ____________________________

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

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

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

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



### 3. Complete Table 3-1 for each process unit listed in Part I, Question 16 (except wastewater

treatment ). 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. Deleted: c

Deleted: response

Deleted: Do you routinely monitor your fuel gas system for leaks? Yes No ¶

4.

Deleted: Questions 14 and 15

Deleted: ) and

Deleted: fuel gas and natural gas system at the facility.

Deleted: 5. For each process unit and fuel gas and natural gas system listed in Table 3-1, provide annual VOC and HAP emission estimates (tons/yr) for equipment leaks following the methods provided

in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part.¶Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__26TABLE 3-1. Equipment and Leak Detection Informationfor Process Units

it Applicable Federal air regulation(s)
1 If su bj ec t t o St a t e, l oca l , or T r ib a l a i r regulation(s), provide the citation(s) Average methane concentration in process fluid that contacts equipment in gas service throughout the process Is the average methane concentration based on sampling and analysis results or estimated (e.g., based on pro cess knowledge)?For each ofthefollowingtypes ofequipment,provide:Pumps Valves FlangesConnectors de pre s tch gla Gages Diaphragms Other 4

Light liquid
2 Heavy liquid
2 Gas 2 Light liquid
2 Heavy liquid
2 Gas 2 Light liquid
2 Heavy liquid
2 Gas 2 Light liquid
2 Heavy liquid
2Number ofPieces ofEquipmentNumber ofPieces ofEquipmentMonitored5MonitoringFrequency6LeakDefinition(ppmv)7Number ofPieces ofEquipmentNumber ofPieces ofEquipmentMonitored5Deleted:Process-specific ...quipment... [6]Deleted:Deleted:Process Unit Type1Deleted Cells... [7]Deleted:2Deleted:Inserted Cells... [8]Inserted Cells... [9]Inserted Cells... [10]Merged Cells... [11]Deleted:Pressure relief devicesDeleted Cells... [12]Merged Cells... [13]Deleted:OtherMerged Cells... [14]Inserted Cells... [15]Inserted Cells... [16]Inserted Cells... [17]Inserted Cells... [18]Deleted:AnyDeleted:AnyDeleted:AnyDeleted:AnyMerged Cells... [19]Split Cells... [20]Split Cells... [21]Split Cells... [22]Split Cells... [23]Deleted:Number of ComponentsDeleted:Number of ComponentsDeleted:Monitoring Frequency3Deleted:Leak Definition (ppmv)4Deleted:Number of ComponentsDeleted:Monitoring Frequency3Deleted:Leak Definition (ppmv)4Deleted:Number of ComponentsDeleted:Monitoring Frequency3Deleted:Leak Definition (ppmv)4Deleted:Number of ComponentsDeleted:Monitoring Frequency3Deleted:Leak Definition (ppmv)4Deleted:Number of ComponentsDeleted:Monitoring Frequency3Deleted:Leak Definition (ppmv)4Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__27MonitoringFrequency6LeakDefinition(ppmv)7Deleted:¶... [50]Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 28 Footnotes for Table 3-1:

1 

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements 2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements

3 NSPS for Equipment Leaks at Petroleum Refineries ( 40 CFR part 60, subpart GGG ) 4 NSPS for Equipment Leaks at Petroleum Refineries ( 40 CFR part 60, subpart GGGa ) 5 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VV) 6 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VVa) 7 HON (40 CFR part 63, subpart H) existing source requirements 8 HON (40 CFR part 63, subpart H) new source requirements 9 MON (40 CFR part 63, subpart FFFF) existing source requirements 10 MON (40 CFR part 63, subpart FFFF) new source requirements 11 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements 12 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements 13 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements 14 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements 99 Other (specify)

2 

### Use the definitions of “gas service,” “light liquid service,” and “heavy liquid service” in the

regulation to which your process unit is subject, if applicable. See the list of definitions for

this ICR for definitions of these terms to use if your process unit is not subject to a regulation

that includes definitions of these terms.

3 

### The information requested for open-ended lines refers to leakage from the open-end of a pipe or

valve 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-mo nitor equipment in this count. Deleted: from the following list of process unit types.¶

Code No. Type of Process Unit¶

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/ hydrotreat – naphtha/reformer feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet fuel¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – 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 plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

37 Marine vessel loading/unloading¶

38 Truck/tank truck loading/unloading¶

39 Rail car loading/unloading¶

50 Fuel gas system¶

51 Natural gas system¶

99 Other (specify)¶ ¶

2 Select

Deleted: applicable

Deleted: 40 CFR part 60, subpart VV¶

4

Deleted: 5 40 CFR part 60, subpart VVa¶

6

Deleted: 3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 29 6 

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

frequency at which the majority of the equipment are monitored for the process unit, type of equipment, and type of service. (For “other,” if you specified multiple types of fugitive emission sources and they have different 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 only for sensory monitoring)

2 Less than annually

3 Annually

4 Semiannually

5 Quarterly

6 Monthly

7 Biweekly

8 Weekly or more frequently

7 

### Select from the following list of leak definitions the monitored concentration above which

repairs are required (or routinely performed ) for the process unit, type of equipment, and type

of service. (For “other,” if you specified multiple types of fugitive emission sources and they have different leak definitions, select th e lowest leak definition for such sources.)

Code No. Leak Definition 0 None (unit/system not monitored for leaks)

1 Detection by sensory monitoring

2 10,000 ppmv

3 5,000 ppmv

4 2,000 ppmv

5 1,000 ppmv

6 500 ppmv

7 Less than 500 ppmv



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

Deleted: equipment component, and

Deleted: service.

Deleted: 1

Deleted: 2

Deleted: 3

Deleted: 4

Deleted: 5

Deleted: 6

Deleted: 7

Deleted: 4

Deleted: )

Deleted: component

Deleted: 2

Deleted: 3

Deleted: 4

Deleted: 5

Deleted: 6Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__30TABLE 3-2. Equipment and Leak Detection Information for Fuel Gas and Natural Gas Systems

Unit ID Applicable Federal air regulation(s)
1 If subject to State, local, or Tribal air regulation(s), provide the citation(s) Average methane concentration in process fluid that contacts equipment in gas service throughout the process Is the average methane concentration based on sampling and analysis results or estimated (e.g., based on process knowledge)?For each of the followingtypes of equipment,provide:PumpsValvesFlangesConnectors Open-ended lines
3

Compressors Hatches Sight glasses Gages Diaphragms Other 4

Light liquid
2 Heavy liquid
2 Gas 2 Light liquid
2 Heavy liquid
2 Gas 2 Light liquid
2 Heavy liquid
2 Gas 2 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 __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 31 Footnotes for Table 3-2:

1 

### Select the Federal air regulation to which the fuel gas or natural gas system is subject from the

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

Code No. Federal Air Regulation

0 None 1 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGG) 2 NSPS for Equipment Leaks at Petroleum Refineries (40 CFR part 60, subpart GGGa) 3 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VV) 4 NSPS for Equipment Leaks at SOCMI (40 CFR part 60, subpart VVa) 99 Other (specify)

2 

### Use the definitions of “gas service,” “light liquid service,” and “heavy liquid service” in the

regulation to which your process unit is subject, if applicable. See the list of definitions for

this ICR for definitions of these terms to use if your process unit is not subject to a regulation

that includes definitions of these terms.

3 

### The information requested for open-ended lines refers to leakage from the open-end of a pipe or

valve 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-mo nitor equipment in this count.

6 

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

Code No. Monitoring Frequency 0 None (unit/system not monitored for leaks) 1 No set interval (use only for sensory monitoring) 2 Less than annually 3 Annually 4 Semiannually 5 Quarterly 6 Monthly 7 Biweekly 8 Weekly or more frequentlyForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 32 7 

### Select from the following list of leak definitions the monitored concentration above which

repairs are required (or routinely performed) for the process unit, type of equipment, and type of service. (For “other,” if you specified mult iple types of fugitive emission sources and they have different leak definitions, select th e 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 ppmvForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__5. Provide the information requested in Table 3-3regarding pressure relief devices(PRD)on each process unit listed in Part I,Question 16(except wastewater treatment) and for each fuel gas and natural gas system at the facility.TABLE 3-3. Pressure Relief Devices

Unit ID, Fuel Gas System ID, or Natural Gas System ID Total number of PRDNumber of PRDrouted to fuel gassystem or controldeviceAtmospheric PRDGasLiquidGasLiquid

Numb er of PRD of contro Number of PRD Type of controls
1 Number of PRD ed with ruptur e diskMethod 21Monitoringfor LeaksMonitoring of Releases Number of PRD Number equipped with rupture disk or second valveMethod 21Monitoringfor LeaksMoni

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 measure the duration of a D escribe your monitoringDeleted:6Deleted:2Deleted:Questions 14 and 15Deleted:2Deleted:Unit IDMerged Cells... [51]Deleted:Process Unit Type1Deleted Cells... [52]Deleted:Total number of pressure relief devicesMerged Cells... [53]Deleted:Number of pressure relief devices... [54]Merged Cells... [55]Deleted:Type of controls2Merged Cells... [56]Deleted:Number of pressure relief valves... [57]Merged Cells... [58]Inserted Cells... [59]Inserted Cells... [60]Inserted Cells... [61]Deleted:If you monitor yourpressure relief... [62]Deleted:?Inserted Cells... [63]Inserted Cells... [64]Inserted Cells... [65]Inserted Cells... [66]Deleted:If you haveDeleted:monitoringDeleted:that measuresDeleted:, describe the systemInserted Cells... [67]Deleted:¶... [68]Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 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 m onitoring frequencies the option that best applies

for the process unit, type of equipment, and type of service. Select “0” if the PRD are not monitored regularly on a set schedule ( i.e. , they are only monitored after a release to confirm that there are no detectable emissions).

