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

Approval Expires __/__/__



## Petroleum Refinery Emissions Information Collection

General Instructions

Please provide the information requested in th is enclosure and, if applicable, Enclosure 2 for the facility listed in the Sec tion 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 2009 calendar year as the base year for all survey responses ( e.g. , 2009 emissions inventory, 2009 throughput, 2009 equipment configura tions) unless another year is specified in the instructions ( e.g. , for emissions test data).

The following sections (Enclosure 1) are to be completed by all facilities and returned to the address noted below within 90 days of receipt of your Section 114 letter:

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

• Part II – Process and Emissi ons Information: Provide detailed information on the process units and other emissions sour ces at the petroleum refinery.

• Part III – Incidence Reports: Provide copi es 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 Source 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 16.

• Part VI – Crude Oil Composition Anal ysis: Conduct an analysis of the composition of each type of crude at the refinery.

Emissions testing according to Enclosure 2 is to be completed by facilities with process units selected for testing. The Section 114 letter you received indicates if a unit at your refinery has been selected for testing. For units requiring stack tests, emissions te sts (consisting of three runs per test method required) are to be conduc ted according to Enclosure 2 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 Encl osure 2 for sampling the wastewater treatment system. The results of the emissions tests and ot her requested analyses sh ould be returned to
EPA within 6 months of rece ipt of this questionnaire.

1 For purposes of this information request, “facility” is defined as any stationary source or group of stationary sources located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 2 The electronic version of the survey (Parts I, II, III, and IV of this Enclosure 1) is in
Microsoft® Excel format and can be downloaded from the ICR website ( http://icr2010.rti.org

, click on “Petroleum Refineries”). Detail ed instructions for each part follow.

NOTE: The final version of this questionna ire 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 Mr. Bob Lucas at (919) 541-0884 or lucas.bob@epa.gov or Ms. Brenda Shine at (919) 541-3608 or shine.brenda@epa.gov

.



## Confidential Business Information (CBI)

If you believe that providing any specific inform ation to us would reve al a trade secret, or would compromise confidential business informa tion (CBI), please identify this information clearly in your response and subm it your response as detailed in the next section. Also, please clearly label any flow diagrams or other attach ments submitted with your survey that contain CBI. However, please do not label your entire response as CBI if onl y a portion includes trade

secrets.
The EPA’s procedures for handling CBI are described in the lett er (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 f acilities 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 pursua nt to those regulations and, for trade secrets,
under 18 U.S.C. 1905. If no claim of confidentia lity accompanies the information when it is 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 confidentialit y, the emission data you provide will be made available to the public notwithstandi ng any claims of confidentiality.



## How to Submit Your Survey Response

If your response to this information collection request includes data with a claim of CBI, you should follow the instructions in this section to ensure the protection of your data. Please note that if you submit CBI, you should separate your data into two packages, one containing any
information claimed as CBI and the other containi ng all other information (hereafter referred to as “non-CBI”). These two packages should be sent to EPA separately, using two different mailing addresses.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 3 Separating CBI and Non-CBI

After you have completed and reviewed your su rvey 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 su rvey response file th at does not include this information. If you have attachments, remo ve 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 f iles. Send these files to EPA using one of the methods described under “Submitting Your Non-CBI Response.”

Create a separate CD or DVD containing only the CBI portion of your survey response. 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 Busine ss 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 re sponse, including non-CBI attachments (and for 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. Deta iled directions for uploading your files are provided on the ICR website ( http://icr2010.rti.org , click on “Petroleum Refineries”).

• 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:

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, Pe troleum Refinery Sector Lead
109 T.W. Alexander Drive Research Triangle Park, NC 27711

EPA recommends sending your non-CBI files vi a Registered U.S. Mail using return receipt requested, Federal Express, or other me thod for which someone must provide a signature upon receipt.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 4 Submitting CBI

Follow the instructions under “Separating CBI and Non-CBI” to create the portion of your survey response that contains CBI. Se nd only these CBI files unde r 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. Ma il using return receipt requeste d, 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 facsimile 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-o ff (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 ex cess air, on a 7-day rolling average basis and 25 ppmv, dry basis correct ed 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 NE SHAP (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-methylbutan e), 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 det ection 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. ____-____

Approval Expires __/__/__



### 7 NAD North American Datum

NESHAP national emissions standa rds 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
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 reducti on 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 En ergy, Energy Information Administration

ULNB ultra low NO X 

### burner (high fraction staged fuel)

UV ultravioletForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 8 VOC volatile organic compounds
wt% weight percent

WWTS wastewater collecti on and treatment system

WWTU wastewater collection or treatment unit
°F degrees Fahrenheit
% percentForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 9 

### PART I: GENERAL F ACILITY INFORMATION

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. Plant Name (as reported on U.S. DOE/ EIA Form-820 (2009), “Annual Refinery Report,”

schedule 2, line 1, page 37, question 1):

_________________________________________________________________________

_________________________________________________________________________

_________________________________________________________________________ 4b. Does this facility report in EIA-820 the combined processing/p roduction capacities for

refining plants that are not contiguously located? Yes No

4c. If Yes , provide the name and location for each non-contiguous facility: _______________

_________________________________________________________________________

________________________________________________________________________ 4d. If Yes , you must complete a separate survey response for each non-contiguous facility.

Indicate the name of th e facility for which the remainder of this survey response applies.

________________________________________________________________________ 5. Complete street address of f acility (physical location): ____________________________

_________________________________________________________________________

_________________________________________________________________________

2 For purposes of this information request, “facility” is defined as any stationary source or group of stationary sources located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 10 6. Provide mailing address if different: ___________________________________________

_________________________________________________________________________

_________________________________________________________________________ 7. Name and title of contact(s) able to answ er technical questions about the completed

survey: __________________________________________________________________

_________________________________________________________________________ 8. Contact(s) telephone number(s): ______________________________________________

and e-mail address(es): _____________________________________________________

9. Dunn and Bradstreet number of your facility: ___________________________________

10. Annual revenue in 2009: $______________________

11. Number of employees at your facility: _________________________________________

12a. Are you part of a larg er corporate entity? Yes No

12b. If Yes : Name of parent company: ____________________________________________

Number of employees in parent company: ___________________________

Corporate crude oil processi ng capacity: (bbl/stream da y)

12c. If Yes, check the statement below that best applies:

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

The parent organization provi des some financial support.

Operations of the parent or ganization and this facility are fully integrated (full access to investment capital, same Board of Directors, etc.)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 11 13. Circle all applicable code number(s) for th e final products produ ced at the 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. ____-____Approval Expires __/__/__1214. Report the number of processes and 2009 process throughputs by completing the table below.Attachment 1 to this enclosure is a copy of the EPA’s 2005 National Scale Air Toxics Assessment (NATA) National EmissionsInventory (NEI) data set for each of your refineries (if available) for your reference.When asked for a Unit ID in Questions15and 16, please use the same identifying numberor code that is used in the NEI data set (if possible and/or applicable). If the NEIdoes not show an entry for a particular unit, or you are not surewhat units are included in the NEI data set, use a unique Unit IDfor each process unit.Processing 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 distillateForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__13Processing 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 percalendar day (bbl/cd) unless noted otherwise. For crude distillation through desulfurization, “throughput” is determined in terms 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 tons per calendar day (LT/cd).4Throughput units are million gallons per day (MMgal/day).Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 14 15. Provide location information for each of th e major processing units at the facility. Provide the coordinates (latitude and longitude ) of the approximate process unit centroid in North American Datum (NAD) 83 with 6 dig its to the right of the decimal point. (See instructions to Part II, Annex A for additiona l details on latitude and longitude format.)

