# app_Instructions

INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any facilities in “Select Facility to Edit.”  Click the button to “Add Facility” and enter all information related to that facility, beginning with the Facility ID, then click “Save And Close.”  Any time you return to this screen, you will need to select your facility from the list at the top of the form before you can view and edit information.

* The “Products Produced” tab is the one question in the entire ICR that you may answer “Other” more than once, so if you have more than one product that is not in the list, select “Other” for each of those and specify in the space provided.

* On the Process Units tab, be sure to click “Add Process Unit” before you add every process unit.  If you type something into the “Process Unit ID” field, enter information, then immediately try to change the Process Unit ID without clicking either “Add Process Unit” or “Save And Close” the entry for the first unit will NOT be saved.

* Several of the Sections in Part II require you to have already entered the process unit on the Process Unit tab in Part I (see list below).  If you get to those sections and have not entered your process units, you will need to return to this screen to enter them. 
Section 3.  Equipment Leaks
Section 5.  Catalytic Cracking Units
Section 6.  Fluid Coking Units
Section 7.  Delayed Coking Units
Section 8.  Catalytic Reforming Units
Section 9.  Sulfur Recovery Units
Section 10.  Hydrogen Plant Vent
Section 13.  Fuel Gas Treatment Units
Section 15.  Wastewater Collection and Treatment


Form Content Help:

* 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.

* General tab:
--- Facility ID:  Enter the ID provided on page 2 of your Section 114 cover letter.  If you cannot locate your Facility ID or did not receive a Section 114 letter for this facility, contact EPA for a Facility ID.

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

*Parent Company tab:
--- Joint venture partners:  For each joint venture partner with 50% or greater ownership, provide the number of employees in the partner company

--- Degree of independence from parent company:  Select the statement that best applies.

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

* Process Units tab:  Report the 2010 process capacities and actual throughput for each process unit by providing the information requested on this tab.  See definitions section for additional descriptions of the terms used.  You may need to add “other” process units if your refinery contains significant processing units that are not covered by the processes listed.  If 2010 throughputs are not representative of normal operations (e.g., plant idled temporarily for economic reasons, change of ownership, or fire, etc.), add a note describing the reason for the unusual operation and provide an estimate of the expected “normal” 2010 processing rates had these issues not occurred.
When asked for a Unit ID, use a unique Unit ID for each process unit.  When possible, use the same identifier from your permit or emissions inventory.

* Process Units tab, Throughput questions:  Throughput by calendar day × 365 days = annual throughput for 2010.Throughput units are barrels per calendar day (bbl/cd) unless noted otherwise.

--- For the following units, “throughput” is determined in terms of charged liquid material (excluding hydrogen gas inputs):
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 regeneration
Catalytic reforming unit – cyclic regeneration
Catalytic reforming unit – semi-regenerative
Fuels solvent deasphalting
Desulfurization/ hydrotreating – naphtha/reformer feed
Desulfurization/ hydrotreating – gasoline
Desulfurization/ hydrotreating – kerosene/jet fuel
Desulfurization/ hydrotreating – diesel
Desulfurization/ hydrotreating – other distillate
Desulfurization/ hydrotreating – residual
Desulfurization/ hydrotreating – heavy gas oil
Desulfurization/ hydrotreating – other

--- For catalytic cracking units, include both fresh and recycle feed.
For the following units, “throughput” is determined in terms of primary product produced (e.g., quantity of alkylate produced in alkylation unit):
HF alkylation
H2SO4 alkylation
Aromatics production
Asphalt production
Isomerization – Isobutane
Isomerization – Iso C5,C6
Lubricants production
Petroleum coke storage
Hydrogen plant
Sulfur recovery unit (SRU)
Gas plant/light ends distillation/LPG production unit
Oxygenate plant – MTBE
Oxygenate plant – ETBE
Oxygenate plant – TAME
Oxygenate plant – other (specify)
Coke calcining
Ethylene production
Ethylene dichloride production
Ethylene dibromide production
Propylene production
Acrylonitrile production
Other petrochemical or organic chemical production (specify chemical)

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

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

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

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

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

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

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

* Process Units tab, Steam Consumption question:  You do not have to answer this question for WWTS.


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any process heaters in “Select Process Heater to Edit.”  Click the button to “Add Process Heater” and enter all information related to that process heater, beginning with the Process Heater ID, then click “Save And Close.”  Any time you return to this screen, you will see your process heater in the list at the top of the form.

* The “Delete Process Heater” button deletes the information you have entered on this form for the selected Process Heater ID, including the Process Heater ID itself.  If you have entered information for this process heater on any other form, that information will also be deleted.


Form Content Help:

* Please provide the information requested in this form for each process heater at the facility that serves a process unit identified in Part I.

General tab: 
--- Air preheat use:  Select the option that best applies for the unit.


INSTRUCTIONS:
Form Navigation Help:

* You should see the sulfur recovery units that you entered in Part I in the dropdown list beside “Unit ID for SRU.”  If you do not, close the form, go back to Part I, and enter your sulfur recovery units on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete SRU Data” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.


Form Content Help:

* Please provide information requested in this form for each sulfur recovery unit (SRU) at the facility.
	
* General tab: 
--- Sulfur Recovery Plant ID:  For purposes of this collection, multiple SRU are considered part of a single SRP when the units share the same source of sour gas.  Sulfur recovery units that receive source gas from completely segregated sour gas treatment systems are considered part of separate SRP.


INSTRUCTIONS:
Form Navigation Help:

* You should see the hydrogen plants that you entered in Part I in the dropdown list beside “Select Unit ID for Hydrogen Plant.”  If you do not, close the form, go back to Part I, and enter your hydrogen plants on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Plant/Vent Data” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.


Form Content Help:

* Please provide information requested in this form for each hydrogen plant at or under common control of the facility.


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any vents in “Select Atmospheric Vent to Edit.”  Click the button to “Add Other Atmospheric Vent” and enter all information related to that vent, beginning with the Atmospheric Vent ID, then click “Save And Close.”  Any time you return to this screen, you will see your other atmospheric vent in the list at the top of the form.

* The “Delete Vent Data” button deletes the information you have entered on this form for the selected Atmospheric Vent ID, including the Atmospheric Vent ID itself.  If you have entered information for this other atmospheric vent on any other form, that information will also be deleted. 
	

Form Content Help:

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

* General tab:
--- Type of Atmospheric Vent:  Select the option that best describes the type of unit or equipment associated with this vent.

--- Unit ID with which the vent is associated:  Enter the Unit ID associated with the vent only if the vent is associated with only one process unit.  If the vent is in general use or used by multiple process units, leave this question blank.  (Any further detail you wish to provide may be included by clicking “Note” at the top of this form.)


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any flares in “Select Flare to Edit.”  Click the button to “Add Flare” and enter all information related to that flare, beginning with the Flare ID Number or Description, then click “Save And Close.”  Any time you return to this screen, you will see your flare in the list at the top of the form.

* The “Delete Flare Data” button deletes the information you have entered on this form for the selected Flare ID, including the Flare ID itself.  If you have entered information for this flare on any other form, that information will also be deleted. 


Form Content Help:

* Please provide information requested in this form for each flare at the facility.

* General tab:
--- Flare Operating Hours:  Select the option that best describes the operation of the flare.


INSTRUCTIONS:
Form Navigation Help:

* You should see the fuel gas treatment units that you entered in Part I in the dropdown list beside “Select Fuel Gas Treatment Unit ID.”  If you do not, close the form, go back to Part I, and enter your fuel gas treatment units on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Treatment Unit Data” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.


Form Content Help:

* Please provide information requested in this form for each fuel gas treatment unit at the facility.


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any heat exchange systems in “Select Heat Exchange System to Edit.”  Click the button to “Add Heat Exchange System” and enter all information related to that heat exchange system, beginning with the Heat Exchange ID Number or Description, then click “Save And Close.”  Any time you return to this screen, you will see your heat exchange system in the list at the top of the form.

* The “Delete System Data” button deletes the information you have entered on this form for the selected Heat Exchange ID, including the Heat Exchange ID itself.  If you have entered information for this heat exchange system on any other form, that information will also be deleted.	


Form Content Help:

* Please provide information requested in this form for each heat exchange (HE) system at the facility.


INSTRUCTIONS:
Form Navigation Help:

* Be sure to answer the questions at the top of the form by clicking on the “Facility-Level Questions” button and the “Wastewater Vent Information” button above “Select Wastewater Treatment System ID.”

* You should see the wastewater collection and treatment systems (WWTS) that you entered in Part I in the dropdown list beside “Select Wastewater Treatment System ID.”  If you do not, close the form, go back to Part I, and enter your WWTS on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Wastewater System Data” button deletes the information you have entered in this Part II form for the selected WWTS ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.

* The first time you come to this screen, you will not see any wastewater treatment processes in “Select Wastewater Treatment Process to Edit.”  Click the button to “Add Wastewater Treatment Process” and enter all information related to that process, beginning with the Type of Wastewater Treatment Process, then click “Save And Close.”  Any time you return to this screen, you will see your wastewater treatment processes in the list at the top of the form.

* The “Delete Wastewater Treatment Process” button deletes the information you have entered on this form for the selected Type of Wastewater Treatment Process.  If you have entered information for this wastewater treatment process on any other form, that information will also be deleted.


Form Content Help:
	
* Please provide information requested in this form to indicate the wastewater treatment processes used for each WWTS (identified in Part 1) at the facility and the applicable air regulations for each selected unit.

* General tab:  Provide the total of the average steam usage rates for each stripper in 2010.  For example, if you have two sour water strippers, add the average steam usage rate in pounds per hour in 2010 for the first sour water stripper to the average steam usage rate in pounds per hour in 2010 for the second sour water stripper and report the resulting sum on this tab.


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any wastewater vents in “Select Select Wastewater Vent to Edit.”  Click the button to “Add Wastewater Vent” and enter all information related to that wastewater vent, beginning with the Wastewater Vent ID, then click “Save And Close.”  Any time you return to this screen, you will see your wastewater vent in the list at the top of the form.

* The “Delete Vent Data” button deletes the information you have entered on this form for the selected Wastewater Vent ID, including the Wastewater Vent ID itself.  If you have entered information for this wastewater vent on any other form, that information will also be deleted.	


Form Content Help:

* General tab:  Please provide information requested on this form for each “wastewater vent” at the facility.  “Wastewater vents” include atmospheric vents associated with wastewater drain systems (including junction box vents) and gases purged from covered WWTS.


INSTRUCTIONS:
Form Navigation Help:

* Be sure to answer the questions at the top of the form by clicking on the “Facility-Level Questions” button above “Select Unit ID for loading operation.”
	
* You should see the loading locations that you entered in Part I in the dropdown list beside “Select Unit ID for loading operation.”  If you do not, close the form, go back to Part I, and enter your product loading locations on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Loading Unit Data” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.


Form Content Help:

* Please provide information requested in this form for each fixed location product loading operation (e.g., dock, loading rack) at the facility (i.e., those considered part of the refinery facility).


INSTRUCTIONS:
Form Content Help:
	
* Wastewater Generation Information:  Please provide the information requested in this table for each process unit that routinely generates wastewater.  Please provide your best estimate based on available information; no additional testing is required to complete this request.


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any releases in “Find Release by Date and Description.”  Click the button to “Add Release” and enter all information related to that release, beginning with the Date of Release and Type of Release, then click “Save And Close.”  Any time you return to this screen, you will see your release in the list at the top of the form.

* The “Delete Release” button deletes the information you have entered on this form for the selected release event.  If you have entered information for this release on any other form, that information will also be deleted.


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any APCD in “Select APCD to Edit.”  Click the button to “Add APCD” and enter all information related to that APCD, beginning with the APCD ID, then click “Save And Close.”  Any time you return to this screen, you will see your APCD in the list at the top of the form.

* The “Delete APCD” button deletes the information you have entered on this form for the selected APCD ID, including the APCD ID itself.  If you have entered information for this APCD on any other form, that information will also be deleted.


Form Content Help:

* Costs should be provided in U.S. dollars.

* The EPA is particularly interested in costs of the following APCD:
--- Electrostatic precipitators
--- Wet scrubbers
--- Baghouses
--- SCR/SNCR for NOX control
--- Steam strippers
--- Carbon adsorbers
--- Thermal/catalytic oxidizers
--- Flares

* General tab:
--- New or Retrofit?  If the APCD was installed at the time the process unit or emission source was constructed, enter “New.”  If the APCD was installed after the process unit or emission source began operation, enter “Retrofit.”

* Capital Costs tab:  
--- Primary Equipment:  Primary equipment is the APCD itself.  Examples include SCR with catalyst, carbon adsorber with carbon, packed scrubber tower with packing, fabric filter with bags, ESP, and steam stripper column with nozzles, manholes, and trays.

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

--- Total purchased equipment cost:  Sum of equipment, auxiliary equipment, instrumentation/monitors, sales tax, and freight.  If you do not have the all detail requested but you do have an estimate for this value, enter the estimate and provide as much detail or explanation as you have available.

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

--- Total installed cost.  Sum of purchased equipment cost and installation cost.  If you do not have the all detail requested but you do have an estimate for this value, enter the estimate and provide as much detail or explanation as you have available.

* Operating Costs tab:  Provide operating costs for the last 12 month period (calendar or fiscal year) for which the refinery has data.

-- Total utilities cost per year:  For each utility that applies to this APCD, multiply the consumption rate (the first column for that utility) by the unit cost (the second column for that utility) to get the annual cost for each utility.  Add the individual utility annual costs to get the total utilities cost.
If you do not have the all detail requested but you do have an estimate for a subtotal, enter the subtotal in the appropriate field and provide as much detail or explanation as you have available.

--- Total Operating and Maintenance Costs:  Sum of annual costs for operating labor; maintenance labor; utilities; waste disposal; major supplies and replacement parts that are needed once per year or more frequently; monitoring, recordkeeping, and reporting; and any other items included under “other annual costs.”
If you do not have the all detail requested but you do have an estimate for a total, enter the total and provide as much detail or explanation as you have available.

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

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


INSTRUCTIONS:
Form Navigation Help:

* Electricity and Steam Generation Information tab:  The questions on this tab will be unlocked if you answer “Yes” to the first question.  If you do not see your generation unit in the list on the left, click “Add Generation Unit.”

* The “Delete Generation Unit” button deletes the information you have entered on this form for the selected Generation Unit ID, including the Generation Unit ID itself.  If you have entered information for this process heater on any other form, that information will also be deleted.


Form Content Help:

* 2010 Fuel Consumption tab:  Provide the total energy use and fuel consumption by the entire refinery in 2010 as reported to EIA on forms EIA-810 and EIA-820.  For crude oil, report only the quantity of crude oil consumed as fuel, not the quantity of crude oil fed to the atmospheric crude or vacuum distillation column.

* Electricity and Steam Generation Information tab:  Provide the information requested for each electricity generating, steam generating, or combined heat and power unit.  Include energy recovery turbines and waste heat boilers used on process unit exhaust lines.

--- Unit description:  For waste heat boiler, list process unit and “waste heat boiler” (e.g., “FCCU waste heat boiler”).

--- Percent Steam to Blowdown:  If the exact percentage is unknown, and you are unable to provide a reasonable estimate, answer “Unknown.”


INSTRUCTIONS:
Form Navigation Help:

* You should see the process units that you entered in Part I in the dropdown list beside “Unit ID.”  If you do not, close the form, go back to Part I, and enter your process units on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Equipment Leak” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.