Code No. Monitoring Frequency 0 None (unit/system not monitored for leaks using Method 21 (but may be monitored using sensory methods)) 1 Less than annually 2 Annually 3 Semiannually 4 Quarterly 5 Monthly 6 Biweekly 7 Weekly or more frequently 8 Only after releases

3 

### Select from the following list of leak definitions the monitored concentration above which

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

Code No. Leak Definition 0 None (unit/system not monitored for leaks using Method 21 (but may be monitored using sensory methods))
1 10,000 ppmv
2 5,000 ppmv 3 2,000 ppmv 4 1,000 ppmv
5 500 ppmv 6 Less than 500 ppmv Deleted: 2

Deleted: units.¶

Code No. Type of Process Unit¶

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

Deleted: ¶

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/ hydrotreat – naphtha/reformer feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet

Deleted: ¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – 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 plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

37 Marine vessel loading/unloading¶

38 Truck/tank truck loading/unloading¶

39 Rail car loading/unloading¶

50 Fuel

Deleted: ¶

51 Natural

Deleted: 99 Other (specify)¶ ¶

2 Select from the following list of controls. List all that apply¶

Deleted: 53

Deleted: 98Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 4. STORAGE TANKS

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

If Yes , provide the following information:

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

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

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

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

____________________ MMscf at 60 °F and 1 atmosphere

4. Please provide information requested in Table 4- 1 for each storage tank at the facility.

TABLE 4-1. Storage Tank General InformationTank IDType of stored liquid1Maximum true vaporpressure ofhydrocarbons instored liquidin 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)ApplicableFederalairregulation(s)3If subject to State, local, or Tribalairregulation(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 2010 Deleted: c

Deleted: response

Deleted: 3. For each storage tank listed in Table 4-1, also provide annual VOC and HAP emission estimates (tons/yr) following the methods provided

in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part. ¶

Formatted Table

Deleted: Deleted: Va p or

Deleted: at average liquid storage temperature

in 2009 Deleted: Average liquid storage temperature in 2009 (°F)

Deleted: 9 Deleted: If sub j ect to

Deleted: ), provide the citation(s) Deleted:

Deleted: 3 Inserted Cells Inserted Cells

Deleted: Deleted: 9

Deleted: 9

Inserted Cells

Inserted Cells

Deleted: 

### ¶ ... [69]Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 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 foll owing 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 oil s 13 Unfinished Oils – Heavy gas oils

14 Unfinished Oils – Residuum

15 Finished Motor Gasoline - Reformulated

16 Finished Motor Gasoline - Conventional 17 Motor Gasoline Blending Components - Reformulated 18 Motor Gasoline Blending Components - Conventional

19 Aviation Gasoline – Finished and Blending Components 20 Special Naphthas (solvents) 21 Kerosene-type Jet Fuel

22 Kerosene 23 Distillate Fuel Oil – 15 ppm sulfur and under 24 Distillate Fuel Oil – greater than 15 ppm to 500 ppm sulfur 25 Distillate Fuel Oil – greater than 500 ppm sulfur

26 Residual Fuel Oil – less than 0.31% sulfur

27 Residual Fuel Oil – 0.31% to 1.0% sulfur 28 Residual Fuel Oil – greater than 1% sulfur 29 Lubricants (total)

30 Asphalt and Road Oil

31 Wax

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

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

35 Aromatics – Benzene

36 Aromatics – Toluene 37 Aromatics – Xylenes (total)

38 Aromatics – Other than BTX 99 Other (specify) Deleted: 3 Intermediate naphtha¶

4 Intermediate distillate oil¶

Deleted: Intermediate heavy

Deleted: 6

Deleted: /blending stocks

Deleted: 7

Deleted: fuels

Deleted: 8 No. 2 diesel fuel¶

9 No. 4 diesel fuel (heavy fuel oil)¶

10 No. 6 diesel fuel (marine diesel/bunker C)¶

11 Lubricating/motor oil¶

12 Petroleum coke¶

13

Deleted: 14 Sulfur¶

15 Ethylene¶

16 LPG (propane/butane)¶

17

Deleted: 18

Deleted: petrochemicals (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

2 

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

See the list of definitions for this ICR for detail s on what is considered a controlled guidepole.

Code No. Type of Tank/Control 1 Fixed roof tank vented to atmosphere

2 Fixed roof tank vented to control device 3 Fixed roof tank using vapor balancing 4 External floating roof, slotted guidepoles 5 External floating roof with solid guidepoles 6 External floating roof, controlled guidepoles 7 Internal floating roof, slotted guidepoles 8 Internal floating roof with solid guidepoles 9 Internal floating roof, controlled guidepoles 10 External floating roof with geodesic dome roof

11 Horizontal tank 12 Pressurized/sphere tank 99 Other (specify)

3 

### Select the Federal air regulation(s) to which the storage vessel is subject from the following list

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements 2 Refinery MACT (40 CFR part 63, subpart CC) new source requirements 3 HON (40 CFR part 63, subpart H) existing source requirements 4 HON (40 CFR part 63, subpart H) new source requirements 5 NSPS for Storage Vessels (40 CFR part 60, subpart K) 6 NSPS for Storage Vessels (40 CFR part 60, subpart Ka) 7 NSPS for Storage Vessels (40 CFR part 60, subpart Kb) 8 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements 9 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements 10 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements 11 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements 99 Other (specify)

4 

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

list of controls.

Code No. Type of Degassing Control 0 None; tank vented to atmosphere while being degassed 54 Portable internal combustion engine

55 Portable thermal oxidizer 56 Portable condensation system

57 Permanent onsite control device 99 Other (specify) Deleted: a

Deleted: b

Deleted: c

Deleted: a

Deleted: b

Deleted: c

Deleted: a A guidepole that has slots or holes through the wall of the pole. The slots or holes allow the stored liquid to flow into the pole at liquid levels above the lowest operating level.¶

b A guidepole that has no slots or holes through the wall of the pole.¶

c Control measures described for storage tank emission reduction partnership program (STERPP) at 72 FR 19891.¶ ¶Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

5 

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

Code No. Year

0 2010

1 2011

2 2012

3 2013

4 2014

5 2015

6 2016

7 2017

8 2018

9 2019

10 2020 or later

6 

### Select the type of primary rim seal.

Code No. Type of Rim Seal

0 None 1 Vapor-mounted seal; flexible wiper type 2 Vapor-mounted seal; resilient-filled type 3 Liquid-mounted seal

4 Mechanical-shoe seal

7 

### Select the type of secondary rim seal.

Code No. Type of Rim Seal

0 None

1 Rim-mounted seal

2 Shoe-mounted seal 3 Vapor-mounted seal; flexible wiper typeForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 5. CATALYTIC CRACKING UNIT

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

.

TABLE 5-2. Catalytic Cracking Unit InformationUnit ID forCCUFresh 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 of othercombustion device after CCUregenerator (Yes/No)?ApplicableFederalairregulation(s)1If subject to State, local, orTribalairregulation(s), providethe citation(s)2010 Weighted Average SulfurConcentration in CombinedFeed (wt%)2010 Weighted AverageNickelConcentration in CombinedFeed (wt%)2010 Weighted AverageVanadium Concentration inCombined Feed (wt%)Type of PM controls2Type of SO2controls3Type of NOXcontrols4



### Footnotes for Table 5-2:

1 

### Select the Federal air regulation(s) to which the CCU is subject from the following list of

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT 2 (40 CFR part 63, subpart UUU) existing source requirements 2 Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements 3 Refinery NSPS (40 CFR part 60, subpart J) 4 Refinery NSPS (40 CFR part 60, subpart Ja) 99 Other (specify) Deleted: c

Deleted: response

Deleted: If the facility has metal concentration for E-cat and/or fines, provide annual average values

Deleted: in the Table 5-1 below.

Deleted: TABLE 5-1. E-Cat and FCCU Fines Metal Concentration¶

CCU ID ... [70]

Formatted Table

Deleted: ID Deleted: Deleted: If subject to

Deleted: ), provide the citation(s) Deleted: Inserted Cells

Deleted:

Deleted: 1 Deleted:

Deleted: 2 Deleted:

Deleted: 3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

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 coke burn-off, but not 50/25 ppmv SO 2 

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

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) Deleted: 98

Deleted: 2

Deleted: 98

Deleted: 3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



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

TABLE 5-2. E-Cat and CCU Fines Metal 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 __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 6. FLUID COKING UNIT

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

TABLE 6-1. Fluid Coking Unit InformationUnit ID forFCUFeed Capacity (bbl/cd)Type of FCU (traditional orflexicoker)ApplicableFederalairregulation(s)1If subject to State, local, or Tribalairregulation(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 the FCU is subject from the following list of

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements 2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements 3 Refinery NSPS (40 CFR part 60, subpart Ja) 99 Other (specify) Deleted: c

Deleted: response

Deleted: 3. For each FCU listed in Table 6-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided

in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part. ¶

Formatted Table

Deleted: ID Deleted: Deleted: If sub j ect to

Deleted: ), p rovide the citation(s) Deleted:

Deleted:

Deleted: 1 Deleted:

Deleted: 2 Deleted:

Deleted: 3

Deleted: 4

Deleted: Deleted: 5 Deleted: 6Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

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 (0.3 wt% or less) feed

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) Deleted: 98

Deleted: 2

Deleted: 98

Deleted: 3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

5 

### Select from the following list the combina tion that best describes the coke handling and

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

Code No. Disposition Code Letter Storage/Handling Method 1 Shipped off-site to coke calciner A Enclosed conveyer to silo for loading/processing
2 Shipped off-site to be used as fuel B Open conveyer to silo for loading/processing
3 Shipped off-site: some to coke

calciner and some as fuel C Enclosed conveyer to open storage pile or bin, wind break only
4 Shipped off-site: other or unknown

use D Enclosed conveyer to open storage pile or bin, wetting only
5 Processed in on-site coke calciner E Enclosed conveyer to open storage pile or bin, wind break and wetting
6 Used on-site as fuel F Open conveyance to open storage pile or bin, wind break only
7 Some used on-site as fuel,

remainder sent off-site to coke

calciner G Open conveyance to open storage pile or bin, wetting only

8 Some used on-site as fuel,

remainder sent off-site for use as

fuel H Open conveyance to open storage pile or bin, wind break and wetting

99 Other (specify) Z Other (specify)

6 

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

Code No. Low Btu Gas Sulfur Control

0 None 1 Conventional amine scrubber ( e.g. , MEA, MDEA ) 2 Sterically-hindered amine scrubber ( e.g. , Flexsorb ®)

3 Selexol®

4 Rectisol® 5 COS hydrolysis + conventional amine scrubber 6 COS hydrolysis + sterical ly-hindered amine scrubber 7 COS hydrolysis + Selexol® 8 COS hydrolysis + Rectisol®

9 Sulfinol ® 98 Management practice or work practice (specify) 99 Other (specify) Deleted: 4

Deleted: 5

Deleted: DMEA

Deleted: FLEXSORBForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

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) Deleted: 6

Deleted: of

Deleted: sForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 7. DELAYED COKING UNIT

1. Facility ID number (EPA will pr o vi de 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 fractionator and the fractionator.