Unit 1 Unit 2 Unit 3 Unit 4 Processing Unit Lat Long Lat Long Lat Long Lat Long
Atmospheric crude distillation

Vacuum distillation Delayed coking Fluid coking (traditional) Flexicoking Visbreaking, other thermal cracking Fluid catalytic cracking unit Non-fluid catalytic cracking unit Catalytic hydrocracking Catalytic reforming unit – continuous regen. Catalytic reforming unit – cyclic regeneration Catalytic reforming unit – semi-regenerative Fuels solvent deasphalting Desulfurization/ hydrotreat – naphtha/CRU feed Desulfurization/ hydrotreat – gasoline Desulfurization/ hydrotreat – kerosene/ jet fuel Desulfurization/ hydrotreat – diesel Desulfurization/ hydrotreat – other distillate Desulfurization/ hydrotreat – residual Desulfurization/ hydrotreat – heavy gas oil 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 treatmentForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 15 

### PART II: PROCESS AND EMISSIONS INFORMATION

As noted in Part I, Attachment 1 to this en closure is a copy of the EPA’s 2005 NATA NEI data set for your refinery (if available) for your reference. When asked for a Unit ID in any section of Part II, please use the same identifying number or code that is used in 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.

SECTION 1. ENERGY MANAGEMENT

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

2. Complete Table 1-1 below to provide the total energy use by th e refinery in 2009:

TABLE 1-1. 2009 Fuel Consumption

Fuel Units Fuel Consumption

Crude Oil bbl

LPG bbl

Distillate Fuel Oil bbl

Residual Fuel Oil bbl

Still Gas MMcf
Petroleum Coke Tons (US) Catalyst Coke Tons (US)

Natural Gas MMcf
Coal Tons (US) Purchased Electricity MWh

Purchased Steam MM lb

Other bbl

Abbreviations: bbl = barrels MMcf = million cubic feet at 60°F and 1 atmosphere MWh = Megawatt-hours MM lb = million pounds



### 3. Does this refinery gene rate electric ity on-site? Yes No

If Yes : Provide the information requested in Ta ble 1-2 for each electricity-generating unit. Include energy recove ry turbines used on pro cess unit exhaust lines.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 16 TABLE 1-2. Electricity Generation Information

Unit ID
Number Unit Description Capacity of Unit (MW) Primary
Fuel Secondary
Fuel Disposition of electricity 1

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 toBlowdown

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

Approval Expires __/__/__



### 17 2 For disposition of steam, enter a ppropriate code number as follows: Enter “1” if generated steam is used only on-site. Enter “2” if generated steam is used only off-site. Enter “3” if generated steam is used on-site with excess used off-site.

3 Enter the code number for each energy efficiency m easure used with this steam-generating unit; list all that apply:

0 None

1 Insulation on boiler

2 Insulation on distribution lines 3 Oxygen and intake air monitors to optim ize fuel/air mixtures and limit excess oxygen 4 Combustion air preheat from flue gas 5 Boiler feed water preheat from flue gas 6 Blowdown steam recovery system for low pressure needs 7 Boiler maintenance program (to reduce scaling; maintain burners) 8 Steam trap maintenance program

9 Steam condensate return lines 10 Steam expansion turbines 99 Other (specify)__________________Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 18 5. Provide the information requested in Ta ble 1-4 for each processing unit listed in Questions 14 and 15 of Part I (except wastewater treatment).

TABLE 1-4. Steam Demand and Process Heater Capacity by Process Unit

Unit ID Processing Unit Type 1 Steam
demand at

capacity
for the processing unit (lb/hr) Total
number of

process heaters Cumulative
rated heat capacity of process heaters for process unit

(MMBtu/hr) Number of

process heaters
with air preheat Cumulative rated heat capacity of process heaters with air preheat for process unit

(MMBtu/hr)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 19 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)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 20 SECTION 2. PROCESS HEATER DATA

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

2. Please provide the information requested in Table 2-1 for each process heater at the facility.

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.

TABLE 2-1. Process Heater General InformationProcess Heater IDProcess unit served byprocess heater1Process heater constructiontype2Process heater draft type3Primary fuel4Secondary fuel4Rated heat capacity(MMBtu/hr)Average heat input rate in2009 (MMBtu/hr)Total operating hours in 2009(hr)Operating hours while cofired in 2009 (hr)Operating hours in turndownin 2009 (hr)If subject to Federalregulation(s), provide thecitation(s)If subject to State, local, orTribal regulation(s), providethe citation(s)Type of PM controls5Type of SO2controls6Type of NOXcontrols7Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 21 Footnotes for Table 2-1:

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 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)

2 

### 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)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 22 3 

### 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 (blast air-side fan only) 5 Balanced draft/air preheat ( both air- and exhaust-side fans) 99 Other (specify)

4 

### Select from the following list of fuels.

Code No. Fuel Type 1 Natural gas 2 Refinery fuel gas

3 Distillate oil 4 Heavy gas oil 99 Other (specify)

5 

### 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 98 Management practice or work practice (specify) 99 Other (specify)

6 

### 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 heavy gas oil 24 Wet scrubber/flue gas desulfurization 25 Spray dryer absorber 98 Management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 23 7 

### Select from the following list of NO X 

### controls; list all that apply.

Code No. Type of NO X Control

0 None 31 (External) flue gas recirculation 32 Staged air low NO X burner 33 Staged fuel low NO X burner

34 Ultra low NO X burner (high fraction staged fuel) (ULNB) 35 “Next generation” low NO X burner (ULNB with internal gas recirculation) 36 Selective non-catalytic reduction (SNCR) 37 Selective catalytic reduction (SCR) 98 Management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 24 SECTION 3. EQUIPMENT LEAKS

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

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

If Yes :

a. Provide the manufactur er and model number: ____________________________

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

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

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

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



### 3. Do you routinely monitor your fuel gas system for leaks? Yes No

4. Complete Table 3-1 for each process unit li sted in Part I, Questions 14 and 15 (except wastewater treatment) and for each fuel gas and natural gas system at the facility.

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 __/__/__25TABLE 3-1. Process-specific Equipment Component and Leak Detection InformationPumps Valves Flanges ConnectorsOpenendedlinesPressurereliefdevicesCompressorsOtherLightliquidHeavyliquidGasLightliquidHeavyliquidGasLightliquidHeavyliquidGasLightliquidHeavyliquidAny Any Any Any

Unit ID Process Unit Type 1 Applicable Federal regulation(s) 2 If subject to State, local, or Tribal regulation(s), provide the citation(s) Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4 Number of Components Monitoring Frequency 3 Leak Definition (ppmv) 4Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 26 Footnotes for Table 3-1:

1 

### Select 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 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) 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)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 27 2 

### Select the Federal regulation to which the process unit is applicable from the following list of

regulations.

Code No. Federal 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 40 CFR part 60, subpart VV 4 40 CFR part 60, subpart GGG 5 40 CFR part 60, subpart VVa 6 40 CFR part 60, subpart GGGa 7 HON (40 CFR part 63, subpart H) existing source requirements 8 HON (40 CFR part 63, subpart H) new source requirements 99 Other (specify)

3 

### Select from the following list of monitoring fre quencies that best applie s for the process unit,

equipment component, and type of service.

Code No. Monitoring Frequency 0 None (unit/system not monitored for leaks) 1 Less than annually 2 Annually 3 Semiannually 4 Quarterly 5 Monthly 6 Biweekly 7 Weekly or more frequently

4 

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

repairs are required (or routinel y) performed for the process un it, equipment component, and type of service.

Code No. Leak Definition 0 None (unit/system not monitored for leaks) 1 10,000 ppmv 2 5,000 ppmv 3 2,000 ppmv 4 1,000 ppmv 5 500 ppmv 6 Less than 500 ppmvForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 28 6. Provide the information request ed in Table 3-2 regarding pres sure relief devices on each process unit listed in Part I, Questions 14 and 15 (except wa stewater treatment) and for each fuel gas and natural gas system at the facility.

TABLE 3-2. Pressure Relief DevicesUnit IDProcess Unit Type1Total number of pressurerelief devicesNumber of pressure reliefdevices routed to fuel gassystem or control deviceType of controls2Number of pressure reliefvalves equipped withrupture disk or second valveIf you monitor yourpressure relief devices forleaks/releases, how manyare monitored using asystem designed to measurethe duration of a release andthe quantity of compoundsreleased?If you have a monitoringsystem that measures theduration of a release and thequantity of compoundsreleased, describe the systemForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 29 Footnotes for Table 3-2:

1 

### Select from the following list of process 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 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) 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)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 30 2 

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

Code No. Type of Control

0 None 50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

53 Flare 98 Management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 31 SECTION 4. STORAGE TANKS

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

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

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.