* On the LDAR tab, make sure you answer questions on all the sub-tabs (if applicable).  The last sub-tab is “Other.”  Use the arrows at the sub-tab level to scroll all the way to the end.


Form Content Help:

* Complete this form for each process unit identified in Part I except WWTS.  The total equipment counts should be the total number of pieces of equipment in a process unit, not necessarily only those currently being monitored.  Do not count pieces of equipment that are in vacuum service.  You may provide reasonable estimates of equipment counts from existing information if the requested equipment counts are not directly available as requested for each process unit as defined in this ICR.

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

* All subtabs on LDAR tab:  
--- When asked for the number of pieces of equipment monitored, do not include difficult-to-monitor equipment.

--- When asked for a monitoring frequency, select the option that best describes the frequency at which the majority of the equipment are monitored for the process unit, type of equipment, and type of service.

--- When asked for a leak definition, select the monitored concentration above which repairs are required (or routinely performed) for the process unit, type of equipment, and type of service.

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

* Other tab on LDAR tab:  Other equipment includes any other fugitive emissions source not already provided that is monitored similar to equipment.  Specify the types of fugitive emission sources.

--- Monitoring frequency question:  If you specified multiple types of fugitive emission sources and they have different monitoring frequencies, select the shortest monitoring interval for such sources.

--- Leak definition question:  If you specified multiple types of fugitive emission sources and they have different leak definitions, select the lowest leak definition for such sources.

* Atmospheric PRD tabs (both Gas and Liquid) on Pressure Relief Devices tab: 
--- Monitoring frequency question:  Select from the option that best applies for the process unit, type of equipment, and type of service.  Select “None” if none of the other options apply.

--- Leak definition question:  Select from the monitored concentration above which repairs are required (or routinely performed) for the process unit and type of service.  Select “None” if the PRD are not monitored regularly on a set schedule (i.e., they are only monitored after a release to confirm that there are no detectable emissions).

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


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any gas systems in “Select Gas System to Edit.”  Click the button to “Add Gas System” and enter all information related to that gas system, beginning with the Fuel or Natural Gas ID, then click “Save And Close.”  Any time you return to this screen, you will see your gas system in the list at the top of the form.

* The “Delete Gas System” button deletes the information you have entered on this form for the selected Fuel or Natural Gas ID, including the Fuel or Natural Gas ID itself.  If you have entered information for this gas system on any other form, that information will also be deleted.


Form Content Help:

* Complete this form for each fuel gas and natural gas system at the facility.  The equipment counts should be the total number of pieces of equipment the fuel gas and natural gas system at the facility (without double counting equipment included on the Equipment Leaks – Process Units form).  You may provide reasonable estimates of equipment counts from existing information if the requested equipment counts are not directly available as requested for each fuel gas and natural gas system.

* LDAR tab:  Use the definition of “gas service” in the regulation to which the fuel gas or natural gas system is subject, if applicable.  See the list of definitions for this ICR for a definition of this term to use if the fuel gas or natural gas system is not subject to a regulation that includes a definition of this term.

* All subtabs on LDAR tab:  
--- When asked for the number of pieces of equipment monitored, do not include difficult-to-monitor equipment.

--- When asked for a monitoring frequency, select the option that best applies for the fuel gas or natural gas system, type of equipment, and type of service.

--- When asked for a leak definition, select the monitored concentration above which repairs are required (or routinely performed) for the fuel gas or natural gas system, type of equipment, and type of service.

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


INSTRUCTIONS:
Form Navigation Help:

* Be sure to answer the questions at the top of the form by clicking on the “Facility-Level Questions” button above “Select Storage Tank to Edit.”

* The first time you come to this screen, you will not see any storage tanks in “Select Storage Tank to Edit.”  Click the button to “Add Storage Tank” and enter all information related to that storage tank, beginning with the Tank ID, then click “Save And Close.”  Any time you return to this screen, you will see your storage tank in the list at the top of the form.

* The “Delete Storage Tank” button deletes the information you have entered on this form for the selected Tank ID, including the Tank ID itself.  If you have entered information for this storage tank on any other form, that information will also be deleted. 


Form Content Help:

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

* General tab:
--- Type of stored liquid:  Report the type of liquid stored (or crude oil received) in the tank for the predominant use of the tank.

--- Type of tank/controls:  See the list of definitions for this ICR for details on what is considered a controlled guidepole.


INSTRUCTIONS:
Form Navigation Help:

* You should see the catalytic cracking units that you entered in Part I in the dropdown list beside “Unit ID for CCU.”  If you do not, close the form, go back to Part I, and enter your catalytic cracking units on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Catalytic Cracking Unit” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.


Form Content Help:

* Please provide information requested in this form for each catalytic cracking unit (CCU) at the facility.


INSTRUCTIONS:
Form Navigation Help:

* You should see the fluid coking unit(s) that you entered in Part I in the dropdown list beside “Unit ID for FCU.”  If you do not, close the form, go back to Part I, and enter your fluid coking unit(s) on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Fluid Coking Unit” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.

* When you select the Unit ID for the FCU, some questions on the General tab will be disabled based on whether the FCU is a traditional FCU or a flexicoking unit.  If the questions applicable to your unit are disabled and the ones left unlocked do not apply to your type of FCU, close the form, go back to Part I, and check to make sure you entered the correct type of FCU for that Unit ID on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.


Form Content Help:

* Please provide information requested in this form for each fluid coking unit (FCU) at the facility.

* General tab: 
--- Produced Coke Disposition: Select the option that best describes the coke disposition method.

--- Produced Coke Handling Controls:  Select the option that best describes the coke handling method.

--- FCU dust/ash handling/disposal method:  Select the method that best describes the flexicoking dust/ash handling and disposal method.


INSTRUCTIONS:
Form Navigation Help:

* You should see the delayed units that you entered in Part I in the dropdown list beside “Unit ID for DCU.”  If you do not, close the form, go back to Part I, and enter your delayed coking units on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Delayed Coking Unit” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.

* Feed Information tab:  Once you’ve entered feed information for one DCU, you can apply the same feed information to another DCU with similar feed compositions.  Select the first DCU in the dropdown on the right, and then click the button that says “Copy Feed Information from Another Unit ID.”


Form Content Help:

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

* Typical Cycle Time tab:  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.

Quench Water tab:  
--- Purged steam blowdown system condensed water and uncondensed vapor dispositions:  Select the methods used to manage the steam exhausted during the steam purge and water quench cycles (prior to venting the vessel to atmosphere).

--- Quench water disposition refers to the water drained from the drum after the vessel is vented to the atmosphere.

Feed Information tab:  If several DCU have similar feed compositions, you may copy the feed information from one DCU to another using the instructions above.  If the DCU at the facility have different feed compositions, provide the typical and maximum feed compositions separately for each set of similar DCU.

--- Typical % Feed:  Typical or average feed composition for DCU.  The sum of all typical feed composition values for one DCU should be 100%.

--- Maximum % Feed:  Maximum percent of each feed source that can be used in the DCU.  The sum of all maximum feed values for one DCU is expected to exceed 100%.


INSTRUCTIONS:
Form Navigation Help:

* You should see the catalytic reforming units that you entered in Part I in the dropdown list beside “Unit ID for CRU.”  If you do not, close the form, go back to Part I, and enter your catalytic reforming units on the “Process Units” tab.  Then return to this form to select the Unit ID for the unit you wish to edit.

* The “Delete Catalytic Reforming Unit” button deletes the information you have entered in this Part II form for the selected Unit ID.  It does not delete information for that process unit anywhere else.  If you want to completely delete a unit from the ICR, go to Part I, Process Units tab.


Form Content Help:

* Please provide information requested in this form for each catalytic reforming unit (CRU) at the facility.

* General tab: 
--- Average Annual Regeneration Frequency:  This question only applies to cyclic and semi-regen units.  If the unit does not regenerate catalyst at least once a year, estimate the number of cycles based on the interval between cycles.  If the interval between cycles varies, you may use the interval between the two most recent cycles.  For example, if regeneration occurs once every two years, then the number of cycles per year would be 1 cycle ÷ 2 years = 0.5 cycles per year.  The number of hours per year may be estimated by multiplying an average number of hours per cycle by the calculated number of cycles per year.


INSTRUCTIONS:
Form Content Help:

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

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

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

For question number 3, types of techniques that EPA is particularly interested in include:
Use of a portable or temporary control device (e.g., for degassing of storage tanks)
Monitoring devices (e.g., monitors that record the duration and quantity of compounds released from a PRD) 
Pollution prevention techniques
Energy management programs identified in Part II, Section 1
Other management practices or work practices that you identified in Part II


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any process and equipment changes in “Select Change to Edit.”  Click the button to “Add Change” and enter all information related to that process or equipment change, then click “Save And Close.”  Any time you return to this screen, you will see your change in the list at the top of the form.

* The “Delete Change” button deletes the information you have entered on this form for the selected change.  If you have entered information for this process or equipment change on any other form, that information will also be deleted.


Form Content Help:

* Costs should be provided in U.S. dollars.

* If you wish to provide more detail than requested in this form (e.g., you wish to itemize total capital costs), you may provide your information in a separate spreadsheet.  

* The EPA is particularly interested in costs of the following process changes or equipment changes/upgrades:
Installation of low/ultra-low NOX burners
Installation of air preheat for process heaters/boilers
Catalyst additives for SOX control from FCCU
Combustion promoters or catalyst additives for NOX control from FCCU
Amine treatment systems
Floating roofs, rim seals, and fittings seals on storage vessels
Installation of geodesic dome for external floating roof tank
Installation of guidepole sleeves/wipers or other tank fitting gaskets

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

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

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

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

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


INSTRUCTIONS:
Form Navigation Help:

* The first time you come to this screen, you will not see any entries in “Select Test or Monitoring Data to edit.”  Click the button to “Add Test/Monitoring Data” and enter all information related to that test or set of monitoring data, beginning with the Test/Monitoring Data ID, then click “Save And Close.”  Any time you return to this screen, you will see your test or set of monitoring data in the list at the top of the form.

* The “Delete Test/Monitoring Data” button deletes the information you have entered on this form for the Test/Monitoring Data ID, including the Test/Monitoring Data ID itself.


Form Content Help:

* Additional description of the specific types of test reports, CEMS data sets, and CMS data sets that EPA requests are located in a separate file on the Refinery ICR website.

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

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

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


# catalytic_cracking_unit_nox_controls

nox_control_desc:
37    Selective catalytic reduction (SCR)


nox_control_desc:
Staged fuel low NOX burner in CO boiler or other post-combustion device


nox_control_desc:
Control excess air in Regenerator and firebox temperature in boiler


nox_control_desc:
Monitoring excess O2 in stack in order to limit NOx formation


nox_control_desc:
Enhanced selective non-catalytic reduction (ESNCR)


nox_control_desc:
No preblended promoter, Regnerator Excess O2 minimization


nox_control_desc:
Low NOX combustion additives to replace Pt-based combustion additives


nox_control_desc:
Low NOX combustion additives to replace Pt-based combustion additives, 99 Other (Thermal DeNOx)


nox_control_desc:
98    Management practice or work practice to reduce NOX (Low NOx catalyst additive to meet 90/70 ppm NOx limit)


nox_control_desc:
minimize excess O2 and minimize CO promoter usage


nox_control_desc:
DMC maintains NOx during normal operation by limiting excess O2 between 0.8 and 1.0 %.


nox_control_desc:
Procedural management of regenerator stoichiometry to minimize nitrogen oxidation.


nox_control_desc:
Oxygen control and minimize usage of platinum-based combustion promoter (CP-5)


nox_control_desc:
Refinery operates under a 365-day NOx cap for FCCU.  Continuously monitor NOx concentration and stack flow.  Adjust FCCU operations to maintain compliance with NOx cap.


nox_control_desc:
NOX guidance document for operational decisions


nox_control_desc:
High-efficiency regenerator and  40    Low NOX combustion additives to replace Pt-based combustion additives


nox_control_desc:
Operations staff target low excess oxygen in the flue gas, which will reduce Nox emissions.


nox_control_desc:
Injection of ammonia upstream of flue gas cooler.


nox_control_desc:
External Flue-Induced Recirculation (FIR) - JLCC Burners


# catalytic_cracking_unit_pm_controls

pm_control_desc:
Ammonia conditioning of PM upstream of the ESP


pm_control_desc:
Add ammonia to ESP to increase control efficiency


pm_control_desc:
Venturi wet scrubber & tertiary cyclones


pm_control_desc:
Non-venturi jet ejector wet gas scrubber


pm_control_desc:
Venturi/wet scrubber and 15 Tertiary cyclone


# catalytic_cracking_unit_so2_controls

so2_control_desc:
FCCU Feed is hydrotreated and is supplemented with DeSOx additive. Unit is subject to Consent Decree limits of 50 ppm on a 365 day rolling average and 150 ppm on a 7-day rolling average


so2_control_desc:
DeSOx catalyst, meeting 50/25 ppmv SO2 limit


so2_control_desc:
DeSOx catalyst, meeting 50/125 ppmv SO2 limit


so2_control_desc:
DeSOx catalyst, meeting 20 lb/ton coke burn-off, but not 50/25 ppmv SO2 limit


so2_control_desc:
Hydrotreated Feed to reduce sulfur to FCCU


so2_control_desc:
DeSOx catalyst addition to meet permit concentration limit


so2_control_desc:
DeSOx catalyst, meeting 50/25 ppmv SO2 Limit (by 4/30/2011 per CD)


so2_control_desc:
DeSOx catalyst, meeting 50/150 ppmv SO2 limit


so2_control_desc:
DeSOx addition of 396 lb/day, regardless of coke burn off rate


# catalytic_reforming_units

depressurization_purge_control_desc:
To fuel gas system, then flare, then atmosphere

purge_process_desc:
Purge by sequential pressurizing/purging with nitrogen

rejuvenation_control_desc:
Management practice or work practice to reduce HCl or chlorine releases (specify) caustic spray injection


rejuvenation_control_desc:
Management practice or work practice to reduce HCl or chlorine releases (specify) packed bed wet air scrubber


rejuvenation_control_desc:
To common refinery Fuel Gas System, boiler or heater, then atmosphere.

reduction_activation_control_desc:
To common refinery Fuel Gas System, Boiler or heater, then atmosphere.


depressurization_purge_control_desc:
To 200# H2 heater, then fuel gas/flare gas recovery

coke_burn_off_control_desc:
Caustic injection to reduce HCl and combustion of VOC through purging to the heater box.

rejuvenation_control_desc:
Caustic injection to reduce HCl and combustion of VOC through purging to the heater box.


depressurization_purge_control_desc:
To 200# H2 header, then fuel gas/flare gas recovery

coke_burn_off_control_desc:
Caustic injection to reduce HCl and combustion of VOC through purging to the heater box


coke_burn_off_control_desc:
Caustic injection to reduce HCl and combustion of VOC through pruging to the heater box


rejuvenation_control_desc:
CCR - rejuvenation (chlorination/burn zone) gas exits through caustic scrubber then to atmosphere

reduction_activation_control_desc:
CCR - rejuvenation (chlorination/burn zone) gas exits through caustic scrubber then to atmosphere.


depressurization_purge_control_desc:
Purge cycle is entirely to fuel gas system, never to atmosphere

reduction_activation_control_desc:
No atmospheric venting during reduction cycle


depressurization_purge_control_desc:
Other (specify) catalyst is sent off site for regeneration

purge_process_desc:
Other (specify) Catalyst is sent offsite for regeneration

coke_burn_off_control_desc:
Other (specify) Catalyst is sent offsite for regeneration

rejuvenation_control_desc:
Other (specify) Catalyst is sent offsite for regeneration

reduction_activation_control_desc:
Other (specify)Catalyst is sent offsite for regeneration


depressurization_purge_control_desc:
To fuel gas system, then flare recovery system then atmosphere

rejuvenation_control_desc:
To fuel gas system, flare recovery system and then atmosphere.