TABLE 7-1. Delayed Coking Unit Operating InformationfcitaType of Coke Produced1CeglrustmWWater Height in Coke Drum When First Vented toAtmosphere (ft) Cycle Time Quench

W tApplicableFederalairregulation(s)7IfsubjecttoState,local,orTribalairregulation(s),id h i i ( )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 SteamBlowdown System Description4Quench WaterDisposition5C tti W t St /H dli6 Deleted: c

Deleted: response

Deleted: 3. For each DCU listed in Table 7-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided

in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part. ¶

Moved (insertion) [1]

Moved (insertion) [2]

Deleted: DCU ID

Merged Cells Deleted: Feed Capacity (bbl/cd)

Merged Cells

Deleted: Coke Production Ca p acit y (tons/cd)

Merged Cells Moved up [1]: Number of Coke Drums

Merged Cells Deleted: Height of Single Coke Drum (ft)

Merged Cells Deleted: Diameter of Single Coke Drum (ft)

Merged Cells Deleted: Typical Coke Drum Outage (ft)

Merged Cells Deleted: If subject to Federal regulation(s),

p rovide the citation(s)

Merged Cells Deleted: If subject to State, local, or Tribal regulation(s), provide the citation(s)

Merged Cells

Deleted: 1 Deleted: Coke Drum Pressure When First Vented to Atmosphere (psig)

Deleted Cells

Deleted: Coke Drum Temperature at Top of

Drum When First Vented to Atmos p here (°F)

Deleted Cells

Moved up [2]: Water Height in Coke Drum

When First Vented to Atmos p here (ft)

Deleted Cells

Deleted: 2

Deleted: 3 Inserted Cells

Deleted: 4Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### Footnotes for Table 7-1:

1 

### Select from the following list of produced coke types.

Code No. Quench Water Source 1 Needle coke, anode grade 2 Needle coke, fuel grade 3 Sponge coke, anode grade 4 Sponge coke, fuel grade 5 Shot coke, anode grade 6 Shot coke, fuel grade 99 Other (specify)

2 

### Complete coke drum cycle time is from the start of one feed cycle to the start of the next feed

cycle for a single drum and should equal feed time + steam time + cooling time + venting time + cutting time + preheat/standby time.

3 

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

Code No. Quench Water Source 1 Use “tap” water ( i.e. , water purchased directly from utility or drinking water) 2 Use process or recycled blowdown water 3 Use recycled cutting water with “tap” water make-up 4 Use recycled cutting water with process or blowdown water make-up 5 Use treated water from sour water stripper 6 Use treated water from wastewater treatment system 99 Other (specify) Deleted: ¶

2Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

4 

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

exhausted during the steam purge and water quench cycles (prior to venting the vessel to atmosphere)

.

Code No. Condensed Water Disposition Code Letter Uncondensed Vapor Disposition

When Not Sent Directly to DCU

Fractionator

1 Sent to wastewater treatment
system A Not applicable; uncondensed vapors are always sent to DCU fractionator
2 Sent to sour water stripper B Uncondensed vapors are sent to

dedicated DCU flare
3 Used to make steam C Uncondensed vapors are sent to flare 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 wate r disposition (referring to water drained from the

drum after the vessel is vented to the atmosphere).

Code No. Quench Water Disposition 1 Sent to wastewater treatment system 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) Deleted: 3

Deleted: s

Deleted: 4Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

6 

### Select from the following list of cuttin g water storage/handling method combinations.

Code No. Cutting Water Source Code Letter Cutting Water Storage/Handling

1 Use “tap” water 

### A Uncovered gravity settling pond

2 Use process or blowdown

water 

### B Covered gravity settling pond/tank

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

### C Mechanical filtration ( e.g. , centrifugal, filter press) to open storage tank or pond
4 Use recycled cutting water with process or blowdown water make-up 

### D Mechanical filtration ( e.g. , centrifugal, filter press) to covered storage tank or pond

5 Use treated water from sour water stripper 

### E Directed to sour water stripper

6 Use treated water from

wastewater treatment system 

### F Directed to wastewater treatment system

99 Other (specify) 

### Z Other (specify)

7 

### Select the Federal air regulation(s) to which the DCU is subject from the following list of

regulations. Select all that apply, but includ e 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 __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



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

set of similar DCU.

TABLE 7-2. Delayed Coking Unit Feed Information

Feed Source DCU ID(s): ____________ DCU ID(s): ____________

Typical

% Feed 1 

### Maximum

% Feed 2 

### Typical

% Feed 1 

### Maximum

% Feed 2



### Atmospheric tower bottoms

Heavy gas oil

Vacuum tower bottoms

Other residual gas oil

Recovered materials

- Recovered oil ( e.g. , slop oil)

- Sludges from crude oil storage tanks

- Sludges from other storage tanks

- Biosolids from wastewater treatment

system

- Other sludges from wastewater

treatment system

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 source that can be used in the DCU. The sum of all values in

this column is expected to exceed 100%. Deleted: 4

Deleted: IDsForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 8. CATALYTIC REFORMING UNIT

1. Facility ID number (EPA will pr o vi de 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 forCRUFeed Capacity (bbl/cd)Operating Pressure(psig)Hydrogen Production Rate (purifiedbasis) (MMscf/cdat 0°C and 1 atm)Type of CRU Regeneration(continuous, cyclic, orsemi-regenerative)ApplicableFederalairregulation(s)1If subject to State, local, or Tribalairregulation(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 VentDi i i / l7Chloriding Agent8 Deleted: c

Deleted: response

Deleted: 3. For each CRU listed in Table 8-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided

in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part. ¶

Deleted: ID Deleted: Deleted: If sub j ect to

Deleted: ), p rovide the citation(s) Deleted:

Deleted: Average Annual Regeneration Time (hours/ y ear)

Deleted Cells Inserted Cells

Deleted: 1

Deleted: 2 Deleted: 3

Deleted: 4 Inserted Cells

Deleted: 5Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### Footnotes for Table 8-1:

1 

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

regulations. Select all that apply, but includ e 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, s ubpart UUU) existing source requirements 2 Refinery MACT 2 (40 CFR part 63, subpart UUU) new source requirements 99 Other (specify)

2 

### If the unit does not regenerate catalyst at least once a year, estimate the number of cycles based

on the interval between cycles. If the interval between cycles varies, you may use the interval between the two most recent cycles. For example, if regeneration occurs once every two years, then the number of cycles per year would be 1 cycle ÷ 2 years = 0.5 cycles per year. The number of hours per year may be estimated by multiplying an average number of hours per cycle by the calculated number of cycles per year.

3 

### Select from the following list of purge controls.

Code No. Type of Depressurization/Purge Control 0 Directly to the atmosphere 1 To fuel gas system, then atmosphere 2 To fuel gas system, then flare, then atmosphere 3 To flare, then atmosphere 4 To process heater or boiler, then atmosphere 95 Management practice or work practice to reduce VOC (specify) 99 Other (specify)

4 

### Select from the following list of purge processes.

Code No. Type of Purge Process 1 Purge by sequential pressurizing/purging with nitrogen 2 Purge using nitrogen and vacuum pump 3 Purge by sequential pressurizing/purging with methane 4 Purge using methane and vacuum pump 99 Other (specify) Deleted: 2Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

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 li st 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) Deleted: 3

Deleted: 98

Deleted: 4

Deleted: 1 Purge by sequential pressurizing/purging with nitrogen¶

2 Purge using nitrogen and vacuum pump¶

98

Deleted: 5Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 9. SULFUR RECOVERY UNIT

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

TABLE 9-1. Sulfur Recovery Unit InformationUnit ID forSRUSulfur, Sulfur Cake or H2SO4Production Capacity (long tonsof sulfur/cd)Type of SRU1Sulfur Recovery Plant (SRP) ID2ApplicableFederalairregulation(s)3If subject to State, local, orTribalairregulation(s), providethe citation(s)Type of Tail Gas TreatmentUnit4PrimarySulfur Pit ControlsPrimarySulfur Pit MaintenanceTimein 2010(hr/yr)SRU Back-upControls/Reduction Measures5 Deleted: c

Deleted: response

Deleted: 3. For each SRU listed in Table 9-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided

in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part. ¶

Formatted Table

Deleted: ID Deleted:

Deleted:

Deleted: Inserted Cells

Deleted: If subject to

Deleted: ), provide the citation(s) Deleted:

Deleted: 2

Deleted: 3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### Footnotes for Table 9-1:

1 

### Select from the following list of sulfur recovery units.

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

5 EuroClaus® 6 SubDewPoint MCRC-SuperClaus®

7 LoCat®

8 Caustic scrubber 9 Sulfuric acid plant 99 Other (specify)

2 

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

units share the same source of sour gas. Sulfur recovery units that receive source gas from completely segregated sour gas treatment systems are considered part of separate SRP.