TABLE 4-1. Storage Tank General Information

For tanks with
EFR or IFRTank IDType of stored liquid1Vapor pressure of stored liquid at averageliquid storage temperature in 2009 (psi)Average liquid storage temperature in 2009(°F)Type of tank/controls2Diameter (ft)Height (ft)Maximum liquid height (ft)Total throughput for all materials stored inthe tank in 2009 (bbl)Is the tank a “drain-dry” tank? (Yes/No)If subject to Federal regulation(s), providethe citation(s)If subject to State,local, or Tribalregulation(s), provide the citation(s)Year in which the tank was last degassedType of control for last degassing event3Was the tank cleaned during last degassingevent? (Yes/No)Year in which you anticipate the nextdegassing eventMinimum height of floating roof abovethe floor at the shell when landedNumber of times floating roof landedin 2009Number of times the tank was emptiedafter roof landed in 2009Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 32 Footnotes for Table 4-1:

1 

### Report the type of liquid stored (or crude oil received) in the tank for the predominant use of

the tank. Select from the following list of liquid types.

Code No. Type of Stored Liquid

1 Unstabilized crude oil

2 Stabilized crude oil 3 Intermediate naphtha

4 Intermediate distillate oil 5 Intermediate heavy gas oil 6 Gasoline/blending stocks

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) 99 Other (specify)

2 

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

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 a 5 External floating roof with solid guidepoles b
6 External floating roof, controlled guidepoles c 7 Internal floating roof, slotted guidepoles a 8 Internal floating roof with solid guidepoles b
9 Internal floating roof, controlled guidepoles c 10 External floating roof with geodesic dome roof

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

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 th e 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 emissi on reduction partnership prog ram (STERPP) at 72 FR 19891.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 33 3 

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

list of controls.

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

55 Portable thermal oxidizer 56 Portable condensation system

57 Permanent onsite control device 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 34 SECTION 5. CATALYTIC CRACKING UNIT

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

2. If the facility has metal concentration fo r E-cat and/or fines, provide annual average values for each catalytic cracking unit (CCU) at the facility in the Table 5-1 below.

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

Concentration (parts per million by weight, ppmw)CCU IDParticle TypeAntimonyArsenicBerylliumCadmiumChromiumCobaltLeadManganeseMercuryNickelSeleniumVanadium

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

Approval Expires __/__/__



### 35 TABLE 5-2. Catalytic Cracking Unit InformationCCU IDFresh 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)?If subject to Federalregulation(s), provide thecitation(s)If subject to State, local, orTribal regulation(s), provide thecitation(s)Nickel Concentration inCombined Feed (wt%)Vanadium Concentration inCombined Feed (wt%)Type of PM controls1Type of SO2controls2Type of NOXcontrols3



### Footnotes for Table 5-2:

1 

### 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 98 Management practice or work practice (specify) 99 Other (specify)

2 

### Select from the following list of SO 2 

### controls; list all that apply.

Code No. Type of SO 2 Control

0 None 24 Wet scrubber/flue gas desulfurization 25 Spray dryer absorber 26 DeSOx catalyst, meeting 50/25 ppmv SO 2 limit 27 DeSOx catalyst, meeting 20 lb/ton c oke burn-off, but not 50/25 ppmv SO 2 limit 28 Low sulfur (0.3 wt% or less) feed 98 Management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 36 3 

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

Approval Expires __/__/__



### 37 SECTION 6. FLUID COKING UNIT

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

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

3. For each FCU listed in Table 6-1, 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 6-1. Fluid Coking Unit Information

If traditional coker If flexicokerFCU IDFeed Capacity (bbl/cd)Type of FCU (traditional orflexicoker)If subject to Federal regulation(s),provide the citation(s)If subject to State,local, or Tribalregulation(s), provide the citation(s)Coke 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 controls1Type of SO2controls2Type of NOXcontrols3Produced Coke HandlingControls and Disposition4Low Btu gas production rate atcapacity (scfm)Low Btu gas sulfur removaltechnique5FCU dust/ash quantityproduced (tons/cd)FCU dust/ash handling/disposalmethod6



### Footnotes for Table 6-1:

1 

### 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 98 Management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 38 2 

### 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 98 Management practice or work practice (specify) 99 Other (specify)

3 

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

Approval Expires __/__/__



### 39 4 

### Select from the following list the combinati on that best describes the coke handling and

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

Code No. Disposition Code Letter Storage/Handling Method 1 Shipped off-site to coke calciner A Enclosed conveyer to silo for loading/processing 2 Shipped off-site to be used as 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 En closed conveyer to open storage pile or bin, wind break and wetting 6 Used on-site as fuel F Open conveyance to open storage pile or bin, wind break only 7 Some used on-site as fuel,
remainder sent off-site to coke
calciner G Open conveyance to open storage pile or bin, wetting only

8 Some used on-site as fuel,
remainder sent off-site for use as
fuel H Open conveyance to open storage pile or bin, wind break and wetting

99 Other (specify) Z Other (specify)

5 

### 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. , DMEA) 2 Sterically-hindered amine scrubber ( e.g. , FLEXSORB®)

3 Selexol®

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

9 Sulfinol 98 Management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 40 6 

### Select from the following list of flexicoki ng dust/ash handling and disposal methods.

Code No. Flexicoking Dust/Ash Handling and Disposal Methods

1 Used on-site as fuel 2 Disposed of in on-site landfill 3 Disposed of in off-site landfill 4 Shipped off-site for use as fuel 5 Shipped off-site for metals recovery 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 41 SECTION 7. DELAYED COKING UNIT

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

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.

3. For each DCU listed in Table 7-1, 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 7-1. Delayed Coking Unit Operating InformationDCU IDFeed Capacity (bbl/cd)Coke Production Capacity (tons/cd)Number of Coke DrumsHeight of Single Coke Drum (ft)Diameter of Single Coke Drum (ft)Typical Coke Drum Outage (ft)If subject to Federal regulation(s), provide thecitation(s)If subject to State, local, or Tribal regulation(s),provide the citation(s)Complete Coke Drum Cycle Time (hr)1Coke 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)Coke Drum Pressure When First Vented toAtmosphere (psig)Coke Drum Temperature at Top of Drum WhenFirst Vented to Atmosphere (°F)Water Height in Coke Drum When First Ventedto Atmosphere (ft)Water Quenching Cycle Description2Typical Quench Water Flow Rate duringQuenchingCycle(gal/min)Average Quench Water Make-up Rate (gal/day)Blowdown System Description3Cutting Water Storage/Handling4



### Footnotes for Table 7-1:

1 

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

Approval Expires __/__/__



### 42 2 

### Select from the following list of wa ter quenching cycle descriptions.

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

3 

### Select from the following list of blowdown system descriptions.

Code No. Condensed Water Disposition Code Letter Uncondensed Vapor Disposition
When Not Sent 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 Unconde nsed 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 atmospheres H Uncondensed vapors are vented directly to atmosphere Z Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 43 4 

### Select from the following list of cutting 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)



### 4. Provide typical and maximum feed com position in Table 7-2 for each DCU at the facility. You may list multiple DCU IDs in a si ngle 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 sepa rately for each set of similar DCU.

TABLE 7-2. Delayed Coking Unit Feed Information

DCU ID(s): ____________ DCU ID(s): ____________

Feed Source 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): ____________Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 44 Footnotes for Table 7-2:

1 

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

100%.