rejuvenation_control_desc:
To process heater or boiler, then atmosphere


reduction_activation_control_desc:
To fuel gas system, then flare, then atmosphere


reduction_activation_control_desc:
Normally no venting, but pressure control lined up to flare


depressurization_purge_control_desc:
Other (specify) To flare, then atmosphere for higher pressure periods in the cycle; To process heater, then atmosphere for lower pressure periods in the cycle

coke_burn_off_control_desc:
Other (specify) - Caustic spray injection followed by Packed-bed wet scrubber

rejuvenation_control_desc:
Other (specify)  To flare, then atmosphere for higher pressure periods in the cycle; To process heater, then atmosphere for lower pressure periods in the cycle

reduction_activation_control_desc:
Other (specify) - To flare, then atmosphere for higher pressure periods in the cycle; To process heater, then atmosphere for lower pressure periods in the cycle


depressurization_purge_control_desc:
To fuel gas system via Flare gas recovery unit

purge_process_desc:
Vacuum evacuation to atmosphere followed by nitrogen purge to atmosphere

rejuvenation_control_desc:
vent disposition/control with caustic circulation through a quill and then to atmosphere

reduction_activation_control_desc:
H2 Reduction - To fuel gas system via Flare gas recovery unit


reduction_activation_control_desc:
H2- Reduction - To the atmosphere for 10-15 minutes then hydrogen is circulated in a closed system


depressurization_purge_control_desc:
To process heater or boiler, then atmosphere


reduction_activation_control_desc:
Other:  The HPCCR reduction gas is mixed with the feed to the first reactor.


reduction_activation_control_desc:
Purge remaining Oxygen to the atm with nitrogen.  Then pressure up and purge the system with hydrogen to the flare.


reduction_activation_control_desc:
Emissions vented to the furnance through lock hopper


depressurization_purge_control_desc:
Other (To fuel gas system, to low pressure fuel collection system, then atmosphere)

coke_burn_off_control_desc:
Chloride absorption system - PURASPEC 2250

rejuvenation_control_desc:
Chloride absorption system - PURASPEC 2250


coke_burn_off_control_desc:
Packed-bed wet scrubber    2 Caustic Spray Injection


depressurization_purge_control_desc:
- Sequential pressuring and purging of nitrogen and hydrogen

reduction_activation_control_desc:
No vents from the reduction or activation section


depressurization_purge_control_desc:
- Sequential pressuring and purging of nitrogen to flare


rejuvenation_control_desc:
Rejuvination gas routed to regenerator coke burn zone then coke burn-off cycle vent

reduction_activation_control_desc:
Reduction gas routed to process reactors


reduction_activation_control_desc:
To process heater or boiler, then atmosphere


depressurization_purge_control_desc:
Sequence in order: to flare gas recovery/fuel gas system, then to process heater


coke_burn_off_control_desc:
Management practice or work practice to reduce HCl or chlorine releases (caustic injection, HCl measurement in vent)

rejuvenation_control_desc:
Management practice or work practice to reduce HCl or chlorine releases (caustic injection, HCl measurement in vent)

reduction_activation_control_desc:
Management practice or work practice to reduce HCl or chlorine releases (caustic injection, HCl measurement in vent)


rejuvenation_control_desc:
Management practice or work practice to reduce HCl or chlorine releases (caustic scrub/injection)


coke_burn_off_control_desc:
caustic water injection at outlet of product separator to keep pH between 6 an 7

rejuvenation_control_desc:
caustic water injection at outlet of product separator to keep pH between 6 an 7


rejuvenation_control_desc:
Other (Vent gas scrubber then atmosphere)


depressurization_purge_control_desc:
Reactor is purged with hydrogen to the process, then blocked in and depressured to flare.  Reactor is then purged to flare with nitrogen.

coke_burn_off_control_desc:
Vent stream passes through a chloride absorber (Chlorocel 901) then to atmosphere.

rejuvenation_control_desc:
Vent stream passes through a chloride absorber (Chlorcel 901) and then to atmosphere.

reduction_activation_control_desc:
Vent stream passes through a chloride absorber (Chlorcel 901) and then to atmosphere.


coke_burn_off_control_desc:
Caustic/water solution injected to neutralize acids and vent chloride concentration monitored throughout the process

rejuvenation_control_desc:
Caustic/water solution injected to neutralize acids and vent chloride concentration monitored throughout the process

reduction_activation_control_desc:
No vent -- reduction is conducted under a H2 atmosphere


purge_process_desc:
Purge through the chlorsorb with the flue gas


coke_burn_off_control_desc:
Caustic scrub circulating gas; vent to atmosphere

rejuvenation_control_desc:
Caustic scrub circulating gas; vent to atmosphere


depressurization_purge_control_desc:
to flare then purge with nitrogen to flare

rejuvenation_control_desc:
chloride gas stream scrubbed with circulating caustic system and vented to atmosphere

reduction_activation_control_desc:
circulating closed loop hydrogen stream for metals reduction


reduction_activation_control_desc:
Performed in the rxtr, no release out of system


coke_burn_off_control_desc:
Management practice or work practice to reduce HCl or chlorine releases (specify) Chloride Trap

reduction_activation_control_desc:
Other (specify) - To cloride trap, then atmosphere


rejuvenation_control_desc:
Other (Continuous regeneration does not have rejuvenation cycle. N2 purge on lift engager goes to heater.)

reduction_activation_control_desc:
Other (Continuous regeneration does not have reduction cycle. H2 purge on lift engager goes to heater.)


depressurization_purge_control_desc:
Purge Gas is returned to the unit recycle gas compressor


coke_burn_off_control_desc:
Closed-loop recirculation using process vessel as caustic scrubber.  Scrubbed stream is only vented to atmosphere intermittently to relieve pressure (about 6 times per day, about 15 minutes) each.

rejuvenation_control_desc:
Closed-loop recirculation using process vessel as caustic scrubber.  Scrubbed stream is only vented to atmosphere intermittently to relieve pressure (about 6 times per day, about 15 minutes) each.

reduction_activation_control_desc:
Closed-loop recirculation using process vessel as caustic scrubber.  Scrubbed stream is only vented to atmosphere intermittently to relieve pressure (about 6 times per day, about 15 minutes) each.


coke_burn_off_control_desc:
Sodium bicarbonate solution injected into reactor effluent coolers and separated before off gas is vented.

reduction_activation_control_desc:
New catalyst is reduced with hydrogen and then vented to flare.


depressurization_purge_control_desc:
Material from Depressuring and Purging of Lock Hoppers is routed to the fuel system (vacuum system).  If the vacuum system is down, the material is sent to FGR

purge_process_desc:
Purging of Lock Hopper #1 and #2 is completed by sweeping hoppers with nitrogen.    This step does not involve pressuring/purging with nitrogen.

rejuvenation_control_desc:
Vent from CCR is directed to the Vent Gas Wash Scrubber where a caustic wash is used to remove chrlorides from the vent before releasing to the atmosphere.

reduction_activation_control_desc:
There is no vent associated with reduction step with CCR design


coke_burn_off_control_desc:
During these steps all vent streams from the regeneration system passes thru a chloride absorbent bed prior to being vented to the atmosphere.

rejuvenation_control_desc:
During these steps all vent streams from the regeneration system passes thru a chloride absorbent bed prior to being vented to the atmosphere.

reduction_activation_control_desc:
Upon completion of the nitrogen purge step, hydrogen is routed thru the rx and vented to the flare for completion of the reduction step.


coke_burn_off_control_desc:
Use dedicated vessel for Chloride treatment of off gas during rejuvenation (BASF CL-760)

rejuvenation_control_desc:
Use dedicated vessel for Chloride treatment of off gas during rejuvenation (BASF CL-760)


depressurization_purge_control_desc:
Recycled gas goes through a scrubber then to the atmosphere


depressurization_purge_control_desc:
To fuel gas system, then atmosphere 
3 To flare, then atmosphere

purge_process_desc:
- Pull vacuum with steam ejector to atmosphere and break vacuum with nitrogen


depressurization_purge_control_desc:
To fuel gas system, then atmosphere
3 To flare, then atmosphere


coke_burn_off_control_desc:
Caustic spray injection and Tray tower wet scrubber

rejuvenation_control_desc:
Pressure control is set to atmosphere then if needed at a higher pressure to flare


purge_process_desc:
Evacuate to atmosphere with steam eductor and break vacuum with nitrogen

reduction_activation_control_desc:
Procedure does not require venting during reduction step


# cooling_water_system_process_units

cooling_water_system_id:
Unit 90 Cooling Water system Unit (90-CT-9000)


cooling_water_system_id:
Unit 90 Cooling Water system Unit (90-CT-9002)


cooling_water_system_id:
Unit 90 Cooling Water system Unit (90-CT-9004)


cooling_water_system_id:
One Ten-Cell Induced Draft Cooling Tower


cooling_water_system_id:
2-97 (Cooling Water Tower Induced Draft)


cooling_water_system_id:
Agrekko Temporary Cooling Tower in Sulfur


cooling_water_system_id:
EUI 2C: HF Alkylation Unit Cooling Tower


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at 7PS


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at 7VPS


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at ABW


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at BIBFBW


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at CLEU


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at CNHBW


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at DSU-1


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at DSU-2


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at FCBW


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at FGBW


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at H2BW


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at HRU-1 (HPU)


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at ISOM-2


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at PFBW


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at POLYSP


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at POLYT


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at PRBW


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at USBW


cooling_water_system_id:
COCTW0002 - Cooling Tower 2A (North-Pritchart)


cooling_water_system_id:
COCTWFLUR - Cooling Tower 2B (South-FLUR)


process_unit_id:
Sour Water Stripping Unit No. 1 - Sulphur Unit


# cooling_water_systems

cooling_water_system_desc:
Forced draft cooling tower (fans for inlet air)


chemical_addition_location:
Bleach is added at the Marley Cooling Tower that feeds the Lube Oil Cooling System.


chemical_addition_location:
Bleach is added at the Marley Cooling Tower that feeds the Naphtha Cooling Water System.


cooling_water_system_desc:
Induced draft cooling tower (fans at outlet)


cooling_water_system_id:
Unit 90 Cooling Water system Unit (90-CT-9000)


cooling_water_system_id:
Unit 90 Cooling Water system Unit (90-CT-9002)


cooling_water_system_id:
Unit 90 Cooling Water system Unit (90-CT-9004)


disinfection_method_desc:
Gutleraldehyde/Isothiazolin, zinc phosphate, tolytriazole, sulfuric acid


cooling_water_system_id:
One Ten-Cell Induced Draft Cooling Tower

disinfection_method_desc:
oxydizing biocides containing 7.1 lb/day sodium hypochlorite


chemical_addition_location:
Mixes with an off-shoot of the cooling water supply line and is added at the bottom of the cooling tower.


disinfection_method_desc:
Other (specify) - Biosurfactant and Amine Biocide


disinfection_method_desc:
Sodium Hypochlorite, 99 Other - Gluteraldehyde


cooling_water_system_id:
Distilling Unit Temporary Cooling Towers (6)


disinfection_method_desc:
Disinfectant is residual chlorine in makeup water from clarifiers


cooling_water_system_id:
2-97 (Cooling Water Tower Induced Draft)


cooling_water_system_desc:
Once through and induced draft, fans at the outlet.


disinfection_method_desc:
Other (Sodium hypochlorite with ~1.6% v/v Bromine)


disinfection_method_desc:
Other (Sodium hypochlorite with ~15.8% v/v Bromine)


chemical_addition_location:
Upstream of Iron Filters and Directly into Basin.


chemical_addition_location:
Upstream of Iron Filters and Directly in Basin.


cooling_water_system_id:
Agrekko Temporary Cooling Tower in Sulfur


disinfection_method_desc:
Sodium Hypochlorite, H2SO4, Betz DN2761, PY5200, BD1501, NX1100


disinfection_method_desc:
Sodium hypochlorite, H2SO4, Betz DN2761, PY5200, BD1501, NX1100


disinfection_method_desc:
Other (specify) A: Nalco TB960, Chlorine and sodium bromide biocide  B:Nalco 3DT222 Corrosion Inhbitor


cooling_water_system_id:
EUI 2C: HF Alkylation Unit Cooling Tower


cooling_water_system_desc:
Closed Loop Temperate Water/Glycol Cooling System


disinfection_method_desc:
25 gpd of Sodium Hypochlroite, 0.9 gpd of Sodium Bromide, 0.8 gpd of BMP & Isothiazolone, and 0.5 gpd of Biodispersant


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at 7PS

disinfection_method_desc:
19.26 gpd of Sodium Hypochlorite and 0.64 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at 7VPS

disinfection_method_desc:
12.84 gpd of Sodium Hypochlorite and 0.43 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at ABW

disinfection_method_desc:
17.65 gpd of Sodium Hypochlorite and 0.59 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at BIBFBW

disinfection_method_desc:
2.88 gpd of Sodium Hypochlorite and 0.1 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at CLEU


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at CNHBW

disinfection_method_desc:
1.61 gpd of Sodium Hypochlorite and 0.05 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at DSU-1

disinfection_method_desc:
0.64 gpd of Sodium Hypochlorite and 0.02 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at DSU-2

disinfection_method_desc:
3.21 gpd of Sodium Hypochlorite and 0.11 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at FCBW

disinfection_method_desc:
46.54 gpd of Sodium Hypochlorite and 1.55 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at FGBW

disinfection_method_desc:
7.06 gpd of Sodium Hypochlorite and 0.24 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at H2BW

disinfection_method_desc:
0.126 gpd of Sodium Hypochlorite and 0.004 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at HRU-1 (HPU)

disinfection_method_desc:
1.12 gpd of Sodium Hypochlorite and 0.04 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at ISOM-2

disinfection_method_desc:
1.29 gpd of Sodium Hypochlorite and 0.04 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at PFBW

disinfection_method_desc:
3.69 gpd of Sodium Hypochlorite and 0.12 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at POLYSP


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at POLYT

disinfection_method_desc:
0.8 gpd of Sodium Hypochlorite and 0.03 gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at PRBW

disinfection_method_desc:
1.29 gpd of Sodium Hypochlorite and 0.04gpd of Catonic Surfactant-Based Molluskicide


cooling_water_system_id:
SWPS Once Through Cooling Water (CW) System at USBW

disinfection_method_desc:
11.24 gpd of Sodium Hypochlorite and 0.37 gpd of Catonic Surfactant-Based Molluskicide


chemical_addition_location:
Fed to the Basin, prior to recirculation pumps


disinfection_method_desc:
Bleach, Y7BH972, Nalco - 184, Y9BH1246, CI2OUT 110


disinfection_method_desc:
Bleach, Sulfuric Acid, Y9BH1246, BPC68095, Y7BH972


chemical_addition_location:
chemicals injected near CT-1 North Basin


cooling_water_system_id:
COCTW0002 - Cooling Tower 2A (North-Pritchart)


cooling_water_system_id:
COCTWFLUR - Cooling Tower 2B (South-FLUR)


disinfection_method_desc:
Chlorine from make-up water or slug feeding biocide (if needed)


disinfection_method_desc:
Other (2 Sodium hypochlorite, Corrosion Inhibitor/Dispersant: PO4/HPS1, Corrosion Inhibitor: PO4, Corrosion Inhibitor: HRA)


disinfection_method_desc:
Other (2 Sodium hypochlorite, Dispersant: HPS1, Corrosion Inhibitor: PO4, Corrosion Inhibitor: HRA, pH Control Sulfuric Acid )


disinfection_method_desc:
Other (2 Sodium hypochlorite, All-In-One Product: HPS1, AEC, HRA, PO4)


disinfection_method_desc:
Other (specify) 3 Calcium hypochlorite, Corrosion Inhibitor /Dispersant: PO4/HPS1, Corrosion Inhibitor: PO4, Corrosion Inhibitor: HRA


disinfection_method_desc:
sodium hypochlorite (100 gpd), Sodium Bromide (12.9 gpd), DemandTrac 985 (35 gpd), Baker BPC 68970 (100) gpq


disinfection_method_desc:
sodium hypochlorite (35 gpd), DemandTrac 995 (6 gpd), Baker BPC-68970 (50 gpq)


disinfection_method_desc:
Chlorine from gas cyclinders (5 lb/day) and DMT 485 (10 lb/day)

chemical_addition_location:
Suction side of cooling tower supply pumps


disinfection_method_desc:
Chlorine from gas cylinders (5 lb/day) and DMT 485 (20 lb/day)


chemical_addition_location:
North side of cooling tower.  Also, add chlorine tablets.