3 

### Select the Federal air regulation(s) to which the SRU is subject from the following list of

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT 2 (40 CFR part 63, s ubpart 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 LoCat®

8 Wellman-Lord 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

5 

### Select from the following li st 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 producti on of high sulfur fuel gas) 98 Management practice or work practice (specify) 99 Other (specify) Deleted: 3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 10. HYDROGEN PLANT VENT

1. Facility ID number (EPA will pr o vi de this number ): ______________________

2. Please provide information requested in Table 10-1 for each hydrogen plant at the facility.

TABLE 10-1. Hydrogen Plant and Vent InformationUnit ID forHydrogen PlantHydrogen Production Capacity(purified basis) (MMscf/cdat0°C and 1 atm)Type of Hydrogen ProductionUnit1ApplicableFederalairregulation(s)2If subject to State, local, orTribalairregulation(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) Deleted: c

Deleted: response

Deleted: 3. For each hydrogen plant listed in Table 10-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part. ¶

Formatted Table

Deleted: ID Deleted: Deleted: If subject to

Deleted: ), p rovide the citation(s) Deleted:

Deleted: 2 Deleted:

Deleted: 3 Deleted: 4Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

2 

### Select the Federal air regulation(s) to which the hydrogen plant is subject from the following

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements 2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements 99 Other (specify)

3 

### Select from the following list of hydrogen purification processes.

Code No. Type of Hydrogen Purification Process 1 Pressure-swing adsorption 2 Membrane separation 3 Cryogenic separation 99 Other (specify)

4 

### Select from the following list of feedstocks.

Code No. Type of Hydrogen Production Unit Feedstock

1 Methane 2 Refinery fuel gas 3 Refinery fuel gas augmented with additional methane 99 Other (specify)

5 

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

Code No. Disposition of the PSA Purge/Off Gas

1 Used as fuel in the reformer furnace 2 Used as fuel elsewhere in the refinery

3 Sent to flare 4 Vented to atmosphere 99 Other (specify) Deleted: 3

Deleted: 4Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 11. OTHER ATMOSPHERIC VENTS

1. Facility ID number (EPA will pr o vi de this number ): ______________________

2. Please provide information requested in Table 11-1 for each “other atmospheric vent” at the facility. “Other atmospheric vents” in clude any continuous or intermittent process vents located at the facility and under common control other than those vents specifically covered in Sections 5 through 10 of this part (Part II) vents associated with process heater or boiler exhausts, and wastewater vents . “Other atmospheric vents” include distillation

tower vents ; blowdown systems vents , knock-out pot vents , vacuum ejectors (hot well vents), analyzer vents as well as vents from Merox TM 

### treatment systems, fuel gas

treatment units (if any), catalytic hydrocracking units (if any), asphalt blowing stills, and coke calcining units . The focus of this section is primarily on vents directed directly to the atmosphere during normal operation, and vents recycled to process units , vents directed to a fuel gas system, or vents directed to a flare are not considered “other atmospheric vents ”. Also, “other atmospheric vents” do not include pressure relief vents where venting occurs only during upset, startup, or shutdown events or vents associated with storage tanks.

TABLE 11-1. Other Atmospheric Vent InformationAtmospheric VentIDTypeofAtmospheric Vent1UnitID (ifapplicable) withwhichthe Vent isAssociated2ApplicableFederalairregulation(s)3If subject to State,local, or Tribalairregulation(s),provide thecitation(s)Atmospheric VentOperating Hours4Atmospheric VentControls5 Deleted: c

Deleted: response

Deleted: on

Deleted: pots

Deleted: , and sampling systems

Deleted: oxygenate production

Deleted:

,

Deleted: , ethylene production units, and other

Deleted: co-located at the facility. “Other

Deleted: ”

Deleted: vents associated with storage tanks or

Deleted: . For “other atmospheric vents” controlled by flares, also complete Table 12-1 to

describe the flare.

Deleted: 3. For each “other atmospheric vent” listed in Table 11-1 (except for vents controlled by a flare), also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part. Report the criteria pollutant and HAP emission estimates (tons/yr) from vents controlled by a flare as emissions from the flare following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part.¶

Formatted Table

Deleted: Descri p tion Deleted: T yp e of

Deleted: /Equipment to Which

Deleted: 1 Deleted: If subject to

Deleted: ), p rovide the citation(s) Deleted:

Deleted: 2 Deleted: 3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### Footnotes for Table 11-1:

1 

### Select from the following list of processes and equipment the option that best describe s the type

of unit or equipment associated with this vent.

Code No. Type of Other Atmospheric Vent 1 Atmospheric crude distillation column/reflux condenser vent

2 Catalytic cracking unit distillation column/reflux condenser vent

3 Catalytic hydrocracking unit distillation column/reflux condenser vent

4 Catalytic reforming unit distillation column/reflux condenser vent 5 Coking unit distillation column/reflux condenser vent

6 Other distillation column/reflux condenser vent

7 Vacuum distillation column vacuum system exhaust vent 8 Hot well vent/vacuum jet exhaust 9 Other vacuum system exhaust 10 Drier regeneration vent

11 Coke calcining vent 12 Asphalt blowing still vent 13 Blow down system vent 14 Knock-out pot vent 15 Analyzer vent 16 Process tank (including surge control vessels, bottoms receivers, etc.) 99 Other (specify)

2 

### Enter the Unit ID associated with the vent only if the vent is associated with only one process

unit. If the vent is in general use or used by multiple process units, leav e this question blank. (Any further detail you wish to provide may be included in the “Notes” to this form.

3 

### Select the Federal air regulation(s) to which th e “other atmospheric vent” is subject from the

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements 2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements 3 Refinery NSPS (40 CFR part 60, subpart J) 4 Refinery NSPS (40 CFR part 60, subpart Ja) 99 Other (specify) Deleted: Unit/E q ui p ment Associated with

Deleted: Vacuum distillation¶

3 Delayed coking¶

4 Fluid coking (traditional)¶

5 Flexicoking¶

6 Visbreaking, other thermal cracking¶

7 Fluid catalytic

Deleted: 8 Non-fluid catalytic cracking unit¶

9

Deleted: 10

Deleted: – continuous regeneration

Deleted: 11 Catalytic reforming unit – cyclic regeneration¶

12 Catalytic reforming unit – semi-regenerative¶

13 Fuels solvent deasphalting¶

14 Desulfurization/ hydrotreat – naphtha/reformer feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet fuel¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – 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 plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

37 Marine vessel loading/unloading¶

38 Truck/tank truck loading/unloading¶

39 Rail car loading/unloading¶

40 Blow down system¶

41 Knock-out pot¶

42 Analyzer¶

43

Deleted: jet

Deleted: 50 Wastewater treatment unit¶

51 Wastewater collection system (drain, junction box, etc.)¶

52 Soil remediation¶

60 Ethylene production¶

61 Ethylene dichloride production¶

62 Ethylene dibromide production¶

64 Propylene production¶

65 Acrylonitrile production¶

69 Other petrochemical or organic chemical production (specify chemical)¶

70Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

4 

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

Code No. Type of Operation 1 Continuous (operates whenever the process is operating) 2 Intermittent; 4,000 hours per year or more 3 Intermittent; 2,000 hours or more but less than 4,000 hours per year 4 Intermittent; 1,000 hours or more but less than 2,000 hours per year 5 Intermittent; less than 1,000 hours per year

5 

### Select from the following list of co ntrol 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) Deleted: 6 Only during startup or shutdown¶

7 Only during upsets¶

8 Only during startup, shutdown, or upsets¶ ¶

3

Deleted: 53 Flare¶Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 12. FLARES

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

TABLE 12-1. Flare InformationFlare ID Number orDescriptionIf 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 System3ApplicableFederalairregulation(s)4If subject to State, local, orTribalairregulation(s),provide the citation(s)Typical Lower HeatingValue of Waste Gas(Btu/scf @ 60°F)Flare Operating Hours5FlareManagement Plan6Flare Reduction Measures7 Deleted: c

Deleted: response

Deleted: 3. For each flare listed in Table 12-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided

in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part.¶

Formatted Table Inserted Cells

Deleted: If sub j ect to

Deleted: ), provide the citation(s) Deleted:

Deleted: 4 Deleted: Controls 5 Inserted CellsForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 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 li st of flare assist types.

Code No. Flare Assist Types

1 Unassisted

2 Steam assisted

3 Air assisted 99 Other (specify)

3 

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

Code No. Type of Flare Pilot or Ignition System 1 Continuous pilot flame 2 Spark ignition, every minute regardless of flow 3 Spark ignition, triggered by flow sensor/monitor 99 Other (specify)

4 

### Select the Federal air regulation(s) to which the flare is subject from the following list of

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

Code No. Federal Air Regulation

0 None 1 General Provisions (40 CFR part 60, subpart A) 2 General Provisions (40 CFR part 63, subpart A) 3 Refinery NSPS (40 CFR part 60, subpart J) 4 Refinery NSPS (40 CFR part 60, subpart Ja) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

5 

### Select from the following list of operating scenarios the option that best describes the operation

of the flare

.

Code No. Type of Operation

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

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

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

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

5 Combusts flare gas only during startup or shutdown

6 Combusts flare gas only during upsets

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

6 

### Select from the following list of components of flare management plans the option that best

describes the scope of the flare manageme nt for the flare; list all that apply.