2 

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

this column is expected to exceed 100%.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 45 SECTION 8. CATALYTIC REFORMING UNIT

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

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

3. For each CRU listed in Table 8-1, 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 8-1. Catalytic Re forming Unit InformationCRU IDFeed Capacity (bbl/cd)Operating PressureHydrogen Production Rate(MMscf/cd)Type of CRU Regeneration(continuous, cyclic, orsemi-regenerative)If subject to Federal regulation(s),provide the citation(s)If subject to State,local, or Tribalregulation(s), provide the citation(s)Average Annual Regeneration Time(hours/year)Average Annual RegenerationFrequency (cyclic and semi-regenunits; regeneration cycles/year)Depressurization /Purge Cycle VentDisposition/control1Purge Process Type2Coke Burn-off Cycle VentDisposition/control3Coke Burn-off Cycle Duration perCycleRejuvenation Cycle VentDisposition/control4Chloriding Agent5Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 46 Footnotes for Table 8-1:

1 

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

Code No. Type of Depressurization/Purge Control 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 99 Other (specify)

2 

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

Code No. Type Purge Process 1 Purge by sequential pressuri zing/purging with nitrogen 2 Purge using nitrogen and vacuum pump 3 Purge by sequential pressurizing/purging with methane 4 Purge using methane and vacuum pump 99 Other (specify)

3 

### 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 98 Management practice or work practice (specify) 99 Other (specify)

4 

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

Code No. Type Rejuvenation Controls 1 Purge by sequential pressuri zing/purging with nitrogen 2 Purge using nitrogen and vacuum pump 98 Management practice or work practice (specify) 99 Other (specify)

5 

### Select from the following list of chloriding agents.

Code No. Type of Chloriding Agent 1 Perchloroethylene

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

Approval Expires __/__/__



### 47 SECTION 9. SULFUR RECOVERY UNIT

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

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

3. For each SRU listed in Table 9-1, 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 9-1. Sulfur Recovery Unit InformationSRU IDSulfur, Sulfur Cake or H2SO4Production Capacity (long tonsof sulfur/cd)Type of SRU1If subject to Federalregulation(s), provide thecitation(s)If subject to State, local, orTribal regulation(s), provide thecitation(s)Type of Tail Gas TreatmentUnit2Sulfur Pit ControlsSulfur Pit Maintenance Time(hr/yr)SRU Back-upControls/Reduction Measures3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 48 Footnotes for Table 9-1:

1 

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

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

5 EuroClaus® 6 SubDewPoint MCRC-SuperClaus®

7 LoCat®

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

2 

### 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)

3 

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

Code No. Type of SRU Back-up Control

0 None

1 Dedicated SRU flare 2 General plant flare

3 Divert to other SRU 4 Sulfur shedding (reduce production of high sulfur fuel gas) 98 Management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 49 SECTION 10. HYDROGEN PLANT VENT

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

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

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.

TABLE 10-1. Hydrogen Plant and Vent InformationHydrogen Plant IDHydrogen ProductionCapacity (MMscf/cd)Type of HydrogenProduction Unit1If subject to Federalregulation(s), providethe citation(s)If subject toState, local,or Tribal regulation(s),provide the citation(s)Hydrogen PurificationMethod Used2Type of FeedstockUsed3Steam Generation Rate(lb/hr)PSA Purge/Off Gas FlowRate (scfm)PSA Purge/Off GasDisposition4Reformer DeaeratorVent Flow Rate (scfm)Other Atmospheric Vent(Yes/No)? (If yes, reportin Table 11-1)



### Footnotes for Table 10-1:

1 

### Select from the following list of hydrogen production units.

Code No. Type of Hydrogen Production Unit 1 Steam-methane reforming

2 Partial oxidation 3 Electrolysis

4 Gasification 99 Other (specify)

2 

### Select 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)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 50 3 

### 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)

4 

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

Code No. Disposition of the PSA Purge/Off Gas

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

3 Sent to flare 4 Vented to atmosphere 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 51 SECTION 11. OTHER ATMOSPHERIC VENTS

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

2. Please provide information requested in Tabl e 11-1 for each “other atmospheric vent” at the facility. “Other atmospheric vents” include any continuous or intermittent process vents located at the facility other than those covered in Sections 5 th rough 10 of this part (Part II). “Other atmospheric vents” in clude vents on blowdown systems, knock-out pots, vacuum ejectors, and sampling systems as well as vents from oxygenate production units, coke calcining units, ethylene production units, and other proces s units co-located at the facility. “Other atmospheric vents” do not include vents asso ciated with storage tanks or pressure relief vents where ve nting occurs only during upset, startup, or shutdown events. For “other atmospheric ve nts” controlled by flares, also complete
Table 12-1 to describe the flare.

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 pa rt. Report the criteria pollutant and HAP emission estimates (tons/yr) from vents controll ed by a flare as emissions from the flare following the methods provided in the Emission Estimation Prot ocol for Petroleum Refineries using the emissions template in Annex A of this part.

TABLE 11-1. Other Atmospheric Vent InformationAtmospheric VentIDDescription ofAtmospheric VentType ofUnit/Equipment toWhich the Vent isAssociated1If subject toFederalregulation(s),provide thecitation(s)If subject to State,local, or Tribalregulation(s),provide thecitation(s)Atmospheric VentOperating Hours2Atmospheric VentControls3Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 52 Footnotes for Table 11-1:

1 

### Select from the following list of processes and e quipment that best describe the type of unit or

equipment associated with this vent.

Code No. Type of Unit/Equipment Associated with Vent 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) 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 Vacuum jet exhaustForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 53 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 ch emical production (specify chemical) 70 Coke calcining 99 Other (specify)

2 

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

Code No. Type of Operation 1 Continuous (operates whenev er the process is operating) 2 Intermittent; 4,000 hours per year or more 3 Intermittent; 2,000 hours or more but less than 4,000 hours per year 4 Intermittent; 1,000 hours or more but less than 2,000 hours per year 5 Intermittent; less than 1,000 hours per year 6 Only during startup or shutdown 7 Only during upsets 8 Only during startup, shutdown, or upsets

3 

### Select from the following list of cont rol devices. List all that apply.

Code No. Type of Control Device

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

12 Venturi/wet scrubber 13 Electrostatic precipitator (ESP)

14 Wet ESP 24 Wet scrubber/flue gas desulfurization 36 Selective non-catalytic reduction (SNCR) 37 Selective catalytic reduction (SCR) 50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

53 Flare 98 Management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 54 SECTION 12. FLARES

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

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

3. For each flare listed in Table 12-1, 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 12-1. Flare InformationFlare ID Number orDescriptionFlare 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 System3If subject to Federalregulation(s), providethe citation(s)If subject toState, local,or Tribal regulation(s),provide the citation(s)Typical Lower HeatingValue of Waste Gas(Btu/scf @ 60°F)Flare Operating Hours4Flare Controls5Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 55 Footnotes for Table 12-1:

1 

### Select from the following list of flares.

Code No. Type of Flare

1 Elevated flare 2 Elevated flare, pressure assisted

3 Ground level flare 4 Ground level flare, pressure assisted 99 Other (specify)

2 

### Select from the following list of flare assist types.

Code No. Flare Assist Types

1 Unassisted

2 Steam assisted

3 Air assisted 99 Other (specify)

3 

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

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

4 

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

Code No. Type of Operation 1 Operates 4,000 hours per year or more 2 Intermittent; Operates 2,000 hours or more but less than 4,000 hours per year 3 Intermittent; 1,000 hours or more but less than 2,000 hours per year 4 Intermittent; less than 1,000 hours per year 5 Only during startup or shutdown 6 Only during upsets 7 Only during startup, shutdown, or upsets

5 

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

Code No. Type of Control Device

1 Amine treatment 2 Flare gas recovery 3 Flare minimization plan 98 Other management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 56 SECTION 13. COOLING WATER SYSTEMS

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

2. Please provide information requested in Table 13-1 for each cooling water system at the facility.

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

TABLE 13-1. Cooling Water System InformationCooling System IDNumber or DescriptionProcess Units Servicedby Cooling WaterSystem1Cooling Water SystemOperation2Type of Cooling WaterSystem3If subject to Federalregulation(s), providethe citation(s)If subject toState, local,or Tribal regulation(s),provide the citation(s)Cooling Water Flow/Recirculation Rate(gal/min)Water Make-up Rate(gal/min)Gas or ChemicalAdditive/DisinfectionMethod4Gas or ChemicalAddition Rate ValueGas or ChemicalAddition Rate Units(volume or mass pertime)Chemical AdditionLocationMonitoring Method andFrequency5Leak DefinitionForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 57 Footnotes for Table 13-1:

1 

### Select from the following list of process units th at best describe the pr ocess 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 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) 40 Blow down system 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 58 2 

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

Code No. Type of Cooling Water System Operation 1 Services only heater exchangers in which the maximum process fluid pressure is lower than the minimum water pressure 2 Services only heater exchangers in which the process fluid contains less than 5 wt% VOC 3 Services only heater exchangers in which the process fluid contains at least 5 wt% VOC but less than 5 wt% organic HAP 4 Services heater exchangers 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 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)

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

Approval Expires __/__/__



### 59 SECTION 14. WASTEWATER COLLECTION AND TREATMENT

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

2. Please provide the following information regarding the facility-wide wastewater collection and treatment system (WWTS).

a. What is the Total Annual Ben zene (TAB) quantity for the facility?

b. Indicate the Benzene Wast e 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 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)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 60 4. Circle the response below that best descri bes the first process un it in the wastewater treatment system that is uncovered or that is covered but not vented to a control device.