# cost_data_apcd

apcd_desc:
LoNox boiler replaced calciner waste heat recovery boiler


apcd_desc:
REPLACED Old DIESEL WITH NATURAL GAS FIRED ENGINE with NSCR


apcd_desc:
Retrofitted with Ultra Low Nox burners and addedFlue gas recirculation equipment


apcd_desc:
Retrofitted to Ultra Low Nox burners and installed Flue Gas recirculation equipment


apcd_desc:
Implemented several projects to lower H2S concentration of the Refinery Low Pressure Fuel Gas System to ensure compliance with NSPS J.


apcd_desc:
Fixed Cover installed on API Oil-Water Separator. Vapors routed to routed to an existing thermal oxidizer


apcd_desc:
Venturi Wet Scrubber and wet scrubber/flue gas desulfurization


apcd_desc:
SRU including TGTUs - operating costs listed are for SRU2, TGTU1 and TGTU2


# cost_data_apcd_other_costs

other_cost_desc:
payroll benefits for additional employees due to APCD (4 console operators, 3 reg operators)


# cost_data_process_changes

process_change_desc_details:
Low NOx burner installation with NOx CEM


process_change_desc_details:
Low NOx burner installation with NOx CEMs


process_change_desc_details:
Hard pipe remediation groundwater to aeration basin


process_change_desc_details:
air to fuel ratio controls along with flue gas recirculation for existing packaged boiler and NOX analyzer

emission_reduction_achieved:
from 0.173 lb/mmbtu of NOX to 0.04 lb/mmbtu


process_change_desc:
piped natural gas to two low nox burner heaters for better NOX control

emission_reduction_achieved:
small quantifiable emission reduction of NOX due to cleaner fuel


process_change_desc_details:
installed new low nox burners and air to fuel ratio controls

emission_reduction_achieved:
from .098 lb/mmbtu NOX to 0.03 lb/mmbtu of NOX


process_change_desc_details:
installed new low nox burner and air to fuel ratio controls


process_change_desc_details:
Three pressure/vacuum vents were installed on junction box vent pipes as part of a BACT determination to prevent the flow of organic vapors from these vents during normal operations.


process_change_desc_details:
LSN1G low NOx < 30 ppm gas. Added 1 burner. Max burner gas input 50,400,000 Btu/hr. Fuel option: natural gas.


process_change_desc:
Enhanced External Floating Roof Emission Control

process_change_desc_details:
Added Geodesic Dome to an External Floating Roof Tank

emission_reduction_achieved:
1.5 tons of VOC reduced per year based upon the results from TANKS v 4.09d.


process_change_desc_details:
Complete replacement of process heater since ULNB could not be installed in existing heater.  New heater fires refinery fuel gas.


process_change_desc_details:
Complete replacement of Boilers 6 and 7.  Two new  250 MLB/Hr (349.6 MMBtu/hr) Boilers were installed in place of two 1940 vintage Boilers that could not be retrofitted with low Nox burners.  New boilers fire refinery fuel gas.


process_change_desc_details:
24 ULNB were installed in the three heater boxes of the platformer heater.  These fire refinery fuel gas.


process_change_desc:
Guidepole sleeves and/or deck leg socks (boots) on tanks

process_change_desc_details:
Guidepole sleeves and/or deck leg socks (boots) were added to tanks T002, T003, T004, and T005


process_change_desc:
Smart flow transmitters and piping modifications for Greenhouse Gas Reporting

process_change_desc_details:
Smart flow transmitters to enable temperature and pressure correction for flow meters were installed. Also for some units piping modifications were required.  Units included 42, 41, 744, 745, 742, 743, 746, 101, 739, 738, 737, 735, 736, and 741.


process_change_desc_details:
32 Burners w/combined firing rate of 11.8 (avg)/21.3 (max) MMBtu/hr, using refinery fuel gas


process_change_desc_details:
42 Burners w/combined firing rate of 32.3 (avg)/44.0 (max) MMBtu/hr, using refinery fuel gas


process_change_desc_details:
30 Burners w/combined firing rate of 150.6 (avg)/182.6 (max) MMBtu/hr, using natural gas, PSA off gas, cryogenic vapor recovery offgas


process_change_desc_details:
External floating roof with mechanical shoe primary seal and rim-mounted secondary seal. Slotted guidepole with wiper ad inner float.  Roof legs equipped with boots.


emission_reduction_achieved:
3400 Tons/year SO2 reduction achieved with shutdown of Calciner 3400 Tons/year SO2 based on average previous yrs. normal operation


process_change_desc:
INSTALLED GC TO REPLACE LEAD ACETATE TAPE MONITOR


process_change_desc_details:
LOADERS REPLACED WITH NEWER, CLEANER ENGINE MODELS


process_change_desc:
REPLACED OLDER VEHICLES WITH NEWER CLEANER ENGINES

process_change_desc_details:
FACILITY VEICLES AND FIRETRUCK FLEET UPDATED WITH NEWER, CLEANER ENGINE MODELS


process_change_desc_details:
New O2 analyzer to improve the FGRU uptime to reduce flaring emissions


process_change_desc_details:
Replacement of H-5001 furnace with H-5002 equipped with Ultra Low-NOx burners


process_change_desc_details:
Replacement of H-57, H-58, H-59 with H-60 equipped with Ultra Low-NOx burners


process_change_desc_details:
Replaced flare tip to improve combustion efficiency and reduce flare emissions


process_change_desc_details:
Replacement of B-6 and B-7 with B-21 and B-22 equipped with Ultra Low-NOx burners


process_change_desc_details:
Replaced West Plant Oil Recovery Unit sump to reduce fugitive VOC emissions


process_change_desc_details:
Replaced cogeneration facility with B-9 and B-10 equipped with Ultra Low-NOx burners


process_change_desc_details:
Replaced slotted guidepoles with solid guidepoles, added sleeves, or pole floats to reduce VOC emissions


process_change_desc_details:
Used Low-NOx CO promoter in FCC to reduce NOx emissions


process_change_desc_details:
Hard piped C4 and IC4 storage sphere PRVs to flare to reduce VOC emissions


# delayed_coking_unit_feed_information

feed_source_desc:
Recovered materials - Recovered oil (e.g., slop oil)


feed_source_desc:
Recovered materials - Sludges from crude oil storage tanks


feed_source_desc:
Recovered materials - Sludges from other storage tanks


feed_source_desc:
Recovered materials - Biosolids from WWTS


feed_source_desc:
Recovered materials - Other sludges from WWTS


# delayed_coking_units

water_quenching_cycle_desc:
Use recycled cutting water with “tap” water make-up

blowdown_system_condensed_water_disposition_desc:
Other (specify) (Used as desalter makeup water)

blowdown_system_condensed_uncondensed_vapor_disposition_desc:
Uncondensed vapors are sent to flare gas recovery system

quench_water_disposition_desc:
- Recycled to unit and used as quench water 
5 - Used as coke cutting water

cutting_water_source_desc:
Use recycled cutting water with “tap” water make-up

cutting_water_handling_desc:
Mechanical filtration (e.g., centrifugal, filter press) to open storage tank or pond


coke_desc:
Sponge coke, anode grade or Sponge coke, fuel grade


water_quenching_cycle_desc:
Use recycled cutting water with process or blowdown water make-up

cutting_water_source_desc:
Use recycled cutting water with process or blowdown water make-up


water_quenching_cycle_desc:
Use recycled cutting water with "tap" water make-up / Use recycled cutting water with process or blowdown water make-up

quench_water_disposition_desc:
Recycled to unit and used as quench water / Used as coke cutting water


cutting_water_handling_desc:
Uncovered gravity settling pond/covered tank


blowdown_system_condensed_uncondensed_vapor_disposition_desc:
Not applicable; uncondensed vapors are always sent to DCU fractionator

quench_water_disposition_desc:
Recycled to unit and used as quench water


water_quenching_cycle_desc:
Use recycled cutting water with stripped sour water makeup.

cutting_water_source_desc:
Recycle cutting water with stripped sour water makeup.


blowdown_system_condensed_uncondensed_vapor_disposition_desc:
Sent through Gas Handling system and eventually will make it to Amine System


blowdown_system_condensed_water_disposition_desc:
Recycled to unit and used as quench water

blowdown_system_condensed_uncondensed_vapor_disposition_desc:
Uncondensed vapors are sent to flare header system to general facility flare

cutting_water_handling_desc:
Other (Uncovered gravity settling basin / covered tank)


water_quenching_cycle_desc:
Use treated water from wastewater treatment system

blowdown_system_condensed_water_disposition_desc:
Other (specify) Steam to blowdown used as quench and drill water for Fuels Coker

cutting_water_source_desc:
Other (specify) Use recycled cutting water with waste water treatment make-up water


coke_desc:
Shot coke, fuel grade &  Sponge coke, anode grade


quench_water_disposition_desc:
Recycled to Unit and used as Quench Water; Used as Coke Cutting Water


coke_desc:
Sponge Coke, Fuel Grade AND Shot Coke, Fuel Grade

blowdown_system_condensed_uncondensed_vapor_disposition_desc:
Combination - Vapors direct to amine treatment/fuel gas system, and some to flare gas recovery system

quench_water_disposition_desc:
Combination of all: Sent to WWTS, Recycled to Unit and used as Quench Water, Used as Coker Cutting Water


coke_desc:
ponge Coke, Fuel Grade AND Shot Coke, Fuel Grade


water_quenching_cycle_desc:
Recycled to unit and used as quench water AND used as coke cutting water.

quench_water_disposition_desc:
Recycled to unit and used as quench water AND Used as coke cutting water


quench_water_disposition_desc:
Recycled to unit and used as quench water, and used as coke cutting water

cutting_water_handling_desc:
Uncovered maze settling system to uncovered tank


blowdown_system_condensed_water_disposition_desc:
Recycled to unit and used as quench water
5 Used as coke cutting water

quench_water_disposition_desc:
Recycled to unit and used as quench water
5 Used as coke cutting water

cutting_water_source_desc:
Use treated water from sour water stripper


coke_desc:
Sponge Coke, Anode Grade; Sponge Coke, Fuel Grade


coke_desc:
Sponge Coke, Fuel Grade; Shot coke, Fuel Grade


water_quenching_cycle_desc:
Fire Water - Combination of well water and treated waste water - recycled

cutting_water_source_desc:
Fire Water - Combination of well water and treated waste water - recycled


quench_water_disposition_desc:
Recycled to unite and used as quench water AND used as coke cutting water


blowdown_system_condensed_uncondensed_vapor_disposition_desc:
Goes through amine scrubber and to process flare


water_quenching_cycle_desc:
Use recycled cutting water with "tap" and process or blowdown water make-up.

quench_water_disposition_desc:
Recycled to unit and used as quench water and used as coke cutting water.

cutting_water_source_desc:
Use recycled cutting water with "tap" and process or blowdown water make-up.


blowdown_system_condensed_uncondensed_vapor_disposition_desc:
Uncondensed vapors are sent to flare gas header system to general facility flare

quench_water_disposition_desc:
Recycled to unit and used as quench water AND used as coke cutting water


quench_water_disposition_desc:
Recycled to the unit & used as quench water & used as cutting water

cutting_water_handling_desc:
water collection basin to covered quench water tank


blowdown_system_condensed_water_disposition_desc:
1/3 of condensed water is "Sent to sour water stripper" remaining 2/3 is "recycled to unit to use as quench water"

quench_water_disposition_desc:
Quench water is both - "Recycled to unit and used as quench water" and is also "Used as coke cutting water".


water_quenching_cycle_desc:
Use recycled cutting water with “tap” water make-up and 5 Use treated water from sour water stripper

quench_water_disposition_desc:
Recycled to unit and used as quench water
5 Used as coke cutting water
6 Used as general process water
99 Other (steam/air decoking)

cutting_water_source_desc:
Use recycled cutting water with “tap” water make-up
5 Use treated water from sour water stripper


# emissions_source_test_apcd_type_ids

apcd_desc:
Catalytic Converter on Refinery wide Gas Engine Compressor.