Code No. Components of Flare Management Plan 0 Not applicable. Do not have a flare management plan for minimizing flaring from this

flare. 1 Simplified P&ID (process and instrument diagram) of flare 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 5 Procedure to conduct a root cause and corrective action analysis for flare events exceeding a set SO 2 

### emission level 6 Procedures to conduct root cause and corrective action analysis for flare events exceeding

a set flow rate level 7 Procedures for monitoring flow of gas to the flare 8 Procedures for monitoring Btu of flared gas 9 Procedures for monitoring sulfur content of flared gas 99 Other (specify) Deleted: Operates

Deleted: Intermittent; Operates

Deleted: Intermittent; 1

Deleted: Intermittent;

Deleted: Only

Deleted: Only

Deleted: Only

Deleted: 5Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

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 treatment systems used 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) Deleted: controls

Deleted: minimization plan¶Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 13. FUEL GAS TREATMENT UNIT

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 Treatment Unit InformationFuel Gas Treatment Unit IDUnit ID for each process unit that generatesfuel Gas treated in the treatment unitType 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), provide the citation(s)Are there any atmospheric vents in the system(Yes/No)? (If yes, report in Table 11-1)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 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 LoCat®

15 Caustic scrubber 16 Sodium hydrosulfide (NaSH) production process 99 Other (specify)

2 

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

Code No. Type of Sulfur Containing Compound 1 Hydrogen sulfide (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) to which the fuel gas combustion units are subject from the

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

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

0 None 1 Refinery NSPS (40 CFR part 60, subpart J) 2 Refinery NSPS (40 CFR part 60, subpart Ja) 3 Steam Generation NSPS (40 CFR part 60, subpart D) 4 Steam Generation NSPS (40 CFR part 60, subpart Db) 5 Steam Generation NSPS (40 CFR part 60, subpart Dc) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 14. HEAT EXCHANGE ( COOLING WATER ) SYSTEMS

1. Facility ID number (EPA will pr o vi de 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 InformationHESystem ID Number orDescriptionUnit IDs forProcess UnitsServiced by Cooling WaterSystemCooling Water SystemOperation – Fluid Pressure1Cooling Water SystemVOC/HAP Concentration2Type of Cooling WaterSystem3ApplicableFederalairregulation(s)4If subject to State, local, orTribalairregulation(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 AdditionLocation Deleted: 13.

Deleted: c

Deleted: response

Deleted: 13

Deleted: cooling water

Deleted: 3. For each cooling water system listed in Table 13-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part.¶

Deleted: 13

Deleted: Cooling

Deleted: 1 Deleted: O p eration 2

Inserted Cells

Deleted: If sub j ect to

Deleted: ), provide the citation(s) Deleted:

Deleted: 4 Deleted: Monitorin g Method and Fre q uenc y 5

Deleted Cells

Deleted: Leak Definition

Deleted CellsForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 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 descript ions of the cooling water system VOC and HAP

concentrations.

Code No. Cooling Water System VOC/HAP Concentration

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

2 Services at least one heat exchanger in which the process fluid contains at least 5 wt%

VOC but no heat exchangers with 5 wt% or more organic HAP

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

3 

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

Code No. Type of Cooling Water System 1 Once-through cooling water system 2 Natural draft cooling tower 3 Induced draft cooling tower (fans at outlet) 4 Forced draft cooling tower (fans for inlet air) 99 Other (specify)

4 

### Select the Federal air regulation(s) to which the cooling water system is subject from the

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements 2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements 3 HON (40 CFR part 63, subpart H) existing source requirements 4 HON (40 CFR part 63, subpart H) new source requirements 99 Other (specify) Deleted: 13

Deleted: Select from the following list of process units that best describe the process units serviced by the cooling water system. List all that apply.¶

Code No. Type of Process Unit¶

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/ hydrotreat – naphtha/reformer feed¶

15 Desulfurization/ hydrotreat – gasoline¶

16 Desulfurization/ hydrotreat – kerosene/jet fuel¶

17 Desulfurization/ hydrotreat – diesel¶

18 Desulfurization/ hydrotreat – other distillate¶

19 Desulfurization/ hydrotreat – residual¶

20 Desulfurization/ hydrotreat – heavy gas oil¶

21 Desulfurization/ hydrotreat – 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 plant¶

32 Gas plant (LPG production unit)¶

33 Oxygenate plant – MTBE¶

34 Oxygenate plant – ETBE¶

35 Oxygenate plant – TAME¶

36 Oxygenate plant – other (specify)¶

40 Blow down system¶

99 Other (specify)¶ ¶

2

Deleted: er

Deleted:

Deleted: er

Deleted:

Deleted: 3

Deleted: only heater exchangers

Deleted: less than

Deleted: 4

Deleted: heater exchangersForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

5 

### Select from the following list of chemical additives.

Code No. Type of Chemical Additive/Disinfection Method 1 Chlorine from gas cylinders 2 Sodium hypochlorite 3 Calcium hypochlorite

4 Chloramine

5 Ozonation

6 UV disinfection 99 Other (specify)

Deleted: 5 Select from the following list the combination that best describes the monitoring methods and frequencies for the unit. List all that apply. For example, select 1B and 4E if you conduct daily visual inspections and quarterly measurements using El Paso stripping column.¶

Code No. ... [71]Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 15 . WASTEWATER COLLECTION AND TREATMENT

1. Facility ID number (EPA will pr o vi de this number ): ______________________

2. Please provide the following information for the facility

.

a. What is the daily average wastewater treatment system flow rate (or discharge rate if wastewater is treated off-site)?

b. What is the Total Annual Benzene (TAB) quantity for the facility?

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

1 2 Mg/yr

2 6 BQ

3 Not applicable because TAB < 10 Mg/yr

4 Other (specify)



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

drawdowns:

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

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

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

4. Complete Table 15-1 to indicate the wastewater treatment processes used for each wastewater treatment system (identified in Part 1, Question 16) at the facility and the applicable air regulations for each selected unit. Deleted: 14

Deleted: c

Deleted: response

Deleted: regarding

Deleted: -wide

Deleted: collection and

Deleted: (WWTS).

Deleted: a.

Deleted: b

Deleted: 3. Please provide the information requested in Table 14-1 for the wastewater collection system components.¶ TABLE 14-1. Wastewater Collection System Components¶

Com p onent ... [72]Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### TABLE 15 -1. Wastewater Treatment Processes

Wastewater Treatment System ID Type of

Wastewater

Treatment

Process 1 For Steam and

Sour Water Strippers, also Provide Average

Steam Usage

Rates in 2010 (lb/hr) Applicable Federal air regulation(s) 2 If subject to State, local, or Tribal air regulation(s), provide the citation(s)



### Footnotes for Table 15 -1:

1 

### Select from the following list of wastewater treatment processes.

Code No. Wastewater Treatment Process 0 None (no on-site wastewater treatment units 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 (trick ling filter, rotating biological contactor) 12 Primary clarifier 13 Secondary clarifier 14 Sour water stripper Deleted: 14

Deleted: Collection S y stem Com p onents

Deleted: Com p onent

Formatted Table Deleted: Number Controlled Deleted: Number Uncontrolled

Deleted: Control Technologies 1 Inserted Cells

Deleted: Drain

Merged Cells

Deleted: Trench

Deleted: Manhole

Deleted: Junction Box

Deleted: Sump

Deleted: Lift Station

Deleted: Weir

Deleted: 14

Deleted: 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 Other (specify)¶ ¶

5. Please provide the information requested in

Table 14-2 for each wastewater collection or treatment unit (WWTU) at the facility. For wastewater collection system components, you may aggregate all similar components as a single unit ID number (all drains, all sumps, all lift stations, all junction boxes, et cetera).¶

6. For each WWTU listed in Table 14-2, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided

in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part.¶

TABLE 14-2. Wastewater Collection and Treatment Unit Information¶

WWTS ID Number ... [73]

Deleted: 99 Other (specify)¶Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

2 

### Select the Federal air regulation(s) to which the selected wastewater treatment unit

is subject from the following list of regulations. Select all that apply, but include only regulations to which the wastewater treatment unit is subject according to the applicability of

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

Code No. Compliance Applicability 0 The unit is not subject to any air standards. 1 The unit is subject to BWON (40 CFR part 61, subpart FF) but exempted from control requirements

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

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

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

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



### 5. Please provide the information requested in Table 15-2 for each process unit that routinely generates wastewater.

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) Deleted: from

Deleted: following list

Deleted: combination that best describes the monitoring parameters and frequencies for the

Deleted: . List all that apply. For example, select 13A, 12B, and 22E if you continuously monitor dissolved oxygen concentration, perform daily MLVSS analyses, and perform quarterly benzene concentration analyses.¶

Code No. ... [74]

Deleted: compliance

Deleted: options. List all compliance applicability options that apply to

Deleted: unit (if more than one option applies

Deleted: under the 2 Mg exclusion.

Deleted:

Deleted: but exempted from

Deleted: as an “enhanced biodegradation unit.”

Deleted: The unit is subject to BWON control requirements.¶

4 The unit is subject to and utilized for compliance with the Hazardous Organic NESHAP

Deleted: G).

Deleted: The unit is subject to the

Deleted: ).

Deleted: 4 Select from the following list of emission reduction methods. List all options that apply to the unit (if more than one option applies).¶

Code No. Type of Emissions Reduction Method¶

0 None ¶

1 Wastewater is steam stripped or otherwise treated

in accordance with the standards for treatment processes in 40 CFR 61.348 prior to unit.¶

2 Unit is covered and vented to a control device in compliance with the standards for closed vent systems and control devices in 40 CFR 61.349. ¶

98 Management practice or work practice (specify)¶

99 Other (specify)¶ ¶Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 6. Please provide information requested in Table 15-3 for each “wastewater vent” at the facility. “Wastewater vents” include atmosphe ric vents associated with wastewater drain systems and gases purged from covered wastewater treatment systems.

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 vents the option that best describes this vent.

Code No. Type of Unit/Equipment Associated with Vent 1 Drain system vent

2 Vent from wastewater treatment unit 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

2 

### Select the Federal air regulation(s) to which th e selected wastewater ve nt is subject from the

following list of regulations. Select all that apply, but include only regulations to which the wastewater vent is subject according to the applicability of the regulation ( i.e. , do not select regulations that are referenced from the regulati on(s) to which the wastew ater treatment unit is subject).