1 Steam stripper

2 Oil-water separator

3 Dissolved air/gas flotation

4 Equalization basin

5 Neutralization basin

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

Approval Expires __/__/__



### 61 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 ReductionMethod4Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 62 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 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 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 63 2 

### Select from the following list the combination that best describes the monitoring parameters

and frequencies for the unit. List all that ap ply. For example, select 13A, 12B, and 22E if you continuously monitor dissolved oxygen concen tration, perform daily MLVSS analyses, and perform quarterly benzene concentration analyses.

Code No. Monitoring Parameter Co de 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)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 64 3 

### Select from the following list of compliance applicability options. List all compliance

applicability options that apply to the unit (if more than one option applies).

Code No. Compliance Applicability 0 The unit is not subject to any air standards. 1 The unit is subject to BWON but exempted from control requirements under the 2 Mg
exclusion. 2 The unit is subject to BWON but exempted from control requirements as an “enhanced biodegradation unit.” 3 The unit is subject to BWON control requirements. 4 The unit is subject to and utilized for compliance with the Hazardous Organic NESHAP (40 CFR part 63, subpart G). 5 The unit is subject to the Refinery Wastewater NSPS (40 CFR part 60, subpart QQQ).

4 

### Select from the following list of emission reducti on methods. List all opti ons 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 wi th 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 __/__/__



### 65 SECTION 15. SOLID WASTE MANAGEMENT

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

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

_________________________________________________________________________

_________________________________________________________________________ 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.

TABLE 15-1. Solid Waste Management Unit InformationUnit ID NumberType of Solid WasteManagement Unit1Description of WasteManaged in UnitArea of Solid WasteManagement Unit (m2)Capacity of Solid WasteManagement Unit (m3)If subject to Federalregulation(s), providethe citation(s)If subject toState, local,or Tribal regulation(s),provide the citation(s)Waste Application orDisposal Rate (m3/yr)Bulk Density of WasteApplied or Disposed(g/cm3)Pretreatment or ControlMethods Used2Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 66 Footnotes for Table 15-1:

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 99 Other (specify)

2 

### Select from the following list of solid waste pr etreatment 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)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 67 SECTION 16. LOADING AND UNLOADING OPERATIONS

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

2. Please provide the information requested in Table 16-1 for each loading and unloading operation at the facility. If you load/unload more than one commodity in a particular location ( e.g. , marine vessel berth, loading rack), use a separate line for each type of commodity loaded/unloaded at that location.

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.

TABLE 16-1. Loading and Unloading InformationUnit (location) IDType of vessel loaded/unoaded1Type of liquid commodityloaded/unloaded2Actual loading throughput(gal/yr)Capacity loading throughput(gal/yr)If subject to Federalregulation(s), provide thecitation(s)If subject to State, local, orTribal regulation(s), providethe citation(s)Typical annual operatinghours (hr/yr)Year loading operationinstalledDoes the facility or parentcompany own the vessels beingloaded? (Yes/No)Type of control device orcontrol technique3Date control device or controltechnique was installedForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 68 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 99 Other (specify)

2 

### Select from the following list of liquid commodities.

Code No. Type of Liquid Commodity

1 Unstabilized crude oil

2 Stabilized crude oil 3 Intermediate naphtha

4 Intermediate distillate oil 5 Intermediate heavy gas oil 6 Gasoline/blending stocks

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) 99 Other (specify)

3 

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

Code No. Type of Control

0 None 50 Thermal or catalytic incinerator/oxidizer

51 Condenser

52 Carbon adsorber

53 Flare 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 belo w the liquid level during most of the filling) 82 Bottom loading 83 Vapor balancing system 98 Other management practice or work practice (specify) 99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 69 4. Are the vessels required to be cleaned periodically? Yes No

If Yes , what are the criteria for determ ining 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 lo aded at this facility that c onduct 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 __/__/__



### 70 ANNEX A to PART II. EMISSIONS INVENTORY DATA

The U.S. EPA is working to fulfill its obligati on under CAA sections 112(f)(2) and 112(d)(6) to review residual risk and pe rform a technology review of the petroleum refinery NESHAP subparts CC and UUU. Emission data sets provided by the individual refine ries will be used for EPA’s residual risk and technology review (RTR). Attachment 1 to this enclosure is a copy of the EPA’s 2005 NATA NEI data set for each of your re fineries (if available) for your reference.

For each unit listed for which data was requested in Part II, provide emission estimates (tons/yr) for the 2009 calendar year for individual HAP a nd criteria pollutants following the methods provided in the Emission Estimation Protocol for Petroleum Refineries using the emissions template provided in this annex. Instructi ons for completing the table are provided below.

1. Unit ID : Use the same identification number th at you provided in Part II, Sections 2 through 16.

2. Unit description : Provide a short description of the unit; if the name of the unit in your operating permit includes the type of unit, you may use that name as your description ( e.g. , FCCU 02, Tank 456).

3. SCC : Attachment 2 to this enclosure pr ovides source classifi cation codes (SCC) extracted from the NEI database lookup tables . There have been updates (both additions and deletions) to the SCC over th e years, and the list in Attach ment 2 contains the current list of SCC that EPA would like you to use for this inventory. If a code that you have used in the past no longer appears in the a pplicable lookup table, please select the most appropriate code from those listed.

4. Emission point ID : Provide the identification number or code for the location at which
emissions are released into the environment.

5. Emission point description : Provide a description of the location at which emissions are
released into the environment.

6. Pollutant name : Enter the name of the pollutant for which you are estimating emissions. You will need to enter only one pollutant per row; for most units, it will take multiple rows to provide emissions estimates for all pollutants.

7. Pollutant CAS No. or Pollutant Code : See Table 1-1 of the Emission Estimation Protocol for Petroleum Refineries for a list of CAS numbers and Pollutant Codes for selected pollutants.

8. 2009 emissions (tons) : All emissions reported in th is column should reflect the ACTUAL emissions during normal operation for the reported calenda r year. (If you use a CEMS/CMS to monitor emissions of a partic ular pollutant, the readings for the entire year were within the calibr ated span of the CEMS/CMS , and you have completed the CEMS Template or CMS Template for that monitor, then you may report the total emissions recorded by that CE MS/CMS in this column.)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 71 9. Protocol methodology rank used : Provide the rank number from the appropriate chapter
of the Emission Estimation Protocol for Petroleum Refineries that best describes how you estimated emissions for the unit and pollutant provided in this row. If any of your
emissions sources is not included in the Emission Estimation Prot ocol for Petroleum Refineries ( e.g. , an ethylene unit), enter “N/A”

10. 2009 non-routine emissions (tons) : All emissions reported in this column should reflect the ACTUAL emissions during any non-routine operation for the reported calendar year, including startups, shutdowns, and other ev ents. (If you use a CEMS/CMS to monitor emissions of a particular polluta nt and the readings for part of the year were not within the calibrated span of the CEMS/CMS, estimat e emissions of that pollutant from the process unit during that event.)

11. Maximum hourly emissions (lb/hr) : Enter the maximum actual emissions from the unit in any one hour of 2009. See the Emission Estimation Protocol for Petroleum Refineries for additional information on how to determine hourly emissions.

12. Annual emissions allowed by NESHAP (tons/yr) : Enter the annual emissions during normal operation allowed by the NESHAP to which this unit is subject. If this unit is not subject to any NESHAP for this pollutant, en ter “N/A.” (Note that if the NESHAP limit is on a concentration basis, you will need to use process data at maximum capacity to convert the limit to tons/yr.)