test_id:
Source Test - Boiler 10 - NH3 - 12_10_2010


test_id:
Source Test - Boiler 10 - PM NH3 - 10_30_2009


test_id:
Source Test - Boiler 10 - PM NOx SO2 CO ROG - 12_19_2007


test_id:
Source Test - Coke Drum During Venting - PM H2S VOC - 03_04_2010


test_id:
Source Test - Coker Steam Vent - PM - 09_08_2008


test_id:
Source Test - H2 Plant Vents - VOC - 10_27_2010


test_id:
Source Test - Acid Plant Scrubber - SOx H2S - 06_29_2009


test_id:
Source Test - Boiler 7 SCR - NH3 - 09_08_2010


test_id:
Source Test - Cogen and Cogen SCR - CO and NH3 - 08_16_2010


apcd_desc:
Wetting storage piles and other dust control measures


apcd_desc:
Diesel Particulate Filter and Low Sulfur Diesel Required for Operation


apcd_desc:
Diesel Particulate Filter and Low Sulfur Diesel Fuel Required in Permit


apcd_desc:
HRU stack is jointly shared with FCC unit.  HRUs are steam boilers (fired or waste heat)


apcd_desc:
Ultra low Nox burners with recirculation


apcd_desc:
Low NOX combustion additives to replace Pt-based combustion additives


apcd_desc:
Incinerator is the control equipment, CEM data is for the incinerator


apcd_desc:
Multi-stage separator (Cyclones combined with baghouses)


apcd_desc:
Multi-stage separator (Cyclones combined with baghouse)


apcd_desc:
Multi-stage separator (Cyclones combined with baghouses


apcd_desc:
The incinerator is the control equipment for the SRU/SCOT unit, stack test is for the incinerator


apcd_desc:
Multi-stage separator (Cyclones combined with bag filters)


apcd_desc:
The vapor recovery unit is a two carbon bed system. Only one bed is operated at any given time, while the other bed is regenerated


apcd_desc:
Vapor Combustor, the VCU will operate anytime the VRU is down for maintenance


apcd_desc:
Vapor recovery unit is a two carbon bed system, while one bed is operating the other is regenerating


apcd_desc:
Third Stage Separator, with Fourth Stage Separator or Pall Filter


test_id:
2004 PPBWTO 9150 & 9151  CO NOx SO2 NMNEHC DE% HAPs (T015-Total) Hexane PM10 Stack Test


test_id:
2010 LCN CRUB NOx CO SO2 TNMHC Stack Test


test_id:
East Side Fuel Gas Line - Sulfur Speciation


test_id:
East Side Mix Drum (Reformer 2, Isocracker, Tank 108, Tank 109, ADHT, H2 Plant) - H2S CMS


test_id:
East Side Mix Drum, TIU Mix Drum, Coker 3, Vac 1 - Sulfur Speciation


test_id:
FCC CO Boiler - Nonsulfuric Acid Particulate Emissions


test_id:
FCC CO Boiler - Nonsulfuric Acid Particulate, PM, SO2, NOx, CO, Ni


test_id:
FCCU - Ammonia, Nonsulfuric, PM, Nickel, SO2, Nox, CO


test_id:
FCCU Coker Burnoff Rate, Nickel Emissions, Nonsulfuric Acid Particulate Emissions


test_id:
TIU Mix Drum (Crude 1, Reformer 1, Coker 2, FCC, Crude 2, Naphtha Hydrotreater, Vac 1, East BGOT) - H2S CMS


test_id:
VE, Net Heating Value, Flare Tip Exit Velocity


apcd_desc:
Reactor Feed Furnace for Diesel Hydrotreater Unit with Next Generation Low NOx Burners


apcd_desc:
Process Heater for Catalytic Hydrotreating Unit with Next Generation Low NOx Burners


apcd_desc:
Refinery Fuel Gas to; Vacuum Unit II Htr(B001), ISO Stabilizer/Splitter Htrs (B002), ISO I & II Htrs (B003), Crude II Htr (B004), Reformate Splitter Reboiler (B005), U/F PRE 1,2,& 3 Htr (B006), Reformer Regenerator Htr (B007), HDS Htr (B008)


apcd_desc:
HDS Furnace with "Next Generation" Low NOx burner (ULNB with internal gas recirculation)


apcd_desc:
Crude II Heater with Ultra Low Nox Burners


apcd_desc:
CE Boiler with  (External) flue gas recirculation


apcd_desc:
Refinery Fuel Gas to; Hot Belt Oil Heater-Arom (B022), Isomerization Heater  (B024), Diesel Hydrotreater Unit (B029)


apcd_desc:
Refinery Fuel Gas to;Riley Boiler (B009), FCC Furnace (B016), CE Boiler (B026), Coker Furnace (B027), Process Heater for Catalytic Gasoline Hydrotreating Unit (B028)


apcd_desc:
NE Boiler with  (External) flue gas recirculation


apcd_desc:
SRU including Claus 1 unit, Claus 2 unit with TGTU (P040) and Butane-Butylene Treater (P041)


apcd_desc:
Refinery Fuel Gas; Vac Unit II Htr(B001), ISO Stabilizer/Splitter Htrs (B002), ISO I & II Htrs (B003), Crude II Htr (B004), Reformate Splitter Reboiler (B005), U/F PRE 1,2,& 3 Htr (B006), Reformer Regenerator Htr (B007), HDS Htr (B008)


apcd_desc:
FCC with Stage Fuel Low NOx Burner in CO boiler pre 2010 TAR. Post TAR CO Boiler removed.


apcd_desc:
FCC with DeSOx catalyst, meeting 50/25 ppmv SO2 limit


test_id:
4 FCCU Wet Scrubber Stack Non-Sulfuric Acid PM Compliance Test 11-30-10 & 12-3-10


test_id:
4 FCCU Wet Scrubber Stack PM, NOx, CO & SO2 Compliance Test 3-17&18-09


test_id:
5 FCCU NSPS Subpart J and Refinery MACT UUU PM Compliance Test 8-15-07


test_id:
5 FCCU Wet Scrubber Non-Sulfuric Acid PM Compliance Test 12-1&2-10


apcd_desc:
flue gas recirculation with air to fuel ratio controls


apcd_desc:
low nox burner and air to fuel ratio controls


apcd_desc:
air to fuel ratio controls - no low nox burner


test_id:
2005 - Emissions Test - Marine Dock Flare


test_id:
2006 - Emission Test - FCCU Wet Gas Scrubber


test_id:
2006 - Emission Test - Sulfur Recovery Tail Gas Thermal Oxidizer


test_id:
2007 - Emissions Test - FCCU Wet Gas Scrubber


test_id:
2011 - Emissions Test - SRU Incinerator Stack


test_id:
2011 - Emissions Test - SRU5 Incinerator Stack


test_id:
MACT UU3 MACT UUU Reactor Performance Test


test_id:
UU3 MACT II Skid Performance Test (2009)


apcd_desc:
Low NOX burners and flue gas recirculation


test_id:
Attachment 3-21. CMS_FLARE04 Heating Value


test_id:
Attachment 3-24. CMS_FLARE11 Heating Value


test_id:
Attachment 3-27. CMS_FLARE14 Heating Value


test_id:
Attachment 3-29. CMS_Base Refinery Blend Gas (Utilities Drums D291/D292(A-812)) H2S


test_id:
Attachment 3-30. CMS_Base Refinery Blend Gas (Utilities Drums D291/D292(A-812)) Heating Value


test_id:
Attachment 3-31. CMS_Hydrofining Unit 9 Blend Gas (HU9 Drum D301(A-802)) H2S


test_id:
Attachment 3-32. CMS_Hydrofining Unit 9 Blend Gas (HU9 Drum D301(A-802)) Heating Value


test_id:
Attachment 3-33. CMS_Flexicoker By-product Called Low Btu Gas (LBG (A-605)) H2S


test_id:
Attachment 3-34. CMS_Flexicoker By-product Called Low Btu Gas (LBG (A-605)) Heating Value


test_id:
Attachment 3-35. CMS_Flexicoker Blend Gas (FXK Drum D315 (A-625)) H2S


test_id:
Attachment 3-36. CMS_High Btu Gas (HSK Drum D853(A-951)) H2S


test_id:
Attachment 3-37. CMS_High Btu Gas (HSK Drum D853(A-951)) Heating Value


test_id:
Attachment 3-38. CMS_Delayed Coking Unit Blend Gas (DCU Drum D616 (A-903)) H2S


test_id:
Attachment 3-39. CMS_Delayed Coking Unit Blend Gas (DCU Drum D616 (A-903)) Heating Value


test_id:
Attachment 3-40. CMS_Pipestill North Blend Gas (PS-7 Drum D714) Heating Value


test_id:
Attachment 3-41. CMS_Hydrofining Unit 10 Blend Gas  H2S


apcd_desc:
chloride traps - fixed bed gas-solid adsorption system


test_id:
Ambient Air Monitoring Reports January 2000 through November 2006


apcd_desc:
Hydrogen Chloride and Chlorine Tests; conditions Carbon Burn and Oxidation Phase


apcd_desc:
Low NOx combustion additives to replace Pt-based combustion additive, Other low NOx catalyst additives


apcd_desc:
DeSOx catalyst, meeting 50/25 ppmv SO2 limit, Low sulfur feed (0.3 wt% or less)


apcd_desc:
CO Boiler, complete coke oxidation, combustion management, feed pretreatment


apcd_desc:
FB10 has flue gas recirculation and low NOx burners


# emissions_source_test_unit_ids

unit_id:
Fuel Gas Treatment Unit (No. 2 Amine Unit)


test_id:
No 10: H2 Plant Methanol Scrubbers 9/15/2009


test_id:
Sulfur Loading- 28F-11 Sulfur Loading Rack Incinerator


test_id:
Sulfur Loading- 28F11 Sulfur Pit Incinerator
 (Sulfur Pit & Loading Rack Vapors w/ Carbon Control)


test_id:
U29- SRU 29F-4 Tail Gas Unit Incinerator #1


test_id:
U29- SRU 29F-4 Tail Gas Unit Incinerator #2


test_id:
Source Test - Boiler 10 - NH3 - 12_10_2010


test_id:
Source Test - Boiler 10 - PM NH3 - 10_30_2009


test_id:
Source Test - Boiler 10 - PM NOx SO2 CO ROG - 12_19_2007


test_id:
Source Test - Coke Drum During Venting - PM H2S VOC - 03_04_2010


test_id:
Source Test - Coker Steam Vent - PM - 09_08_2008


test_id:
Source Test - H2 Plant Vents - VOC - 10_27_2010


test_id:
Source Test - Acid Plant Scrubber - SOx H2S - 06_29_2009


test_id:
Source Test - Boiler 7 SCR - NH3 - 09_08_2010


test_id:
Source Test - Cogen and Cogen SCR - CO and NH3 - 08_16_2010


test_id:
Source Test - Sulfur Plant Acid Stack - CO PM H2SO4 - 04_16_08


test_id:
FCCU-1 NOx SO2 CO VOC Source Test_03-19-2009


test_id:
HTR-ALKY-HM2 NOx CO Source Test_06-17-2008


test_id:
HTR-DU1-F301 NOx, PM, CO, VOC Source Test_03-30-2006


test_id:
North Property Flare H2S Source Test_2007-12-13


test_id:
WWTP Benzene Biodegradation Rate_June 2005


test_id:
AQS 09653-11-001 & Associated Appendices - Boiler 1


test_id:
AQS 09653-11-001 & Associated Appendices - Boiler 2


test_id:
AQS 09653-11-001 & Associated Appendices - Boiler 4


test_id:
AQS 09653-11-001 & Associated Appendices - Crude


test_id:
AQS 09653-11-001 & Associated Appendices - Platform


test_id:
East Side Fuel Gas Line - Sulfur Speciation


test_id:
East Side Mix Drum (Reformer 2, Isocracker, Tank 108, Tank 109, ADHT, H2 Plant) - H2S CMS


test_id:
East Side Mix Drum, TIU Mix Drum, Coker 3, Vac 1 - Sulfur Speciation


test_id:
FCC CO Boiler - Nonsulfuric Acid Particulate Emissions


test_id:
FCC CO Boiler - Nonsulfuric Acid Particulate, PM, SO2, NOx, CO, Ni


test_id:
FCCU - Ammonia, Nonsulfuric, PM, Nickel, SO2, Nox, CO


test_id:
FCCU Coker Burnoff Rate, Nickel Emissions, Nonsulfuric Acid Particulate Emissions


unit_id:
TRP SRU Rich Amine Flash Drum H2S  (AT5512)


test_id:
TIU Mix Drum (Crude 1, Reformer 1, Coker 2, FCC, Crude 2, Naphtha Hydrotreater, Vac 1, East BGOT) - H2S CMS


test_id:
VE, Net Heating Value, Flare Tip Exit Velocity


test_id:
2 CRU Subpart UUU - NESHAP Initial Compliance Test 7-10 & 13 & 21 & 22-05


test_id:
3 CRU Subpart UUU Initial Compliance Demonstration 1-11,15,28-05


test_id:
4 FCCU Wet Scrubber Stack Non-Sulfuric Acid PM Compliance Test 11-30-10 & 12-3-10


test_id:
4 FCCU Wet Scrubber Stack PM, NOx, CO & SO2 Compliance Test 3-17&18-09


test_id:
5 FCCU NSPS Subpart J and Refinery MACT UUU PM Compliance Test 8-15-07


test_id:
5 FCCU Wet Scrubber Non-Sulfuric Acid PM Compliance Test 12-1&2-10


test_id:
Boiler B-21 NOx & CO Compliance Test 9-17-10


test_id:
Boiler B-22 NOx & CO Compliance Test 3-26-10


test_id:
Boiler B-8 NOx, CO, & O2 RATA 5-15-07 (Part 1 of 2)


test_id:
Boiler B-8 VOCs Engineering Evaluation 5-7-08


test_id:
Boilers B-9 & B-10 NOx, CO, & O2 CEMS RATA 4-22-09


test_id:
Boilers B-9 & B-10 NSPS Subpart Db Initial Compliance Test 11-20-06 (Part 1 of 2)


test_id:
No_6 Hydrotreater Fuel Gas H2S RATA 9-22-10


test_id:
Y-7 Cooling Tower VOC Emissions 12-27-10


test_id:
Y-8000 Cooling Tower VOC Emissions 12-27-10


test_id:
2005 - Emissions Test - Marine Dock Flare


test_id:
2006 - Emission Test - FCCU Wet Gas Scrubber


test_id:
2006 - Emission Test - Sulfur Recovery Tail Gas Thermal Oxidizer


test_id:
2007 - Emissions Test - FCCU Wet Gas Scrubber


test_id:
2011 - Emissions Test - SRU Incinerator Stack


test_id:
2011 - Emissions Test - SRU5 Incinerator Stack


test_id:
MACT UU3 MACT UUU Reactor Performance Test


test_id:
UU3 MACT II Skid Performance Test (2009)


test_id:
Attachment 3-31. CMS_Hydrofining Unit 9 Blend Gas (HU9 Drum D301(A-802)) H2S


test_id:
Attachment 3-32. CMS_Hydrofining Unit 9 Blend Gas (HU9 Drum D301(A-802)) Heating Value


test_id:
Attachment 3-33. CMS_Flexicoker By-product Called Low Btu Gas (LBG (A-605)) H2S


test_id:
Attachment 3-34. CMS_Flexicoker By-product Called Low Btu Gas (LBG (A-605)) Heating Value


test_id:
Attachment 3-35. CMS_Flexicoker Blend Gas (FXK Drum D315 (A-625)) H2S


test_id:
Attachment 3-38. CMS_Delayed Coking Unit Blend Gas (DCU Drum D616 (A-903)) H2S


test_id:
Attachment 3-39. CMS_Delayed Coking Unit Blend Gas (DCU Drum D616 (A-903)) Heating Value


test_id:
Attachment 3-40. CMS_Pipestill North Blend Gas (PS-7 Drum D714) Heating Value


test_id:
Attachment 3-41. CMS_Hydrofining Unit 10 Blend Gas  H2S


test_id:
2009.04_VPS4 Common Stack & Atmospheric Heater C


unit_id:
33-Tankage Pipeway & Truck rack (Truck Rack)


# emissions_source_tests

process_testing_notes:
The fuel and refinery gas routed to the flare is monitored for H2S content with a qualified CMS.

frequency_of_testing_for_pollutants_listed:
The CMS is required to be in continous operation when the process unit is operational.


process_testing_notes:
RATA for SO2 and O2 analyzers in Sulfur Recovery Unit


frequency_of_testing_for_pollutants_listed:
At least once every 5 years (Unit is not currently operating)


test_id:
No 10: H2 Plant Methanol Scrubbers 9/15/2009


test_id:
Sulfur Loading- 28F-11 Sulfur Loading Rack Incinerator


test_id:
Sulfur Loading- 28F11 Sulfur Pit Incinerator
 (Sulfur Pit & Loading Rack Vapors w/ Carbon Control)

configuration_changes:
Installation of carbon bed control for sulfur pit vapors


test_id:
U29- SRU 29F-4 Tail Gas Unit Incinerator #1


test_id:
U29- SRU 29F-4 Tail Gas Unit Incinerator #2


test_id:
Source Test - Boiler 10 - NH3 - 12_10_2010


test_id:
Source Test - Boiler 10 - PM NH3 - 10_30_2009


test_id:
Source Test - Boiler 10 - PM NOx SO2 CO ROG - 12_19_2007


test_id:
Source Test - Coke Drum During Venting - PM H2S VOC - 03_04_2010


test_id:
Source Test - Coker Steam Vent - PM - 09_08_2008


test_id:
Source Test - H2 Plant Vents - VOC - 10_27_2010


test_id:
Source Test - Acid Plant Scrubber - SOx H2S - 06_29_2009


test_id:
Source Test - Boiler 7 SCR - NH3 - 09_08_2010


test_id:
Source Test - Cogen and Cogen SCR - CO and NH3 - 08_16_2010


test_id:
Source Test - Sulfur Plant Acid Stack - CO PM H2SO4 - 04_16_08


process_testing_notes:
Ambient monitoring data for 2010 is attached in separate files


frequency_of_testing_for_pollutants_listed:
Daily Calibration, Annual RATA, Monthly CGA


frequency_of_testing_for_pollutants_listed:
Daily Calibrations, Quarterly CGA, Annual RATA


configuration_changes:
This process was shutdown with the calcining operations in 2007


process_testing_notes:
Boiler D231 is the refinery's main boiler providing steam to all associated process units


process_testing_notes:
Boiler D214 is serves as a back-up (spare) boiler to boiler D231.