Code No. Compliance Applicability 0 The vent is not subject to any air standards. 1 The vent is subject to BWON (40 CFR part 61, subpart FF) but exempted from control requirements. 2 The vent is subject to BWON (40 CFR part 61, subpart FF) control requirements. 3 Refinery MACT (40 CFR part 63, subpart CC) existing source requirements 4 Refinery MACT (40 CFR part 63, subpart CC) new source requirements 5 HON (40 CFR part 63, subpart H) existing source requirements 6 HON (40 CFR part 63, subpart H) new source requirements 7 Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ)

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 co ntrol devices. List all that apply.

Code No. Type of Control Device

0 None 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 __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 16. LOADING OPERATIONS

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

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

0 None. There are no shipments made via marine vessels

1 Marine vessel operations are contiguous with the refinery.

2 Marine vessel operations are conducted on-shor e but are not contiguous with the refinery.

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



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

Yes No

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

Yes No

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

rail car.

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

0 None. There are no shipments made via tank truck

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

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


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

0 None. There are no shipments made via rail car

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

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

Deleted: c

Deleted: responseForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



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

TABLE 16-1. Loading InformationUnit IDfor loading operationType of vesselloaded1Capacity loading throughput(gal/yr)ApplicableFederalairregulation(s)2If subject to State, local, orTribalairregulation(s),provide the citation(s)Typical annual operatinghours (hr/yr)Doesthefacilityorparentcompany own the vessels beingl d d? (Y /N )Type ofcontroldevice orcontrol technique3 Deleted: and unloading

Deleted: at the facility. If you load/unload more than one commodity in a particular location

Deleted: marine vessel berth

Deleted: ), use a separate line for each type of commodity loaded/unloaded at that location.

Deleted: 3. For each loading/unloading location listed in Table 16-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part.¶

Deleted: and Unloadin g

Formatted Table

Deleted: (location)

Deleted: loaded/unoaded 1 Deleted: Type of liquid commodity

loaded/unloaded 2

Deleted Cells

Deleted: Actual loadin g throu g h p ut ( g al/ y r)

Deleted Cells Deleted: If subject to

Deleted: ), p rovide the citation(s) Deleted:

Deleted: Year loadin g o p eration installed

Deleted Cells

Deleted: Date control device or control technique was installed

Deleted CellsForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### Footnotes for Table 16-1:

1 

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

Code No. Type of Vessel 1 Tank ship
2 Barge

3 Truck/tank truck

4 Rail car 5 Containers with capacity less than 250 gallons 6 Containers with capacity from 250 gallons to less than 1,000 gallons 7 Containers with capacity from 1,000 gallons to less than 20,000 gallons 8 Containers with capacity greater than or equal to 20,000 gallons 99 Other (specify)

2 

### Select the Federal air regulation(s) to which the lo ading/unloading location is subject from the

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

Code No. Federal Air Regulation

0 None 1 Refinery MACT 1 (40 CFR part 63, subpart CC) existing source requirements 2 Refinery MACT 1 (40 CFR part 63, subpart CC) new source requirements 3 HON (40 CFR part 63, subpart H) existing source requirements 4 HON (40 CFR part 63, subpart H) new source requirements

5 Gasoline Loading NSPS (40 CFR part 60, subpart XX) 6 Gasoline Distribution (40 CFR part 63, subpart R) existing source requirements 7 Gasoline Distribution (40 CFR part 63, subpart R) new source requirements 8 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) existing source requirements 9 Gasoline Distribution (40 CFR part 63, subpart BBBBBB) new source requirements 99 Other (specify)

3 

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

Code No. Type of Control

0 None 50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

55 Flare 80 Submerged loading 82 Bottom loading 83 Vapor balancing system

95 Other management practice or work practice to reduce VOC (specify) 99 Other (specify) Deleted: from the following list of liquid

commodities.

Deleted: Type of Liquid Commodity

Deleted: 1 Unstabilized crude oil¶

2 Stabilized crude oil¶

3 Intermediate naphtha¶

4 Intermediate distillate oil¶

5 Intermediate heavy gas oil¶

6

Deleted: /blending stocks

Deleted: 7 Aviation fuels¶

8 No. 2 diesel fuel¶

9 No. 4 diesel fuel (heavy fuel oil)¶

10 No. 6 diesel fuel (marine diesel/bunker C)¶

11 Lubricating/motor oil¶

12 Petroleum coke¶

13 Asphalt¶

14 Sulfur¶

15 Ethylene¶

16 LPG (propane/butane)¶

17 Aromatics¶

18 Other petrochemicals (specify)¶

Deleted: 53

Deleted: 80 Submerged loading ( i.e. , loading from the top of the vessel; the fill pipe extends

almost to the bottom of the vessel such that it is below the liquid level during most of the filling)¶

Deleted: 98

Deleted: 4. Are the vessels required to be cleaned periodically? Yes No ¶

If Yes , what are the criteria for determining whether cleaning is needed?¶

¶ ¶ ¶ ¶

5. Are vessel cleaning operations conducted at the refinery or are they conducted at a separate facility? Please explain.¶

¶ ¶ ¶ ¶

6. Are there vessels or barges loaded at this facility that conduct non-segregated ballasting? What types of vessels or barges and what commodities conduct non-segregated ballasting? Is non-segregated ballasting water treated in the refinery’s wastewater treatment plant?¶

¶ ¶ ¶Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### SECTION 17 . SOLID WASTE MANAGEMENT

1. Facility ID number (EPA will pr o vi de this number ): ______________________

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

_________________________________________________________________________

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

TABLE 17 -1. Solid Waste Management Unit InformationSolid WasteManagementIDNumberType of Solid WasteManagement Unit1Description of WasteManaged in UnitArea of Solid WasteManagement Unit (m2)Capacity of Solid WasteManagement Unit (m3)ApplicableFederalairregulation(s)2If subject to State, local,or Tribalairregulation(s), providethe citation(s)Waste Application orDisposal Rate (m3/yr)Bulk Density of WasteApplied or Disposed(g/cm3)Pretreatment or ControlMethods Used3



### Footnotes for Table 17 -1:

1 

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

Code No. Type of Solid Waste Management Unit 1 Hazardous waste (RCRA Subtitle C) landfill 2 Industrial waste (RCRA Subtitle D) landfill 3 Land application unit 4 Waste pile 5 Composting operation Deleted: 15

Deleted: c

Deleted: response

Deleted: 2. Please provide information requested in Table 15-1 for each solid waste management unit ( e.g. , landfill, land application unit, or waste pile) at the facility. ¶

3

Deleted: 4. For each solid waste management unit listed in Table 15-1, also provide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided in the Air Emission Models for Waste and Wastewater (EPA-453/R-94- 080A) using the emissions template in Annex A of this part.¶

Deleted: 15

Deleted: Unit

Formatted Table

Deleted: Deleted: Deleted: If subject to

Deleted: ), p rovide the citation(s) Deleted:

Deleted: 2

Deleted: 15Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__

2 

### Select the Federal air regulation(s) to which the solid waste management unit is subject from

the following list of regulations. Select all that apply, but include only regulations to which the solid waste management unit is subject accordi ng to the applicability of the regulation ( i.e. , do not select regulations that are referenced fr om the regulation(s) to which the solid waste management unit is subject).

Code No. Federal Air Regulation

0 None 99 Other (specify)

3 

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

apply.

Code No. Type of Pretreatment or Control Method 1 Dewatering 2 Fixation (solidification/stabilization) 3 Steam stripping 4 Water for dust suppression 5 Oil for dust suppression 6 Foam for dust suppression

7 Leachate collection 8 Landfill gas collection 99 Other (specify) Deleted: 2Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__PART III. INCIDENCE REPORTS1. Complete the following table for eachnon-routine emissions event during 2010.Date ofreleaseType of release(startup/shutdown;equipmentorcomponentmalfunction)Description of releaseeventProcessunitsassociatedwith thereleaseDurationof thereleaseevent(hours)PollutantnamePollutantCAS No.orPollutantCodeQuantityofpollutantreleased(lb)Quantitydeterminationmethod(measured orcalculated)Deleted:CERCLA air release notification made tothe National Response Center in 2009Inserted CellsFormatted TableDeleted:continuousDeleted:noncontinuousForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__2. Complete the following table for each flare, air emission, or odor complaint receivedin 2010.Date ofcomplaintComplainantnameComplainantcontactinformationSubstanceofcomplaintDeleted:over the past 5 yearsInserted CellsDeleted:Date of complaintDeleted CellsDeleted:If applicable, provide the...Deleted CellsDeleted:Response to complaintDeleted CellsDeleted:Description of release event associatedwith complaintDeleted:Process unit(s) associated with thereleaseDeleted:Duration of the release event¶(hours)Deleted CellsDeleted CellsForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 83 

### PART IV. COST DATA

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

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

introduction to this enclosure.