13. Hourly emissions allowed by NESHAP (lb/hr) : Enter the maximum hourly emissions during normal operation allowed by the NESHAP to which this unit is subject. If this unit is not subject to any NESHAP for this pollutant, enter “N/A.” (Note that if the NESHAP limit is on a concentration basis, you will need to use process data at maximum capacity to convert the limit to lb/hr.)

14. Annual emissions allowed by permit (tons/yr) : Enter the annual emissions during normal operation allowed by your operating permit (may be more stringent than the emissions limit under the applicable NESHAP). (Note th at if the permit limit is on a concentration basis, you will need to use process data at maximum capacity to convert the limit to tons/yr.) If your permit does not have a numer ical limit for emissions of this pollutant from this unit, enter “N/A.”

15. Hourly emissions allowed by permit (lb/hr) : Enter the maximum hourly emissions during normal operation allowed by your operating permit (may be more stringent than the emissions limit under the applicable NESHAP). (Note that if the permit limit is on a concentration basis, you will need to use pro cess data at maximum capacity to convert the limit to lb/hr.) If your permit does not ha ve a numerical limit for emissions of this pollutant from this unit, enter “N/A.”

16. Type of Release (Point or Fugitive) : Point releases are the emissions released from a facility unit that is included in the facility inventory through one or more stacks or vents. Fugitive releases are air pollutants released to the air other than those from stacks or vents, including small releases from leaking plant equipment such as valves, pump seals,Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 72 flanges, or sampling connections, and large open area releases such as from landfills, waste ponds, or unpaved roads.

17. Point Sources : Complete the columns listed below if you answered “Point” in Number
16.

Release Height (ft) : Enter the height of the stack or vent from the ground.

Internal Vent Diameter (ft) : Enter the diameter of the stack or vent at the release height.

Exit Temperature (°F) : Enter the temperature of the exit gas stream

Gas Flow Rate (acfm) : Enter the flow rate of the exit gas stream.

18. Fugitive Sources : Complete the columns listed be low if you answered “Fugitive” in
Number 16.

Length (ft) : Enter the dimension of the sour ce in the east-west (x-) direction

Width (ft) : Enter the dimension of the source in the north-south (y-) direction

Angle : The release angle is the orientation of the y-dimension relative to true North, measured positive for clockwise starting at 0 degrees (maximum 89 degrees). EPA will assume 0 degrees if it is not provided.

19. Longitude and Latitude : Pay particular attention when entering emission release point stack parameters and locations. EPA require s latitude/longitude for each emission point provided in North American Datum (NAD) 83 w ith 6 digits to the right of the decimal point. These data are critical inputs to the modeling files that EPA will use to determine the risk profile for the re sidual risk review process. 3



### 20. Comments : Provide any comments that you feel ar e necessary to qualify or explain any of your answers to the previous questions.

3 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 fugitive angle is zero or the western most corner if the fugitive angle is greater than zero. Longitude measure in decimal degrees of the angular distance on a meridian east or west of the prime meridian. Negative (-) data point for North Am erica. Example: -123.23456 1. 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 fug itive angle is greater than zero.Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__73ANNEX A to PART II. EMISSIONS INVENTORY DATAPoint SourcesFugitiveSources

Unit ID Unit description SCC Emission point ID Emission point description Pollutant name Pollutant CAS No. or Pollutant Code 2009 emissions (tons) Protocol methodology rank used 2009 non-routine emissions (tons) Maximum hourly emissions (lb/hr) Annual emissions allowed by NESHAP (tons/yr) Hourly emissions allowed by NESHAP (lb/hr) Annual emissions allowed by permit (tons/yr) Hourly emissions allowed by permit (lb/hr) Type of Release (Point or Fugitive) Release Height (ft) Internal Vent Diameter (ft) Exit Temperature (°F) Gas Flow Rate (acfm) Length (ft) Width (ft) Angle Longitude Latitude CommentsForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__74PART III. INCIDENCE REPORTS1. Complete the following table for eachCERCLA air release notification made to the National Response Center in 2009.Type of release(continuous ornoncontinuous) Description of release eventProcessunitsassociatedwith thereleaseDuration ofthe releaseevent(hours)PollutantnamePollutantCAS No.Quantity ofpollutantreleased (lb)Quantitydeterminationmethod(measured orcalculated)Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__752. Complete the following table for each flare, air emission, or odor complaint received over the past 5 years.If applicable, provide the...ComplainantnameComplainantcontactinformationDate ofcomplaintSubstance ofcomplaintDescription of releaseevent associated withcomplaintProcess unit(s)associated withthe releaseDuration ofthe releaseevent(hours)Response tocomplaintForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 76 

### 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 10 years for which you have readily available cost information, please provide those costs as described in this part. If you wish to provide more detail than requested in Table 2 ( e.g. , you wish to itemize total capital costs), you may provide your information in a sepa rate 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 a nd your best estimate of wh ich of the components in the appropriate table were factored into that approximate cost (in lieu of completing the applicable
table for that c ontrol technique).

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

1. Please complete Table 1 for any new APCD in stalled in the last 10 years on any of the process units or other emissions sources desc ribed in Part II for which you have readily available information. The EPA is particul arly interested in costs of the following
APCD:

• Electrostatic precipitators

• Wet scrubbers

• Baghouses

• SCR/SNCR for NO X 

### control

• Steam strippers

• Carbon adsorbers

• Thermal/catalytic oxidizers

• Flares

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

• Combustion promoters or catalyst additives for NO X 

### control from FCCU

• Amine treatment systemsForm Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 77 • Installation of geodesic dome fo r external floating roof tank

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

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

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

• Monitoring devices ( e.g. , monitors that record th e duration and quantity of compounds released from a pressure relief device)

• Pollution prevention techniques

• Other management practices or work pr actices that you iden tified in Part IIForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__78Table 1. Cost Data for APCD1CAPITAL COSTS ANNUAL OPERATING COSTS10Purchasedequipmentcosts ($)5Utilities ($)Suppliesandparts13

Operating labor ($) Maintenance labor ($) Electricity Water Steam Natural gas Liquid chemicals Solid chemicals Compressed Air Other (specify) Waste disposal ($) Other annual costs (itemize) 14