process_testing_notes:
Stack test for NOx, SOx, CO, PM, and ROG (Note: VOC destruction efficiency also performed).

frequency_of_testing_for_pollutants_listed:
VOC Destruction Efficiency = Annually; PM = 5 years; CO = Annually or 5 Years; NO = 3 years; SOx = not specified


process_testing_notes:
Collect 5 inlet stream samples: 1)Asphalt Truck Loading, 2)Asphalt Blowing, 3) API (wastewater vent), 4)Storage Tanks, and 5) Refinery Gas (Atmospheric and Vacuum Tower off-gass).   The measure 2 stack locations (Main and Bypass) of incinerator.


configuration_changes:
Boiler #1 idled per Delaware regulations

process_testing_notes:
Boiler #1 - TSP, PM10, H2SO4 Mist, CO, VOC


configuration_changes:
Combined Cycle Unit #2 has had burner modifications to use natural gas as a fuel.  No longer using syngas as fuel.


configuration_changes:
Boiler #3 is no longer using syngas as a fuel.

process_testing_notes:
Boiler #3 - TSP, PM10, H2SO4 Mist, CO, VOC


process_testing_notes:
Boiler #2 - TSP, PM10, H2SO4 Mist, CO, VOC


configuration_changes:
Combined Cycle Unit #1 has had burner modifications to use natural gas as a fuel.  No longer using syngas as fuel.


process_testing_notes:
PAH, Semi-volatiles, Volatiles, Acute Toxicity


configuration_changes:
stack testing prior to addition of low NOx burner


configuration_changes:
stack testing after low NOx burner added.


configuration_changes:
This test was to evaluate two possible maintenance modes for the WGS.  One condition had only one WGS ring running and the WESP running, the other condition had one WGS ring running and the WESP off-line.  These are not normal operating conditions.

process_testing_notes:
This test was to evaluate two possible maintenance modes for the WGS.  One condition had only one WGS ring running and the WESP running, the other condition had one WGS ring running and the WESP off-line.  These are not normal operating conditions.


configuration_changes:
Tested two conditions. Condition 1 represents normal operations, with both of wet gas scrubber's (WGS) rings and the wet electrostatic precipitator (WESP) operating.  Condition 2 represents running with both WGS rings operating but the WESP off-line.

process_testing_notes:
Tested two conditions. Condition 1 represents normal operations, with both of wet gas scrubber's (WGS) rings and the wet electrostatic precipitator (WESP) operating.  Condition 2 represents running with both WGS rings operating but the WESP off-line.

frequency_of_testing_for_pollutants_listed:
Annually for PM, until three consecutive performance tests demonstrate meeting the consent decree PM performance level.


configuration_changes:
Start-up of Selective Catalytic Reduction for Nox control in November 2010


process_testing_notes:
Unit configuration - 2 parallel Claus units vent tailgas which is commingled and fed to one tailgas cleanup unit.  This unit vents to 2 parallel thermal oxidizers.  The exhaust from the 2 oxidizers is vented to a single stack with a single CEMS.


test_id:
FCCU-1 NOx SO2 CO VOC Source Test_03-19-2009


configuration_changes:
FCCU-2 NOX CEMS - SCR commenced operation on 12/15/2010


configuration_changes:
FCCU-2 CO Heater SO2 CEMS - wet scrubber commenced operation on 12/15/2010


configuration_changes:
FCCU-1 data included in report, however FCCU-1 was controlled by an electrostatic precipitator at the time, these controls were replaced by a SCR and wet scrubber in December 2008; FCCU-2 wet scrubber commenced operation on 12/15/2010


configuration_changes:
FCCU-2 wet scrubber commenced operation on 12/15/2010


test_id:
HTR-ALKY-HM2 NOx CO Source Test_06-17-2008


test_id:
HTR-DU1-F301 NOx, PM, CO, VOC Source Test_03-30-2006

process_testing_notes:
In test report, HTR-DU1-F302 is labled as "North" heater and HTR-DU1-F301 is labled as "South" heater


process_testing_notes:
Benzene destruction efficiency test on enclosed flare (marine vapor recovery) on DOCKS benzene loading operation


test_id:
North Property Flare H2S Source Test_2007-12-13


configuration_changes:
Testing conducted during SCOT control device outage per Consent Decree Requirement


test_id:
WWTP Benzene Biodegradation Rate_June 2005

process_testing_notes:
Test report incidates "DRAFT" however this is the final report.


configuration_changes:
The ESPs are installed on both FCUs.  The SCR is installed on FCU 600 only.


configuration_changes:
SCR controls were installed and in use for these stack tests (No. 3 Stanolind Power Station Boilers #31, #33, and #36).


configuration_changes:
SCR controls were installed and in use for these stack tests (No. 3 Stanolind Power Station Boilers #33 and #36).


test_id:
AQS 09653-11-001 & Associated Appendices - Boiler 1


test_id:
AQS 09653-11-001 & Associated Appendices - Boiler 2


test_id:
AQS 09653-11-001 & Associated Appendices - Boiler 4


test_id:
AQS 09653-11-001 & Associated Appendices - Crude


test_id:
AQS 09653-11-001 & Associated Appendices - Platform


process_testing_notes:
FCCU Regenerator Stack - CEMs (CO, Nox, SO2, NO, CO2, O2)


process_testing_notes:
Hydrotreating Unit Reactor Charge Heater Stack (210-H-100)


process_testing_notes:
Hydrotreating Unit Reboiler Stabilizer Heater Stack (210-H-101)


frequency_of_testing_for_pollutants_listed:
Initial Compliance Test for 63 Subpart UUU


process_testing_notes:
Maximum charge rates were run for maximum coke make.  See Cover letter for ESP Settings

frequency_of_testing_for_pollutants_listed:
Per our Consent Decree, NCRA tested the FCC annually until there were three consecutive tests in which the limit was not exceeded then the testing went to every two years.


process_testing_notes:
Maximum charge rates were run but limited by air intake.  See cover letter for ESP Settings


process_testing_notes:
Maximum charge rates were run for maximum coke make.  See cover letter for ESP Settings


process_testing_notes:
Initial performance test for two new flares NCU-5 and NCU-6


process_testing_notes:
Initial Performance Test for Flare UCR-2


frequency_of_testing_for_pollutants_listed:
Only initial test required, but failed BTU limit.  Increased sweep gas rates and re-tested.


process_testing_notes:
Test for East Railcar Loading Rack Flare


process_testing_notes:
Method 5B for particulate matter at worst case wet gas scrubber operating conditions.


process_testing_notes:
Method 5B for particulate matter with the wet gas scrubber operating at normal conditions.


process_testing_notes:
Method 5B for particulate matter testing at the worst case operating conditions of the wet gas scrubber.


process_testing_notes:
Method 5B for particulate matter with the wet gas scrubber at normal operating conditions.


process_testing_notes:
Method 5B for particulate matter at the wet gas scrubber worst case operating condition


process_testing_notes:
Method 5B for particulate matter with the wet gas scrubber operating at normal conditions


process_testing_notes:
This test also contains H2S performance test.


process_testing_notes:
CEMS certified October 1, 2010 as part of the flare gas recovery system project as required by the NSR CD.


configuration_changes:
No configuration changes after testing was performed.

process_testing_notes:
Flare gas is treated with a caustic scrubber.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during April 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during August 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during December 2005.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during December 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during February 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during January 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during July 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during June 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during March 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during May 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during November 2005.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during November 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during October 2005.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during October 2006.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during September 2005.


process_testing_notes:
Alarm and canister report from the fenceline montoring conducted during September 2006.


process_testing_notes:
Fuel Gas Flow Rate Thru Treaters is provided under the daily production column of the CMS data template.


process_testing_notes:
Test was performed on FCC Regen Stack, Hot Oil Heater (H-1501), Vapor Combustor, and Stripper Reboiler (H-1702) for engineering assessment of emissions and not to demonstrate compliance with any State or Federal regulations or permit limits.


process_testing_notes:
NOx CEMS data for the FCCU unit. Low NOx combustion additives to replace Pt-based combustion additives are used to control NOx.


process_testing_notes:
SO2 CEMS data from the FCCU. A wet scrubber/flue gas desulfurizaion is used to control SO2 emissions from the FCCU.


process_testing_notes:
Summary report for the fenceline monitoring conducted from September 2005 through December 2006, that was submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from April 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from August 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from December 2005 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from December 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from February 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from January 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from July 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from Jun 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from March 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from May 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from November 2005 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from November 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from October 2005 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from October 2006 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from September 2005 submitted to the LDEQ.


process_testing_notes:
Fenceline monitoring data from September 2006 submitted to the LDEQ.


process_testing_notes:
Initial Title V Permit compliance test. Includes results for heaters Crude Heater (CRUDE), Hot Oil Heater (ROSE), Reformer Heater (REFORMER), Vacuum Heater (VACUUM), Turbine GT-901 and Boiler B-901 (GEN1), and Turbine GT-902 and Boiler B-902 (GEN2).


process_testing_notes:
Emissions from the FCCU were tested to determine the emissions of PM, SO2, NOx, and CO in order to demonstrate compliance with emission limits from Title V Permit No. 3120-00012-V0 issued by the LDEQ.


process_testing_notes:
Emissions from P-804 Diesel Engine were tested to determine the emission rates of NOx and CO under Title V Permit No. 3120-00012-V3.  This source is currently shutdown and not operational.


process_testing_notes:
To determine the emission rates of NOx, CO, and VOC on the Enclosed Vapor Combustor.  This unit controls emissions from storage tanks and loading operations and is not associated with a single process unit.


process_testing_notes:
Test was conducted on No. 2 Hot Oil Heater (H-2701) as an initial performance test to measure NOx and CO mass emission rates.  NOx, CO, and O2 were measured as part of this test.


configuration_changes:
Tested at higher firing rate than the previous stack test.

process_testing_notes:
Test was conducted on No. 2 Hot Oil Heater (H-2701) to measure NOx and CO mass emission rates.  NOx, CO, and O2 were measured as part of this test.


configuration_changes:
Unit was retested with heater firing rate within the permitted limits.

process_testing_notes:
NOx and CO emissions from the Reformer Heater (H-2401, H-20402, H-2403) were measured to demonstrate compliance with the emission limits in Title V Permit No. 3120-00012-V4 issued by LDEQ.


configuration_changes:
FCC Unit tested after installing Wet Gas Scrubber on the FCCU that controls SO2 emissions.

process_testing_notes:
Initial compliance test and the RATA on the Wet Gas Scrubber on the FCCU Unit. Test determined pollutant mass emissions of SO2, NOx, CO, PM10 and to quality assure the continuous emission monitoring system (CEM) on FCCU to measure SO2, CO, and NOx.


configuration_changes:
Test completed after refinery expansion.

process_testing_notes:
Test demonstrates compliance with the NOx emission factors in LAC 33:III.2201.D, Table D-1A and the permitted emission rates for NOx and CO from Title V Permit No. 3120-00012-V6 issued by LDEQ for Crude Heater (H-201).


process_testing_notes:
Includes test results for Cogen 1/Boiler 1 which is comprised of Turbine GT-9-601 and Boiler B-901 and Cogen 2/Boiler 2 which is comprised of Turbine GT-9-602 and Boiler B-902.


process_testing_notes:
HDS Charger Heater (H-1701), Stripper Reboiler (H-1702) associated with HDS unit and on FCCU Preheater (F-502) associated with FCCU unit were tested to demonstrate compliance with NOx and CO limits in the Title V Permit No. 3120-00012-V6 issued by LDEQ.


process_testing_notes:
Emissions from SRU Incinerator No. 1 (SRU1) and SRU Incinerator No. 2 (SRU2) were tested to determine compliance with the SO2 emission limits in the Title V Permit No. 3120-00012-V6 issued by LDEQ.


configuration_changes:
Heater was tested after refinery expansion.

process_testing_notes:
Vacuum Crude Tower Heater (H-401) tested to measure NOx and excess O2 and to demonstrate compliance with the NOx emission factors in LAC 33:III.2201.D, Table D-1A and the NOx and CO emission rates from Title V Permit No. 3120-00012-V6 issued by LDEQ.


process_testing_notes:
40 CFR 63 Subpart UUU Compliance Re-Test


process_testing_notes:
Engineering study of Boiler No. 3 and Boiler No. 4.


process_testing_notes:
The CrudVacHtr was tested at this same time, which is in the test report. This report is listed below as 4_04-05CrudVacHtr_PM_12-2008


process_testing_notes:
The Crude Heater and Vacuum Heater vent through the same stack and are monitored by one CEMS.


process_testing_notes:
The Crude Heater and Vacuum Heater vent through the same stack and are monitored by one CEMS.  The cover page does not specify the CrudVac Htr although it is included in the report with the FCCU Stack Test report.


process_testing_notes:
The term "FCCU Crude Heater" used in the report should actually be "FCCU Charge Heater"


process_testing_notes:
* Multiple sample runs were conducted with one ESP off-line * The annual requirement for this test has been fulfilled.  Although the results of the test have not been received to date.


process_testing_notes:
Testing conducted during maximum capacity operations.


configuration_changes:
prior to implementation of TGTU required by CD


process_testing_notes:
Incinerator Stack, Coker heater, Fuel Gas


process_testing_notes:
Incinerator Stack, Reformer Stack, Boiler Stack, FCCU Feed Preheater, Fuel Gas


frequency_of_testing_for_pollutants_listed:
Biennial for Heater Stacks, Annual for Reformer Stack


process_testing_notes:
Represents the emissions from the FCCU CO Boiler Stack (FCCU SO2, NOx, CO, O2, and Flow Relative Accuracy Test Audit PM and SO2 Compliance Demonstration for ExxonMobil Billings Refinery, 12/22/2010, BATES LABEL 203 - 360)


configuration_changes:
Flue gas routed to normal disposition to offsite lime treatment cogeneration facility.