1. Please complete Table 1 for any new APCD installed in the last 5 years on any of the process units or other emissions sources described in Part II for which you have readily

available information. The EP A is particularly interested in costs of the following

APCD:

• Electrostatic precipitators

• Wet scrubbers

• Baghouses

• SCR/SNCR for NO X 

### control

• Steam strippers

• Carbon adsorbers

• Thermal/catalytic oxidizers

• Flares

2. Please complete Table 2 for any process changes or equipment changes/upgrades performed in the last 5 years to any of the process units or other emissions sources described in Part II for which you have r eadily available information. The EPA is 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 Deleted: 10

Deleted: 10

Deleted: 10Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 84 • Combustion promoters or catalyst additives for NO X 

### control from FCCU

• Amine treatment systems

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

• Installation of geodesic dome for external floating roof tank

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

3. Please provide any readily available costs fo r other techniques used at your refinery to reduce emissions of any pollutant. EPA is par ticularly 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 technique (labor costs), cost of any equipment needed on a temporary basis, cost of any monitoring devices needed to indicate when action is needed or to measure progress). Types of techniques that EPA is particularly interested in

include:

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

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

• Pollution prevention techniques

• Energy management programs iden tified in Part II, Section 1

• Other management practices or work practices that you identified in Part II Deleted: pressure relief deviceForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__85Table 1. Cost Data for APCD1

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 of 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 ($) Waste disposal ($)Supplies andparts13 Monitoring, recordkeeping & reporting ($/yr) Other annual costs (itemize)
14 Total annual operating & maintenance cost 15

Primary equipment ( $)
6 Auxiliary equipment ($)
7 Instrumentation and monitors ($) Sales tax and freight ($) Total purchased equipment costs ($) Electricity Water Steam Natural gas Liquid chemicals Solid chemicals Compressed Air Other (specify) Total utilities cost ($/yr)
12 Description of most significant part Number of years between replacement Replacement cost (with installation) ($)

hr/yr $/yr hr/yr $/yr kWh/yr $/kWh gal/yr $/gal lb/yr $/lb scf/yr $/scf gal/yr $/gal lb/yr $/lb scf/yr $/scf amt/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 the subtotal 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 emission source was constructed, enter “New.” If the APCD was installed after the process unit or emission source beganoperation, enter “Retrofit.”Inserted CellsFormatted TableDeleted:Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__865Sum of equipment, auxiliary equipment, instrumentation/monitors, sales tax, and freight.6Primary equipment is the APCD itself. Examples include SCR with catalyst, carbon adsorber with carbon, packed scrubber towerwith packing, fabric filter with bags, ESP, andsteam stripper column with nozzles, 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 ductwork and 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 to get the total utilities cost.13Includethe most significant of themajor supplies and replacement parts; examples include catalyst for SCR and catalytic incinerators, bagsforfabric filters, and carbon for carbonadsorbers.14An example might be catalyst regeneration. Note that this question is not asking for costs of maintenance 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 any other items included under “other annual costs.”Deleted:ofForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__87Code 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/cartridgefilter (“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 adsorber53Single carbon adsorber canister54 Two carbon adsorber canisters in series55Flare56Portable internal combustion engine57Portable thermal oxidizer58Portable condensation system59Permanent onsite control device for storage tanks60 Flare gas recovery83 Vapor balancing system99 Other (specify)Deleted:Deleted:54Deleted:55Deleted:56Deleted:57Deleted:Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__88Table 2. Cost Data for Process and Equipment ChangesUnit IDProcess orequipmentchangetype1Process orequipmentchangedescription2Year of processor equipmentchangeNumber of daysprocess shutdown in order tomake the change(days of lostproduction)3Total capitalcost, $4Change in totalannualoperating cost,$/yr5Emissionreductionachieved (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” andspecifythe type of process or equipment change.2Describe theprocess 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 production required to implement the process or equipment change. If the change occurred duringscheduled downtime that would have occurredregardless of the process or equipment change, then do not include the scheduled downtime. Only the days of lost production that can be specifically attributed to the process 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, then indicate 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 before and after modification).You may provide this information as a separate attachment to your response if you wish.Formatted TableDeleted:description1Inserted CellsDeleted:2Deleted:3Deleted:yr4Deleted:5Deleted:describe yourDeleted:2Deleted:3Deleted:4Deleted:5Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__89Code 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/toncoke burn-off, but not 50/25 ppmv SO2limit28 Low sulfur (0.3 wt% or less) feed31 (External) fluegas 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 loading (i.e., loading from the top of the vessel; the fill pipe extends almost to the bottom of the vessel such that it isbelow the liquid level during most of the filling)82 Bottom loading99 Other (specify)Deleted:Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 90 

### PART V. EMISSIONS MONITORING AND SOURCE TEST DATA

In this section, emissions test data are requested. Please satisfy this request as completely as possible from existing information. No additional monitoring or emission testing is required by your company to respond to the data request in th is section. Four types of existing emissions data are requested: 1) source test data, 2) qual ified CEMS data, 3) biological treatment units data, and 4) ambient or remote sensing data. The emissions test data collected will provide

valuable information on current emissions levels and will allow EPA to consider variability in emissions from refinery to refinery (and over time for a given emission unit and pollutant) in reviewing and setting emission standards. When s ubmitting test data, EPA is requesting full test reports with field and lab data sheets and ex ample calculations, not just summary reports.

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

introduction to this enclosure.

1. Source Tests : Provide any existing emissions test reports from emissions tests conducted on any of the processes or emission points included in Part II, Sections 3 through 17 on or after January 1, 2005. Electronic (pdf) or hard copies are acceptable. Include the summary portion of the report and any appendices showing run-by-run test parameters, method detection limits, labora tory data, production data, example calculations, etc. If you have multiple tests for one pollutant from one process unit, submit only the most recent tests for that pollutant and process unit . (We are only requesting a maximum of

the three most recent tests per unit for one pollutant , but you may submit more than three, particularly if additional tests reflect th e effect of different operating conditions or equipment configurations.)

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

includes:

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

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

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

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

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

### , SO 2 

### , O 2 

### , and THC CEMS on any of the processes or emission points included in Part II, Sections 2 through 17 . Report daily averages for each day in 20 1 0 using the Microsoft® Excel CEMS Template; an example template is shown in Attachment 2 . The Excel templates are specific to each pollutant and type of unit, and each template is designed to Deleted: 16

Deleted: (

Deleted: ).

Deleted: summary table

Deleted: 3 of this enclosure

Field Code Changed

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).)

Deleted: emission rates measured,¶ (B)

Deleted: method or procedure used,

Deleted: (C) information on actual production or processing rates and on process conditions at the time the measurements were made, and¶ (D) a statement that any APCD (if present) were operating normally during the test, or if not, what the abnormal operating conditions were.¶

Deleted: 16

Deleted: 9

Deleted: 4Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 91 accommodate data from one CEMS (including oxygen data). Electronic copies of the template can be downloaded from the ICR website ( https://refineryicr .rti.org ).

Qualified CEMS data include: data from a PM CEMS that meets Performance Specification 11 or 15; data from a CO CEMS that meets Performance Specification 4;

data from a SO 2 

### and/or NO X 

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

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 flare gas lines. Report daily averages for each day in 20 1 0 using the Microsoft® Excel CMS Template; an example template is

shown in Attachment 2 . The Excel templates are specific to each pollutant and type of unit, and each template is designed to accommodate data from one CMS. Electronic copies of the template can be downloaded from the ICR website ( https://refineryicr .rti.org ).

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

4. Biological treatment unit : If you performed a biodegradation rate test or a complete mixing test on a biological treatment unit on or after January 1, 2000, provide a complete copy of the test report.

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

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

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).

Deleted: 9

Deleted: 4

Field Code Changed

Deleted: http://icr2010

Deleted: , click on “Petroleum Refineries”).Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__1-1Deleted:3Attachment 1Logof SourceTests ProvidedTestNumber1UnitID(s)If the APCDtype(s) is notclear from thetest report, enterthe APCD type(s)Configuration changes2OPTIONAL:Processtestingnotes3OPTIONAL: How oftenare you required toperform testing of thisemission unit for thepollutants listed?OPTIONAL:Approximate costper test, $1Assign a test ID or number to each test report that you provide so that EPA can match your responses in this log to the correct test report.2If the configuration of the emission unit, combustion controls, collection system, or APCD changed since the test was conducted, describe the changes. If there are no 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, where only selected emission points/vents were tested)Deleted:.2005 NEI Data for Each Refinery ¶(To be pulled from the NEI data and compiled foreach refinery. This page could be a cover pageand/or each refinery table could have a cover page,or the NEI table may just have a header or footer thatidentifies it as partDeleted:Attachment 1)¶¶Section Break (Next Page)Attachment 3.Deleted:Test Summary TableInserted CellsDeleted:APCD Type(s)Deleted:Date of test reportDeleted CellsDeleted:Pollutants tested1Deleted CellsDeleted:Test method(s) used2Deleted CellsDeleted:Are these inlet or outlet data (or both)?Deleted CellsDeleted:3Deleted:notes (optional)4Deleted:1List the pollutants tested. Separatemultiple pollutants by commas. ¶2Enter the EPA test method number (e.g., M5,M7E). Be very specific if the method used was notan EPA method.¶3Deleted:4Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__2-1Deleted:4Attachment2. Example CEMS TableNOXCEMS DATAEmission Unit ID:Deleted:4Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__2-2Deleted:4CEMSDate(mm/dd/yyyy)Dailyproduction/throughputrate(value)1Dailyproduction/throughputrate(units)1-day averageemission valuefor NOX(as measuredby the CEMS)Unit ofmeasurerecordedbyCEMSO2content (%)Moisturecontent(%)Dataaverageaffectedby astartup,shutdown, orotherevent?1OPTIONAL:Emissionvalue(ppmvd @7% O2)OPTIONAL: 1-day average emission valuefor NOXin otherunits1-day averageemission valuefor NOX,corrected for%O2(value)1-dayaverageemissionvalue forNOX, (units)% O2correction(by volume,dry basis)01/01/201001/02/201001/03/201001/04/201001/05/201001/06/201001/07/201001/08/2010......12/25/201012/26/201012/27/201012/28/2010Deleted:APCD_ID:¶Formatted TableDeleted:Production RateDeleted:Production RateDeleted:ppmdv, corrected for %O2Deleted:% O2correction (by volume, dry basis)Inserted CellsInserted CellsInserted CellsDeleted:unitsDeleted:than ppmvdDeleted:9Deleted:9Deleted:9Deleted:9Deleted:9Deleted:9Deleted:9Deleted:9Deleted:01/09/2009Deleted:......... [75]Formatted TableDeleted:9Inserted CellsInserted CellsInserted CellsDeleted:9Deleted:9Deleted:9Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__2-3Deleted:412/29/201012/30/201012/31/20101Provide the process production rate, heat input rate, coke burn-off rate or other normalizing factor appropriate for the type of process.2If no, leave blank. If yes, respond “startup,” “shutdown,” or “event”; if you respond “event” please include a brief description of the event.Deleted:9Deleted:9Deleted:9Page 13: [1] Deleted Author 1/17/2011 9:44:00 AMProcessing UnitNumberof UnitsUnit 1IDUnit 1Throughput(bbl/cd)1Unit 2IDUnit 2Throughput(bbl/cd)1Unit 3IDUnit 3Throughput(bbl/cd)1Unit 4IDUnit 4Throughput(bbl/cd)1Atmospheric crude distillationVacuum distillationDelayed cokingFluid coking (traditional)FlexicokingVisbreaking, other thermal crackingFluid catalytic cracking unitNon-fluid catalytic cracking unitCatalytic hydrocrackingCatalytic reforming unit– continuous regen.Catalytic reforming unit– cyclic regenerationCatalytic reforming unit – semi-regenerativeFuels solvent deasphaltingDesulfurization/ hydrotreat –naphtha/reformer feedDesulfurization/ hydrotreat – gasolineDesulfurization/ hydrotreat – kerosene/ jetfuelDesulfurization/ hydrotreat – dieselDesulfurization/ hydrotreat – other distillateProcessing UnitNumberof UnitsUnit 1IDUnit 1Throughput(bbl/cd)1Unit 2IDUnit 2Throughput(bbl/cd)1Unit 3IDUnit 3Throughput(bbl/cd)1Unit 4IDUnit 4Throughput(bbl/cd)1Desulfurization/ hydrotreat – residualDesulfurization/ hydrotreat – heavy gas oilDesulfurization/ hydrotreat – otherHF alkylationH2SO4alkylationAromatics productionAsphalt productionIsomerization – IsobutaneIsomerization – Iso C5,C6Lubricants productionPetroleum coke storageHydrogen plant2Sulfur plant3Gas plant (LPG production unit)Oxygenate plant – MTBEOxygenate plant – ETBEOxygenate plant – TAMEOxygenate plant – other (specify)Marine vessel loading/unloadingTruck/tank truck loading/unloadingRail car loading/unloadingWastewater treatment41Throughput units are barrels per calendar day (bbl/cd) unless noted otherwise. For crude distillation through desulfurization, “throughput” is determined interms of charged material;for alkylation through oxygenates, “throughput” isdetermined in terms of materials produced.2Throughput units are million cubic feet per calendar day (MMcf/cd).3Throughput units are long tonsper calendar day (LT/cd).4Throughput units are million gallons per day (MMgal/day).Section Break (Next Page)