Unit ID APCD Type 2 APCD Size 3 New or retrofit APCD? 4 Year of APCD installation Expected APCD equipment life (yrs) Demolition Cost of prev ious APCD, if any ($) Base year for capital costs Primary equipment ( $) 6 Auxiliary equipment ($) 7 Instrumentation and monitors ($) Sales tax and freight ($) Total purchased equipment costs ($) Installation costs ($) 8 Total Installed Cost of APCD 9 Base year for operating costs 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 $/amt Total utilities cost ($/yr) 12 amt/yr 11 $/yr Description Number of years between replacement Replacement cost (with installation) ($) Monitoring, recordkeeping & reporting ($/yr) 1 2 3 Total annual operating & maintenance cost 151Columns that are sums of other columns are shaded gray. If you do not have the all detail requested but you do have an estimate for a subtotal, enter thesubtotal in the appropriateshaded column and provide as much detailor explanation as you have available.2See list following the last footnote for codes corresponding to APCD types.3Provide the numerical value as well as the units (e.g.scfm).4If the APCD was installed at the time the process unit or emissionsource was constructed, enter “New.” If the APCD was installed after the process unitor emission source beganoperation, enter “Retrofit.”Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__795Sum of equipment, auxiliary equipment, instrumentation/monitors, sales tax, and freight.6Primary equipment is the APCD itself.Examples include SCR with catalyst, carbonadsorber with carbon, packed scrubber towerwith packing, fabric filter with bags, ESP, andsteam stripper column 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 ductworkand piping, painting,engineering, construction and fieldexpenses, contractor fees, start-up, and testing.9Sum of purchased equipment cost and installation cost.10Provide operating costs for the last 12 month period (calendar or fiscal year) for which the refinery has data.11Specify units.12For each utility that applies to this APCD, multiply the consumption rate (the first column for that utility) by the unit cost(the second column for that utility) to get the annual costfor each utility. Add the individual utility annual costs toget the total utilities cost.13Include major supplies and replacement parts; examples include catalyst for SCR and catalytic incinerators, bags of fabric filters, and carbon for carbon adsorbers.14An example might be catalyst regeneration. Note that this question is not asking for costs ofmaintenance materials, capitalrecovery, overhead, administration, property taxes, andinsurance because EPA will estimate these costs as a function of other costs.15Sum of annual costs for operating labor; maintenance labor; utilities;waste disposal; major supplies and replacement parts that are needed once per year or more frequently;monitoring, recordkeeping, and reporting; and anyother items included under “other annual costs.”Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__80Code No. Type of APCD1 Amine treatment2 Caustic spray injection3 Packed-bed wet scrubber4 Tray tower wet scrubber5 Chlorsorb11 Fabric/cartridge filter (“baghouse”)12 Venturi/wet scrubber13 Electrostatic precipitator (ESP)14 Wet ESP15 Tertiary cyclone24 Wet scrubber/flue gas desulfurization25 Spray dryer absorber36 Selective non-catalytic reduction (SNCR)37 Selective catalytic reduction (SCR)42 LoTOX® scrubber50 Thermal or catalytic incinerator/oxidizer51 Condenser52 Carbon adsorber53 Flare54 Portable internal combustion engine55 Portable thermal oxidizer56 Portable condensation system57 Permanent onsite control device for storage tanks60 Flare gas recovery83 Vapor balancing system99 Other (specify)Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__81Table 2. Cost Data for Process and Equipment ChangesUnit IDProcess orequipment changedescription1Year of process orequipment changeNumber of daysprocess shut downin order to makethe change (daysof lostproduction)2Total capital cost,$3Change in totalannual operatingcost, $/yr4Emissionreduction achieved(if quantified)51See 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” anddescribe your process or equipment change. Be as descriptive as possible. For example, for installation of low NOXor ultra low NOXburners for a process heater, note the numberof new burners, their sizes, and the fuel options (e.g., fuel gas, oil).2Enter number of days of lost productionrequired to implement the process or equipment change. If the change occurred duringscheduled downtime thatwould have occurredregardless of the process or equipment change, then do not includethe scheduled downtime. Only the days of lost production that can be specifically attributed to the process orequipment change are of interest.3Please 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.4Provide changes in annual operating costs (if estimated). Otherwise, leave blank. Include annual operating costs that are anincrease to prior operating costs (e.g., additionaloperating costs due to installation of low NOXburners). If the process or equipment change resulted in decreased annual operating costs, thenindicate the cost decrease asanegative number.5Describe the air pollutants affected and emissions reduction achieved.Indicate the basis for emissions reduction reported (e.g., air emissions testing beforeand after modification).You may provide this information as a separate attachment toyour response if you wish.Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__82Code No. Type of Process or Equipment Change1 Amine treatment21 H2S limit in fuel gas22 TRS limit in fuel gas23 Low sulfur distillate or heavy gas oil26 DeSOx catalyst, meeting 50/25 ppmv SO2limit27 DeSOx catalyst, meeting 20 lb/ton coke burn-off, but not 50/25 ppmv SO2limit28 Low sulfur (0.3 wt% or less) feed31 (External) flue gas recirculation32 Staged air low NOXburner33 Staged fuel low NOXburner34 Ultra low NOXburner (high fraction staged fuel) (ULNB)35 “Next generation” low NOXburner (ULNB with internal gas recirculation)39 High-efficiency regenerator40 Low NOXcombustion additives to replace Pt-based combustion additives41 Other low NOXcatalyst additives70 Water seal71 Fixed seal72 Hard piping80 Submerged loading (i.e., loading from the top of the vessel; the fill pipe extendsalmost to the bottom of the vessel such that it isbelow the liquid level during most of the filling)82 Bottom loading99 Other (specify)Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 83 

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

In this section, emissions test data are requeste d. Please satisfy this request as completely as possible from existing information. No additiona l monitoring or emission testing is required by your company to respond to the data request in this section. Four type s of existing emissions data are requested: 1) source test data, 2) qua lified 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 submitting test data, EPA is requesting full test reports with field and lab data sheets and example calculati ons, not just summary reports.

If any of the data requested in th is part is considered CBI, follow the instructions in the section “Submitting CBI” under the heading “How to Submit Your Survey Response” in the
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 incl uded in Part II, Sections 3 through 16 on or after January 1, 2005. Electronic (pdf) or ha rd copies are acceptable. Include the summary portion of the report and any appendi ces showing run-by-r un test parameters, method detection limits, laboratory data, product ion 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 (maximum of three tests per unit for one pollutant).

In addition, complete the source test summary table shown in Attachment 3 of this enclosure for each source test you submit. (Electronic copies of this table can be downloaded from the ICR website ( http://icr2010.rti.org , click on “Petroleum Refineries”).) Note that the informati on requested in the summary table includes:

(A) emission rates measured,

(B) the test method or procedure used,

(C) information on actual production or pro cessing 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.

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

### , SO 2 

### , and THC CEMS on any of the processes or emission poi nts included in Part II, Sections 2 through 16. Report daily averages for each day in 2009 using the Microsoft® Excel CEMS Template; an example template is shown in Attachment 4. The Excel templates are specific to each pollutant and type of unit, and each template is designed to accommodate data from one CEMS (including oxygen data). Electronic copies of the template can be downloaded from the ICR website ( http://icr2010.rti.org , click on “Petroleum Refineries”).Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 84 Qualified CEMS data include: data fr om a PM CEMS that meets Performance Specification 11 or 15; data from a CO CEMS that meets Performance Specification 4;
data from a SO 2 

### and/or NO X 

### CEMS that meets Performance Specification 2; data from a THC CEMS that meets Performance Specificat ion 8A; or data from any CEMS meeting the accuracy and ongoing QA/QC requirements of 40 CFR part 60, Appendix F.

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 2009 using the Microsoft® Excel CMS Template; an example template is shown in Attachment 4. The Excel templates are specific to each pollutant and type of unit, and each template is designed to acco mmodate data from one CMS. Electronic copies of the template can be downloaded from the ICR website ( http://icr2010.rti.org

, click on “Petroleum Refineries”).

Qualified CMS data include: data from a H 2 

### S CMS that meets Performance Specification 7; data from a reduced sulfur or total reduced sulfur CMS that meets Performance Specification 7; data from a hydrocarbon or Btu CMS (gas composition monitor) that meets Performance Specifica tion 5; data from any CMS meeting the accuracy and ongoing QA/QC requirements of 40 CFR part 60, Appendix F; or data from any CMS for that has been calibrated per th e manufacturer’s specifi cations within the past 12 months and is operated and maintained (including on-going QA/QC requirements) according to the manufacturer’s specifications.

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

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

6. Equipment leak correlations : If you developed site-specific correlations for equipment leaks at your facility and you use those co rrelations to estimate emissions from equipment leaks, provide a complete copy of the report or other documentation describing the testing and deve lopment of the correlations.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 85 

### PART VI. SUMMARY OF TEST PROCEDURES, METHODS, AND REPORTING REQUIREMENTS FOR CR UDE OIL COMPOSITION ANALYSIS

The EPA petroleum refinery test program is reque sting variability data for crude oil-based HAP. This part provides an overview of approved met hods, target pollutants and units of measure, and reporting requirements for the crude oil composition analysis. All recipients must complete and submit test results within 90 days of receipt.

The crude oil composition analyses requested in clude: mercury, chlorine, sulfur, and metals ( e.g. , antimony, arsenic, beryllium, cadmium, chro mium, cobalt, lead, manganese, nickel, and selenium).

You will need to collect at le ast three samples of each crud e oil received by your refinery, composite these samples, and then analyze and report each composited sample. Directions for collecting, preparing, and analyzing the crude oil samples are outlined below.

Note: If you do not refine any crude oil at your facility, provide a list of the intermediate feedstocks that are refined by your facility and perform the analyses described below for those
intermediate feedstocks in lieu of the crude oil composition analysis.