process_testing_notes:
Represents the emissions from the B-8 Boiler Stack (Emissions Test Report for F-551 Hydrogen Plant Process Heater and the B-8 Boiler ExxonMobil Billings Refinery, 12/16/2010, BATES LABEL 361-442)


process_testing_notes:
Emissions test - Boilers 1&2 (combined stack) - NOx and CO - reference report files [Boiler NOx-CO Test 02-11-10 Part 1.pdf] and [Boiler NOx-CO Test 02-11-10 Part 2.pdf]


process_testing_notes:
Emissions and CEM RATA test - Boilers 1&2 (combined stack) - SO2 - reference report file [Boiler SO2 Test 02-09-11.pdf]


process_testing_notes:
Test to demonstrate compliance with refinery MACT II HCl limit during catalyst regeneration - reference report file [Cat Reformer Heater HCl Test MACT II 10-13-05.pdf]

frequency_of_testing_for_pollutants_listed:
Per performance test requirements of refinery MACT II


process_testing_notes:
FCC CO emissions and CEM RATA test - reference report file [FCC CO Test 03-08-11 Part 1.pdf] and {FCC CO Test 03-08-11 Part 2.pdf]


process_testing_notes:
Test to demonstrate compliance with refinery MACT II nickel emission limit for catalytic cracking units - reference report file [FCC Nickel Test MACT II 09-13-05.pdf]

frequency_of_testing_for_pollutants_listed:
Per performance testing requirements of refinery MACT II


process_testing_notes:
Test to demonstrate compliance with catalyst regenerator particulate matter limit - reference report file [FCC PM Test 02-08-11.pdf]


process_testing_notes:
Emissions and CEM RATA tests - catalyst regenerator SO2 and NOx - reference report file [FCC SO2-NOx-O2 Test 02-09-11.pdf


process_testing_notes:
Test to demonstrate compliance with TOC limit for loading racks in refinery MACT I and to demonstrate compliance with NOx and CO emission limitation pursuant to State requirements - reference report file [Gasoline Loading VCU Test 09-22-08.pdf]


process_testing_notes:
Heater for Hydrogen Plant #1 for NOx and CO emissions - reference report file [HTU-H2#1 NOx-CO test 10-08-08.pdf]


process_testing_notes:
Heater for Hydrogen Plant #2 - Test for NOx lb/MMBtu; conducted at unit rated capacity - reference report file [H2 #2 NOx Test 02-09-10.pdf]


process_testing_notes:
Heater for Hydrogen Plant #2 - Test for NOx lb/MMBtu - conducted at unit "normal" operating rate - reference report file [H2 #2 NOx Test 02-10-11.pdf]


process_testing_notes:
Test for HTU heater emissions (NOx and CO) - last done in 2008 - reference report file [HTU-H2 #1 NOx-CO test 10-08-08.pdf]

frequency_of_testing_for_pollutants_listed:
No set schedule; only as required by State agency


process_testing_notes:
Unit ID: Boiler 1; Nox CEMS installed in 2010, RATA performed in August 2010, valid data began September 1, 2010


process_testing_notes:
Unit ID: Boiler 2; Nox CEMS installed in 2010, RATA performed in August 2010, valid data began September 1, 2010


configuration_changes:
Added Mist Eliminator to WESP and Added SNCR


process_testing_notes:
Test of the Wet Gas Scrubber, September 20, 2010


process_testing_notes:
Test of U4 Boiler 3 (West), May 17, 2011


process_testing_notes:
Test of Boiler 4 (East), October 27, 2010


process_testing_notes:
Test of Vapor Recovery Unit at Truck Loading Terminal, March 2011


process_testing_notes:
Test of Vapor Recovery Unit A at Marine Loading, August 2010


process_testing_notes:
Test of Vapor Recovery Unit B at Marine Loading, September 2010


process_testing_notes:
10/1/08 5 year test. Also performed for Consent Decree


test_id:
2004 PPBWTO 9150 & 9151  CO NOx SO2 NMNEHC DE% HAPs (T015-Total) Hexane PM10 Stack Test


test_id:
2006 H2BW Degassifier Vent CO NH3 TNMHC Stack Test


test_id:
2010 LCN CRUB NOx CO SO2 TNMHC Stack Test


process_testing_notes:
BTU content of refinery fuel gas CEM data


process_testing_notes:
H2S content of refinery fuel gas CEM data


process_testing_notes:
Crude Unit 7 Process heater F1 NOx CEM data


process_testing_notes:
Crude Unit 7 Process Heater F2 NOx CEM data


process_testing_notes:
Stack testing of sulfur plant tail gas units


process_testing_notes:
Stack test report for 3 boilers and 1 gas turbine


process_testing_notes:
CEMS is before CO boiler.  CEMS was installed in October 2010.


process_testing_notes:
Fuel gas is used facility wide but CMS is located after Amine Treatment unit


process_testing_notes:
MACT II Initial Performance Test April 2006


process_testing_notes:
October 2007 performance test for SO2 to fulfill the requirements of NSR permit.

frequency_of_testing_for_pollutants_listed:
Initial/Quarterly Dragar tube testing required


process_testing_notes:
February 2010 performance test to fulfill the requirements of NSR permit


process_testing_notes:
December 2010 performance test to fulfill the requirements of NSR permit


process_testing_notes:
December 2009 performance test to fulfill the requirements of NSR permit


process_testing_notes:
December 2009 engineering performance test for metals and particulate characterization.  Also includes gaseous pollutant test.


test_id:
East Side Fuel Gas Line - Sulfur Speciation


test_id:
East Side Mix Drum (Reformer 2, Isocracker, Tank 108, Tank 109, ADHT, H2 Plant) - H2S CMS


test_id:
East Side Mix Drum, TIU Mix Drum, Coker 3, Vac 1 - Sulfur Speciation


test_id:
FCC CO Boiler - Nonsulfuric Acid Particulate Emissions

configuration_changes:
Normal Operating Mode
Upset Mode - Both ESP compartments operating with 1 of 8 transformers to simulate a malfunction.
Maintenance Mode - 1 of 2 ESP compartments offline, de-energized, and sealed; remaining compartment operating w/ 4 transformers.


test_id:
FCC CO Boiler - Nonsulfuric Acid Particulate, PM, SO2, NOx, CO, Ni


test_id:
FCCU - Ammonia, Nonsulfuric, PM, Nickel, SO2, Nox, CO


test_id:
FCCU Coker Burnoff Rate, Nickel Emissions, Nonsulfuric Acid Particulate Emissions


test_id:
TIU Mix Drum (Crude 1, Reformer 1, Coker 2, FCC, Crude 2, Naphtha Hydrotreater, Vac 1, East BGOT) - H2S CMS


test_id:
VE, Net Heating Value, Flare Tip Exit Velocity


configuration_changes:
In 1st Quarter of 2008, new Seimens BTU analyzer was placed into service and the old ABB H2S analyzer was decommisioned.


configuration_changes:
New air grid, cyclones, and catalyst distributor as of 11/25/10.  CO Boiler permanently shutdown as of 10/5/10.  Installed new waste heat boiler as of 11/25/10

process_testing_notes:
Stack Test at FCCU ESP Stack to measure PM, SO2, NOx, and CO


process_testing_notes:
Annual RATA SO2/O2 CEMS located on ESP Stack


process_testing_notes:
Initial RATA CO/CO2/O2/SO2/NOX CEMS located on FCC Regen line upstream of ESP


process_testing_notes:
Annual RATA H2S CEMS for Aromatics Fuel Gas


process_testing_notes:
Annual RATA H2S CEMS for East Side Fuel Gas


process_testing_notes:
Annual RATA CO/CO2/O2 CEMS located on FCC Regen line upstream of ESP


configuration_changes:
1/1/10 -10/15/10 the FCC unit operated with a CO Boiler and and ESP.  During the fall 2010 TAR the CO Boiler was permanently shutdown and replaced with a waste heat boiler.  Post TAR 11/25/10, the outlet of the FCC only had an ESP.


configuration_changes:
New air grid, cyclones, and catalyst distributor as of 11/25/10

process_testing_notes:
CEMS data located at FCC Regen outlet before ESP Stack


process_testing_notes:
P008 Flare visible emissions, pilot flame presence, net heating value, exit velocity


process_testing_notes:
P009 flare visible emissions, pilot flame presence, net heating value, exit velocity


test_id:
2 CRU Subpart UUU - NESHAP Initial Compliance Test 7-10 & 13 & 21 & 22-05


test_id:
3 CRU Subpart UUU Initial Compliance Demonstration 1-11,15,28-05


test_id:
4 FCCU Wet Scrubber Stack Non-Sulfuric Acid PM Compliance Test 11-30-10 & 12-3-10


test_id:
4 FCCU Wet Scrubber Stack PM, NOx, CO & SO2 Compliance Test 3-17&18-09


test_id:
5 FCCU NSPS Subpart J and Refinery MACT UUU PM Compliance Test 8-15-07


test_id:
5 FCCU Wet Scrubber Non-Sulfuric Acid PM Compliance Test 12-1&2-10


test_id:
Boiler B-21 NOx & CO Compliance Test 9-17-10


test_id:
Boiler B-22 NOx & CO Compliance Test 3-26-10


test_id:
Boiler B-8 NOx, CO, & O2 RATA 5-15-07 (Part 1 of 2)


test_id:
Boiler B-8 VOCs Engineering Evaluation 5-7-08


test_id:
Boilers B-9 & B-10 NOx, CO, & O2 CEMS RATA 4-22-09


test_id:
Boilers B-9 & B-10 NSPS Subpart Db Initial Compliance Test 11-20-06 (Part 1 of 2)


test_id:
No_6 Hydrotreater Fuel Gas H2S RATA 9-22-10


test_id:
Solid Vapor Extractor Vent (SVE) Hydrocarbons Engineering Evaluation Test 11-7-07 (Part 1 of 2)


test_id:
Y-7 Cooling Tower VOC Emissions 12-27-10


test_id:
Y-8000 Cooling Tower VOC Emissions 12-27-10


configuration_changes:
Removed from service and replaced with Indeck Boiler (next test)


configuration_changes:
Removed from service and replaced with electric motor


configuration_changes:
CO tested for annual emissions inventory information.


configuration_changes:
No changes made that affect chloride emissions. Under advice from the CCR manufacturer, UOP, reactor purge gas temperature was increased to strip hydrocarbon from the circulating catalyst as it travels from the reactor to the regenerator to reduce TOC

frequency_of_testing_for_pollutants_listed:
After further review of MACT UUU, we believe TOC testing is not required because control device vents are exempt from the TOC limit.  HCl testing is required as an initial demonstration of compliance.


configuration_changes:
Retest TOC following temperature increase.

frequency_of_testing_for_pollutants_listed:
After further review of MACT UUU, we believe TOC testing is not required because control device vents are exempt from the TOC limit.


configuration_changes:
Stack flow is not measured and is required for annual emissions inventory.

frequency_of_testing_for_pollutants_listed:
Part 70 operating permit requires annual testing.


frequency_of_testing_for_pollutants_listed:
Part 70 operating permit requires annual PM testing.


process_testing_notes:
2011 EC Flare Performance Test- velocity, heat content, etc.


process_testing_notes:
Oct. 2007 PM and NH3 tests (with different NH3 injection rates)


process_testing_notes:
2006 Reformer Regeneration Performance Test


process_testing_notes:
2005 McGill Vapor Recovery Unit Performance Test


process_testing_notes:
2005 John Zink Vapor Recovery Unit Performance test


process_testing_notes:
2005 Sulfur Recovery Unit Compliance Test


process_testing_notes:
2009 Flare Test - 10 Plant Flare- velocity, heat content, etc.


process_testing_notes:
2009 Flare Test - 12 Plant Flare- velocity, heat content, etc.


process_testing_notes:
2008 Ethylene Oxide Compliance Tests and Total Resource Effectiveness


process_testing_notes:
Jan. 2007 NH3 tests (with & without Process Water Stripper on)


process_testing_notes:
Jun. 2007 PM and NH3 tests (with & without NH3 injection into ESPs)


configuration_changes:
Sulfur sent to sulfur storage tank instead of sulfur pit


configuration_changes:
upgraded from three fields to six fields


test_id:
2005 - Emissions Test - Marine Dock Flare


test_id:
2006 - Emission Test - FCCU Wet Gas Scrubber


test_id:
2006 - Emission Test - Sulfur Recovery Tail Gas Thermal Oxidizer


test_id:
2007 - Emissions Test - FCCU Wet Gas Scrubber


test_id:
2011 - Emissions Test - SRU Incinerator Stack


test_id:
2011 - Emissions Test - SRU5 Incinerator Stack


test_id:
MACT UU3 MACT UUU Reactor Performance Test


test_id:
UU3 MACT II Skid Performance Test (2009)


test_id:
Attachment 3-21. CMS_FLARE04 Heating Value


test_id:
Attachment 3-24. CMS_FLARE11 Heating Value


test_id:
Attachment 3-27. CMS_FLARE14 Heating Value


test_id:
Attachment 3-29. CMS_Base Refinery Blend Gas (Utilities Drums D291/D292(A-812)) H2S


test_id:
Attachment 3-30. CMS_Base Refinery Blend Gas (Utilities Drums D291/D292(A-812)) Heating Value


test_id:
Attachment 3-31. CMS_Hydrofining Unit 9 Blend Gas (HU9 Drum D301(A-802)) H2S


test_id:
Attachment 3-32. CMS_Hydrofining Unit 9 Blend Gas (HU9 Drum D301(A-802)) Heating Value


test_id:
Attachment 3-33. CMS_Flexicoker By-product Called Low Btu Gas (LBG (A-605)) H2S


test_id:
Attachment 3-34. CMS_Flexicoker By-product Called Low Btu Gas (LBG (A-605)) Heating Value


test_id:
Attachment 3-35. CMS_Flexicoker Blend Gas (FXK Drum D315 (A-625)) H2S


test_id:
Attachment 3-36. CMS_High Btu Gas (HSK Drum D853(A-951)) H2S


test_id:
Attachment 3-37. CMS_High Btu Gas (HSK Drum D853(A-951)) Heating Value


test_id:
Attachment 3-38. CMS_Delayed Coking Unit Blend Gas (DCU Drum D616 (A-903)) H2S


test_id:
Attachment 3-39. CMS_Delayed Coking Unit Blend Gas (DCU Drum D616 (A-903)) Heating Value


test_id:
Attachment 3-40. CMS_Pipestill North Blend Gas (PS-7 Drum D714) Heating Value


test_id:
Attachment 3-41. CMS_Hydrofining Unit 10 Blend Gas  H2S


configuration_changes:
installed selective catalytic reduction unit (SCR) in 2009


test_id:
Ambient Air Monitoring Reports January 2000 through November 2006


process_testing_notes:
Cogen 42 - Tested for PM, NH3, Nox, CO, VOC


process_testing_notes:
Cogen 41- Tested for PM, NH3, NOx, CO, VOC


process_testing_notes:
Cogen 24 - Tested for PM, NH3, NOx, CO, VOC, SO2


process_testing_notes:
Cogen 43 - Tested for PM, NH3, Nox, CO, VOC


process_testing_notes:
PtR-4 Regeneration Vent - Tested for SO2, HCL, CL2, CO


process_testing_notes:
PtR - 3Reactor Regeneration Vent - Tested for HCL, CL2


process_testing_notes:
FCC Wet Gas Scrubber Stack - Tested for PM, H2SO4, NH3, Nox, CO, VOC


process_testing_notes:
FCC Wet Gas Scrubber Stack - Tested for PM


process_testing_notes:
Cooling Towers tested using the El Paso Method


process_testing_notes:
Moisture and Flow Testing from exhaust stack


process_testing_notes:
DHT Charge and Reboiler heaters from common stack


process_testing_notes:
Marine Vapor Combustor - Initial CEMS performance demonstration

frequency_of_testing_for_pollutants_listed:
Iniitial only - quarterly CGAs allowed in lieu of annual RATA.