## 15. Provide location information for each of the major processing units at the facility.

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### Desulfurization/ hydrotreat – other
HF alkylation

H 2 

### SO 4 

### alkylation
Aromatics production
Asphalt production

Isomerization – Isobutane

Isomerization – Iso C5,C6
Lubricants production
Petroleum coke storage
Hydrogen plant
Sulfur plant
Gas plant (LPG production unit)
Oxygenate plant – MTBE
Oxygenate plant – ETBE
Oxygenate plant – TAME
Oxygenate plant – other (specify)
Marine vessel loading/unloading
Truck/tank truck loading/unloading
Rail car loading/unloading

Wastewater treatment

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## Abbreviation: MW = megawatts

1 

## For disposition of electricity, enter appropriate code number as follows:

Enter “1” if generated electricity is used only on-site.

Enter “2” if generated electr icity is used only off-site ( e.g. , sent to grid).

Enter “3” if generated electricity is used on- site with excess used off-site or sent to grid.



## 4. Does this refinery generate steam on-site? Yes No

If Yes : Provide the information requested in Ta ble 1-3 for each steam-generating unit.

TABLE 1-3. Steam Generation InformationUnit IDUnit Description1Boiler Heat InputCapacity(MMBtu/hr)Steam GeneratingCapacity (lb/hr)Pressure of Steam(psia)Primary FuelSecondary FuelDisposition ofsteam2Energy EfficiencyMeasures3Does this unithave air preheat?(Yes/No)Percent Steam toBlowdownPage 20: [4] Deleted Author 1/17/2011 9:57:00 AM

## Footnotes for Table 1-4:

1 

## Select the process unit se rved by the process heaters from the following list.

Code No. Type of Process Unit 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 un it – cyclic regeneration 12 Catalytic reforming unit – semi-regenerative 13 Fuels solvent deasphalting 14 Desulfurization/ hydrotreat – naphtha/reformer feed 15 Desulfurization/ hydrotreat – gasoline 16 Desulfurization/ hydrotreat – kerosene/jet fuel 17 Desulfurization/ hydrotreat – diesel 18 Desulfurization/ hydrotreat – other distillate 19 Desulfurization/ hydrotreat – residual 20 Desulfurization/ hydrotreat – heavy gas oil 21 Desulfurization/ hydrotreat – 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 plant 32 Gas plant (LPG production unit) 33 Oxygenate plant – MTBE 34 Oxygenate plant – ETBE 35 Oxygenate plant – TAME 36 Oxygenate plant – other (specify) 99 Other (specify)

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## Process-specific

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## Process-specific

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## Deleted Cells

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## Inserted Cells

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## Inserted Cells

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## Inserted Cells

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## Merged Cells

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## Split Cells

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## Split Cells

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## Split Cells

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## Split Cells

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## Deleted Cells

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## Deleted Cells

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## Deleted Cells

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## Deleted Cells

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## Deleted Cells

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## Deleted Cells

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## Merged Cells

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### Number of pressure relief devices routed to fuel gas system or control device

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## Merged Cells

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## Merged Cells

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### Number of pressure relief valves equipped with rupture disk or second valve

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## Merged Cells

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## Inserted Cells

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## Inserted Cells

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### If you monitor your pressure relief devi ces for leaks/releases, how many are

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## Inserted Cells

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## Inserted Cells

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## Inserted Cells

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## TABLE 5-1. E-Cat and FCCU Fines Metal ConcentrationCCU IDParticle Type 

## Concentration (parts per million by weight, ppmw)AntimonyArsenicBerylliumCadmiumChromiumCobaltLeadManganeseMercuryNickelSeleniumVanadium



## E-cat

Fines

E-cat

Fines

E-cat

Fines

E-cat

Fines



## 3. Please provide information requested in Table 5-2 for each CCU at the facility.

4. For each CCU listed in Table 5-2, also pr ovide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part.

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5 

## Select from the following list the combination that best describes the monitoring methods and

frequencies for the unit. List all that apply. For example, select 1B and 4E if you conduct daily visual inspections and quarterly meas urements using El Paso stripping column.

Code No. Monitoring Method Code Letter Monitoring Frequency
1 Visual inspection A Continuous

2 Chemical addition rates B Daily

3 Measurement of redox potential C Weekly

4 El Paso stripping column D Monthly

5 TOC/VOC/Organic HAP water

measurements E Quarterly

99 Other (specify) Z Other (specify)

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## 3. Please provide the information requested in Table 14-1 for the wastewater collection

system components.

TABLE 14-1. Wastewater Collection System Components

Component Number

Controlled Number Uncontrolled Control Technologies 1



## Drain

Trench

Manhole

Junction Box

Sump

Lift Station

Weir



## Footnotes for Table 14-1:

1 

## Select from the following lis t of control technologies.

Code No. Type of Control Technology 50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

53 Flare

70 Water seal

71 Fixed seal 72 Hard piping 90 Performance-based standard (specify) 99 Other (specify)

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## 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 Other (specify)



## 5. Please provide the information requested in Table 14-2 for each wast ewater collection or treatment unit (WWTU) at the facility. Fo r wastewater collection system components, you may aggregate all similar components as a single unit ID number (all drains, all sumps, all lift stations, all junction boxes, et cetera).

## 6. For each WWTU listed in Table 14-2, also pr ovide criteria pollutant and HAP emission estimates (tons/yr) following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template in Annex A of this part.

## TABLE 14-2. Wastewater Collection and Treatment Unit InformationWWTS ID NumberWWTU ID NumberWWTU Type1WWTU Design FlowCapacity (MMgal/day)Indicate Covered orOpenIf subject to Federalregulation(s), provide thecitation(s)If subject toState, local,or Tribal regulation(s),provide the citation(s)WWTU MonitoringMethod and Frequency2WWTU Dimensions(surface area x waterdepth)ComplianceApplicablity3Emission ReductionMethod4

## Footnotes for Table 14-2:

1 

## Select from the following list of WWTU types. If the WWTU type is part of the wastewater

collection system, enter “0” followed by the code letter that best describes the collection system component ( e.g. , select 0A for drains).

Code No. Type of WWTU Code Letter Collection System Component
0 Wastewater collection system A Drain

B Trench

C Manhole

D Junction box

E Sump

F Lift station

G Weir
Z Other (specify)

1 Steam stripper 2 Oil-water separator 3 Dissolved air/gas flotation 4 Equalization basin

5 Neutralization basin

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## . List all that apply. For example, select 13A, 12B, and 22E if you continuously monitor dissolved oxygen concentrati on, perform daily MLVSS analyses, and perform quarterly benzene concentration analyses.

Code No. Monitoring Parameter Code Letter Monitoring Frequency

0 None A Continuous
1 Inlet water temperature B Daily
2 Outlet water temperature C Weekly
3 Inlet water flow rate D Monthly
4 Outlet water flow rate E Quarterly
5 Steam temperature Z Other (specify)
6 Steam usage rate

7 COD inlet concentration

8 COD outlet concentration

9 BOD inlet concentration

10 BOD outlet concentration

11 MLSS concentration

12 MLVSS concentration
13 Dissolved oxygen concentration

14 Sludge age

15 Solids retention time

16 F/M ratio
17 Oxygen uptake rate

18 Wastewater flow rate
19 Sludge wasting rate
20 Volatile organic compounds (VOC)

21 Organic hazardous air pollutants (Organic HAP)

22 Benzene

23 Phenol
24 Hydrogen sulfide
25 Oil and grease

26 Inlet pH

27 Outlet pH

28 TSS inlet concentration

29 TSS outlet concentration

30 Phosphorus removal from effluent

31 TOC concentration as an alternative to BOD

32 Chlorine outlet concentration

33 Chorine consumption
99 Other (specify)3 

## Select

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