1. How to collect a crude oil sample : Table 1 outlines a summary of how samples should be
collected.

Table 1. Summary of Sample Collection Procedures

Sampling Location Sampling Procedures

Site-Specific Sampling and Analysis

Manual Sampling Follow collection me thods outlined in ASTM D4057

Automatic Sampling Follow collection methods outlined in ASTM D4177

Crude Oil Supplier Analysis

Crude Oil Supplier If you will be using crude oil analysis from a crude oil supplier in lieu of site-specific sampling and analysis, th e crude oil supplier must collect the sample as specified above and prepare the sample according to methods specified in Steps 2 and 3 of this part.



### 2. Prepare sample for analysis : To prepare your samples for mercury and selected metal analyses, use SW-846-3020A or any SW-846 sample digestion procedures giving
measures of total metal. For other analyses, use the guidance in ASTM D7455-08 for appropriate sample preparation.

3. Analyzing crude oil sample : Table 2 outlines a list of approved methods for analyzing crude oil samples. If you would like to use a method not on this list, and the list does not meet the definition of “equivale nt” provided in Section 5 of th is document, please contact EPA for approval of an alternative method.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 86 Table 2. List of Analytical Methods for Crude Oil Analysis

Analyte Method Target Reported Units

of Measure

Higher Heating Value ASTM-5865-03a, ASTM D240, ASTM E711-87 (1996) Btu/lb

Density/API Gravity ASTM D287-92, ASTM D1217-993, ASTM D1481-93,
ASTM D4052-96 lb/ft 3 AND API Gravity

Mercury Concentration SW-846-7470A, EPA Method 1631E, SW-846-1631E, SW-846-1631, EPA 821-R-01-013, or equivalent ppm

Total Selected Metals
Concentration SW-846-6020, -6020A, , SW-846-6010B, SW-846- 7740 for Se, SW-846-7060 or -7060A for As ppm

Chlorine Concentration ASTM E776-87 (1996, 2004, or 2009), SW-846-9250, SW-846-5050, -9056, -9076, or -9250 ppm

Sulfur Concentration ASTM D129-00 (2005), ASTM D1552-01 or -08,
ASTM D2622-98 or -10 ppm



### 4. Reporting crude oil analysis data : You must report the analysis results separately for each of the composited samples in a Microsoft ® Excel Crude Oil Analysis Template. This Excel template can be downloaded from the ICR website ( http://icr2010.rti.org

, click on “Petroleum Refineries”). The template asks you to identify th e country of origin and crude type ( e.g. , Texas sweet) for crude analysis. If you conducted composition analysis on more than one type of crude o il, you must make a copy of the worksheet and update the crude oil type in each worksheet order to distinguish between the separate crude oil composition analyses.

You must keep the following records for 3 years:

• Documentation that crude oil samples we re obtained in accordance with the above sampling protocol;

• Documentation of the proper chain of custody for each crude oil sample;

• Description of the QA/QC procedures followed in preparing each crude oil sample for analysis and perfor ming the required analysis; and

• The results of the analyses performed on each crude oil sample.Form Approved __/__/__ OMB Control No. ____-____

Approval Expires __/__/__



### 1-1 

### Attachment 1. 2005 NEI Data for Each Refinery

(To be pulled from the NEI data and compiled fo r each refinery. This page could be a cover page and/or each refinery table could have a cove r page, or the NEI table may just have a header
or footer that identifies it as part of Attachment 1)Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__2-1Attachment 2. Lists of SCC(This is an example of one of multiple tablesthat will be in this Attachment. Each type of emission source will have an SCC in thisAttachment.)Table 2-1. List of Storage Tank SCCSCCSCC_L1SCC_L2SCC_L3SCC_L440302001 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Crude Oil40302002 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Gasoline40302003 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Jet Naphtha (JP-4 or Jet B)40302004 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Kerosene (including JetKerosene Jet A-1, Jet A, JP-5,or JP-8)40302005 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Distillate Fuel (Diesel Fuel,#2 Fuel Oil, or #3 Fuel Oil)40302006 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Heavy Fuel Oil (# 4 Fuel Oil)40302007 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Residual or Heavy Gas Oil (#5 or #6 Fuel Oil)40302008 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Unfinished or IntermediateNaphtha40302009 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesFixed Roof Tanks Other (Specify)40302101 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Crude Oil40302102 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Gasoline40302103 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Jet Naphtha (JP-4 or Jet B)Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__2-2SCCSCC_L1SCC_L2SCC_L3SCC_L440302104 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Kerosene (including JetKerosene Jet A-1, Jet A, JP-5,or JP-8)40302105 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Distillate Fuel (Diesel Fuel,#2 Fuel Oil, or #3 Fuel Oil)40302106 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Heavy Fuel Oil (# 4 Fuel Oil)40302107 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Residual or Heavy Gas Oil (#5 or #6 Fuel Oil)40302108 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Unfinished or IntermediateNaphtha40302109 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(Without Geodesic Dome)Other (Specify)40302201 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Crude Oil40302202 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Gasoline40302203 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Jet Naphtha (JP-4 or Jet B)40302204 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Kerosene (including JetKerosene Jet A-1, Jet A, JP-5,or JP-8)40302205 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Distillate Fuel (Diesel Fuel,#2 Fuel Oil, or #3 Fuel Oil)40302206 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Heavy Fuel Oil (# 4 Fuel Oil)40302207 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Residual or Heavy Gas Oil (#5 or #6 Fuel Oil)40302208 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Unfinished or IntermediateNaphthaForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__2-3SCCSCC_L1SCC_L2SCC_L3SCC_L440302209 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesExternal Floating Roof Tanks(With Geodesic Dome)Other (Specify)40302301 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Crude Oil40302302 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Gasoline40302303 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Jet Naphtha (JP-4 or Jet B)40302304 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Kerosene (including JetKerosene Jet A-1, Jet A, JP-5,or JP-8)40302305 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Distillate Fuel (Diesel Fuel,#2 Fuel Oil, or #3 Fuel Oil)40302306 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Heavy Fuel Oil (# 4 Fuel Oil)40302307 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Residual or Heavy Gas Oil (#5 or #6 Fuel Oil)40302308 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Unfinished or IntermediateNaphtha40302309 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesInternal Floating Roof Tanks Other (Specify)40302401 Petroleum and SolventEvaporationPetroleum Product Storage atRefineriesLPG Pressurized Tanks Examples: Propane Spheres,Butane SpheresForm Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__3-1Attachment 3. Source Test Summary TableUnitID(s)APCDType(s)Date of testreportPollutantstested1Testmethod(s)used2Are theseinlet oroutlet data(or both)?Configurationchanges3Process testingnotes(optional)4OPTIONAL: Howoften are yourequired to performtesting of thisemission unit for thepollutants listed?OPTIONAL:Approximatecost per test,$1List the pollutants tested. Separate multiple pollutants by commas.2Enter the EPA test method number (e.g., M5, M7E). Be very specific if the method used was not an EPA method.3If the configuration of the emission unit,combustion controls, collection system, orAPCD changed sincethe test was conducted, describe the changes. If there are no configurationchanges, enter “N/A”4Use this column for notes or if helpful to specify the emission points tested (e.g., for equipment with multiple emission points, whereonly selected emission points/vents were tested)Form Approved __/__/__OMB Control No. ____-____Approval Expires __/__/__4-1Attachment 4. Example CEMS TableNOXCEMS DATAEmission Unit ID:APCD_ID:OPTIONAL: 1-day average emission value for NOXin units other than ppmvdCEMSDate(mm/dd/yyyy)DailyProductionRate(value)DailyProductionRate(units)1-day averageemission valuefor NOX(ppmdv,corrected for%O2)% O2correction(by volume,dry basis)Data averageaffected by astartup,shutdown, orother event?11-day averageemission valuefor NOX,corrected for%O2(value)1-day averageemission valuefor NOX,(units)% O2correction (byvolume, drybasis)01/01/200901/02/200901/03/200901/04/200901/05/200901/06/200901/07/200901/08/200901/09/2009......12/25/200912/26/200912/27/200912/28/200912/29/200912/30/200912/31/20091If no, leave blank. If yes, respond “startup,” “shutdown,” or “event”; if you respond “event” please include a brief description of the event.