process_testing_notes:
SRU Tail Gas Thermal Oxidizer - includes H2S testing

frequency_of_testing_for_pollutants_listed:
Initial test and annual RATA for CEMS pollutants


process_testing_notes:
SRU Tail Gas Thermal Oxidizer - includes H2S

frequency_of_testing_for_pollutants_listed:
Initially and Annual RATA for CEMS pollutants


process_testing_notes:
Fluid Catalytic Cracking Unit Wet Gas Scrubber RATA


process_testing_notes:
736 and 737 Delayed Coker Steam Vent Testing - see "Problems Encountered" in report for known error/uncertainty with moisture correction for Method 15 and 18 results for speciated VOCs and H2S.

frequency_of_testing_for_pollutants_listed:
One-time (but ICR will require retest with more pollutants)


test_id:
2009.04_VPS4 Common Stack & Atmospheric Heater C


process_testing_notes:
This monitor measures H2S in the fuel gas that goes to 4 heaters in units 11 and 14.  The throughput on the yearly CMS summary is the sum of the fuel feed to all 4 heaters.


frequency_of_testing_for_pollutants_listed:
This was initial test shortly after unit came on-line, the TCEQ permit requires that this source be tested once every 5 years.


frequency_of_testing_for_pollutants_listed:
Testing is done once every 5-years per the TCEQ permit.


frequency_of_testing_for_pollutants_listed:
This was initial compliance test after the new scrubber becamse operational.  Going forward it will be tested annually per the consent decree.


frequency_of_testing_for_pollutants_listed:
This was a one time test to get approval of an alternate monitoring plan (AMP) for opacity.  Additional tests will only be done if the approval at different scrubber parameters than in the current approved AMP from EPA is sought.


process_testing_notes:
This monitor measures H2S in the fuel gas that goes to 9 heaters in Units 9, 25.1, 26.1 and 38.  The throughput on the yearly data is the sum of the fuel feed to all of the heaters.


process_testing_notes:
Flare 11 is one of a series of flares in the Sweeny flare gas system.  Flare 11 only flares during periods when there is more flare gas than the flare gas recovery system can handle.


process_testing_notes:
Flare 11 is one of series of flares in the Sweeny flare gas system. Flare 11 only flares during periods when there is more off gas than the flare gas recovery system can handle.


process_testing_notes:
Flare is one of a series of flares in the Sweeny flare gas system.  Flare 16 only flares during periods when there is more flare gas than the flare gas recovery system can handle.


process_testing_notes:
Flare 16 is one a series of flares in the Sweeny flare gas system, Flare 16 only when flares when there is more flare gas than the flare gas recovery system can handle/


process_testing_notes:
Flare 17 is one of a series of flares in the Sweeny flare gas system.  Flare 17 only flares during periods when there is more flare gas than the flare gas recovery system can handle.


process_testing_notes:
Flare 17 is one of a series of flares in the Sweeny flare system, Flare 17 only flares during periods when there is more flare gas than the flare gas recovery system can handle.


process_testing_notes:
Flare 19 is one of a series of flares in the Sweeny flare gas system.  Flare 19 only flares during periods when there is more flare gas than the flare gas recovery system can handle.


process_testing_notes:
Flare 19 is one of a series of flares in the Sweeny flare gas system, Flare 19 only flares during periods when there is more flare gas than the flare gas recovery system can handle.


process_testing_notes:
Flare 29 is one of a series of flares in the Sweeny flare gas system.  Flare 29 flares only during periods when there is more flare gas than the flare gas recovery system can handle.


process_testing_notes:
Flare 29 is one of a series of flares in the Sweeny flare gas system, Flare 29 only flares during periods when there is more flare gas than the flare gas recovery system can handle.


process_testing_notes:
Unit ID:  East Cogen HRSG, West Cogen HRSG, East Cogen Turbine, West Cogen Turbine


frequency_of_testing_for_pollutants_listed:
To demonstrate compliance with new operating parameters.


process_testing_notes:
Particulates, Sulfur Dioxide, Sulfuric Acid Mist


process_testing_notes:
NOx and CO. Special condition - all cat adders down.


process_testing_notes:
RATA Test, H2S in Reformer Fuel Gas, Refinery Fuel Gas, FCC Absorber OG


configuration_changes:
Wet Gas Scrubber installed and operational November 12th, 2010.


# equipment_leak_detection

fugitive_emission_sources_other_any:
Caps, Check Valve, Coupling, Elbow, Filter, Gauge, Hatch, Level Control, Bleeder, Mixer Pump, Plug, Reducer, Regulator, Sight Glass, Tee, Tubing, Fitting, Union, Vent, Manway


process_unit_id:
Other Non Process Units for Equipment Leak Reporting


process_unit_id:
(P4S1) Nine-Pos. Asphalt/Fuel Oil Tank Car Loading


process_unit_id:
(P4S3) Two-Pos. Asphalt Tank Truck - West Loading


process_unit_id:
(P4S5) Two-Pos. Asphalt/Fuel Oil Tank Truck - East Loading


process_unit_id:
(P4S7) Single Pos Asphalt Tank Truck Loading


fugitive_emission_sources_other_any:
77 Hatches, 74 Sight Glasses, 127 Gauges


fugitive_emission_sources_other_any:
16 Hatches, 39 Sight Glasses, 120 Gauges


fugitive_emission_sources_other_any:
84 Hatches, 51 Sight Glasses, 257 Gauges


process_unit_id:
(P8S27) Gasoline Tank Truck Loading Rack No. 21


process_unit_id:
(P8S4) Asphalt Tank Truck Loading Rack No. 4


process_unit_id:
(P8S5) Asphalt Tank Truck Loading Rack No. 5


process_unit_id:
(P8S6) Asphalt Tank Truck Loading Facility No. 6


process_unit_id:
(P8S7) Asphalt Tank Truck Loading Facility No. 7


process_unit_id:
(P8S8) Asphalt Tank Truck Loading Facility No. 8


process_unit_id:
(P8S9) Asphalt Tank Truck Loading/Unloading Faciilty No. 11


fugitive_emission_sources_other_any:
Unclassified equipment such as sight glass, regulators, manways and explosion doors


fugitive_emission_sources_other_any:
Unclassified equipment such as sight glass, manways, regulators and explosion doors.


fugitive_emission_sources_other_any:
Unclassified equipment such as sight glass, regulators, manways, explosion doors.


fugitive_emission_sources_other_any:
Unclassified equipment such as sight glass, regulators, manways, and explosion doors.


fugitive_emission_sources_other_any:
Unclassified equipment such as sight glass, regulators, manway and explosion doors.


fugitive_emission_sources_other_any:
controller box, check valve, clamp, gauge


fugitive_emission_sources_other_any:
electrical connection, vacuum breaker, other


process_unit_id:
(P8S11) Asphalt Tank Truck Loading/Unloading Rack No. 13


process_unit_id:
(P8S12) Fuel Oil/Gas Oil Tank Truck Loading Rack No. 14


process_unit_id:
(P8S13) Asphalt Tank Truck Loading Facility No. 15


process_unit_id:
(P8S16) Fuel Oil/Light Products Truck Loading Facility No. 18


process_unit_id:
(P8S17) Fuel Oil/Diesel Tank Truck Loading Rack No. 19


process_unit_id:
(P8S18) Gasoline Loading Facilities No. 20


process_unit_id:
(P8S20) LPG Tank Truck Unloading Rack No. 22


process_unit_id:
(P8S25) Organic Tank/Rail Car Loading/Unloading Facility


notes:
Note 3: Part 2 Section 3, Equipment Leaks - Process Units, Atmospheric PRD - Liquid. The 7 PRDs identified for this process are 1" thermal relief valves for expansion relief during blocked-in conditions on the loading suction and discharge line.


notes:
GGG exempts pumps in light liquid service (naphtha) & valves in gas or light liquid service within a process unit that is located on the Alaska North Slope.  Also, the open-ended lines counted are valves with plugs or blinds.


fugitive_emission_sources_other_any:
Meter, site glass, manway, contractor, etc.


process_unit_id:
FUEL GAS TREATING SYSTEM (V-1640) SYSTEM


process_unit_id:
Fuel Storage and Dispensing (Gasoline 15W)


process_unit_id:
Fuel Storage and Dispensing (Gasoline 16E)


process_unit_id:
HCU Fuel Gas Treatment (V-1011) Treatment


fugitive_emission_sources_other_any:
Gauge, meter, strainer, hatch, check valve


fugitive_emission_sources_other_any:
gauge, meter, sight glass, manway, filter, strainer, check valve


fugitive_emission_sources_other_any:
manway, meter, hatch, check valve, connection, thermowell


process_unit_id:
108- SOUR CRUDE / REDUCED CRUDE TANK FARM


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (41; 41; quarterly; 10,000); Instrumentation Systems LL (141; 141; quarterly; 10,000); Agitator, LL (6; 6; monthly; 10,000)


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (46; 46; Annually; 10000); Instrumentation Systems, LL (21; 21; Annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (77; 77; Annually; 10000); Instrumentation Systems, LL (30; 30; Annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (41; 41; Annually; 10000); Instrumentation Systems, LL (21; 21; Annually; 10000); Instrumentation Systems, HL (48; 48; Less than annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (96; 96; Annually; 10000); Instrumentation Systems, LL (122; 122; Annually; 10000); Instrumentation Systems, HL (14; 14; Annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (73; 0; No set interval; 500); Instrumentation Systems, LL (297; 0; No set interval; 500);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (8; 8; Annually; 10000); Instrumentation Systems, HL (1; 1; Less than annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (173; 173; Annually; 10000); Instrumentation Systems, LL (54; 54; Annually; 10000); Instrumentation Systems, HL (60; 60; Less than annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, HL (24; 24; Less than annually; 10000); Agitator, HL (2; 0; No set interval; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (41; 41; Annually; 10000); Instrumentation Systems, LL (24; 21; Annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (122; 122; Annually; 10000); Instrumentation Systems, LL (84; 84; Annually; 10000); Instrumentation Systems, HL (12; 12; Less than annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (59; 59; Annually; 10000); Instrumentation Systems, LL (76; 76; Annually; 10000); Instrumentation Systems, HL (1; 1; Less than annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (3; 3; Annually; 10000); Instrumentation Systems, LL (18; 18; Annually; 10000); Instrumentation Systems, HL (2; 2; Less than annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (2; 2; Annually; 10000); Instrumentation Systems, LL (21; 21; Annually; 10000); Instrumentation Systems, HL (4; 4; Less than annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (14; 14; Annually; 10000); Instrumentation Systems, LL (20; 20; Annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (54; 54; Annually; 10000); Instrumentation Systems, LL (114; 115; Annually; 500); Instrumentation Systems, HL (23; 23; Less than annually; 10000); Agitator, LL (2; 2; Monthly; 10000); Agitator, HL (0, 6; sensory; 10000)


fugitive_emission_sources_other_any:
Instrumentation Systems, LL (1; 1; Annually; 10000);


fugitive_emission_sources_other_any:
Instrumentation Systems, GV (14; 0; No set interval; 10000); Instrumentation Systems, LL (12; 0; No set interval; 10000);


fugitive_emission_sources_other_any:
Instumentation Systems GV (80); Instrumentation Systems LL (109)


fugitive_emission_sources_other_any:
Relief valves venting back to the process (spillback)


process_unit_id:
Loading - Rail Rack (Asphalt and Decanted Oil)


process_unit_id:
Other LDAR - Tank Farms, Blending, Loading


process_unit_id:
Fuel Gas Treatment (Unit 2800 Utilities)


fugitive_emission_sources_other_any:
Difficult-to-monitor equipment is included in this count.


fugitive_emission_sources_other_any:
Drains, Junction Boxes, Agigators, Transmitters and Sight Glasses


fugitive_emission_sources_other_any:
Drains, Junction Boxes, Agitators, Transmitters and Sight Glasses


fugitive_emission_sources_other_any:
Drains, Junction boxes, Agitators, Transmitters and Sight Glasses


fugitive_emission_sources_other_any:
Drains, Junction Boxes, Agigators, Tramsmitters and Sight Glasses


fugitive_emission_sources_other_any:
Other includes: Access hatches, drains, drain seals, wastewater vents, clamps, and mixers


fugitive_emission_sources_other_any:
Other could include: Access hatches, drains, drain seals, wastewater vents, clamps, and mixers


process_unit_id:
Sour Water Stripping Unit No. 1 - Sulphur Unit


process_unit_id:
33-Tankage Pipeway & Truck Rack (LPG Loading Ops)


process_unit_id:
33-Tankage Pipeway & Truck rack (Truck Rack)


notes:
Truck rack loading component counts includes components from the loading rack and upstream to the loading rack, including product storage tanks.


# equipment_leak_detection_fuel_gas

fuel_gas_system_id:
#1 MEROX Unit              #2 MEROX Unit                    #3 MEROX Unit


fuel_gas_system_id:
108- SOUR CRUDE / REDUCED CRUDE TANK FARM


fuel_gas_system_id:
A - Fuel gas components are included with data in Table 3-1


fuel_gas_system_id:
Refinery Fuel Gas Collection and Distribution System


fuel_gas_system_id:
Natural Gas Compents based on Fuel Gas Components


notes:
Fuel Gas methane concentration is based on sampling from the refinery fuel gas balance drum, which is supplemented with natural gas.


# equipment_leaks

model_number:
Model: TheraCAM GasFindIR Class I, Div II


model_number:
FLIR Model GasFindIR; Part # 20438-200; Serial Number AS0157


model_number:
Find IR camera Model HSX, Part # 25147-200


# facility_contacts

contact_title:
Health, Safety, Security and Environmental Manager


contact_name:
Casey Frederick, Director, Environmental Affairs


contact_title:
Environmental Engineering Supervisor - Air


contact_name:
Donald Cuffel - Principal Environmental Engineer


contact_title:
Safety & Environmental Compliance Officer


contact_title:
Cracking and Light Ends Permit and Compliance Coordinator


contact_title:
Air Permit and Compliance Coordination Section Supervisor


contact_title:
Environmental Manager Programs and Permits


contact_title:
Director, Health, Safety and Environmental Affairs


# facility_information

legal_owner_name:
BP Exploration (Alaska) Inc., Chevron USA Inc, ConocoPhillips Alaska, Inc., ExxonMobil Alaska Production, Inc.

physical_address:
Section 11, Township 11N, Range 14E, Umiat Meridian (Prudhoe Bay Oilfield)

notes:
Part I - The Crude Oil Topping Plant (COTP) facility is located in the Prudhoe Bay Oilfield and does not have a numeric street address.  The facility also produces Kerosene-type Jet Fuel, but none was produced in 2010.  The facility supports a dynamic oilfield operation and annual production varies from year to year based on oilfield operations. The annual revenue list is for the facility parent company BP America.
                                                                                                                                                                                                                                                        Part II, Section 1 – The COTP facility does not produce electricity on-site or purchase electricity from a metered third party (as indicated on the form EIA-820).  The electricity for the facility is produced at another facility within the oilfield that provides electricity to all of the oilfield facilities in the Prudhoe Bay Oilfield.  

Part II, Section 2 - The average heat input for the process heaters is not monitored for H1, H2, and H4.  Total operating hours are not monitored for H1, H2, and H4.  None of the heaters at COTP have a secondary fuel source.   
                                                                                                                                                                                                                                                       Part II, Section 3 - The facility has access to a thermal imaging camera but does not use it on a routine basis to check for leaks.  The facility does not have any LDAR regulated equipment and all of the equipment counts in Table 3-1, Table 3-2, and Table 3-3 are engineering estimates based on Piping and Instrumentation Diagrams (P&IDs) and facility survey information. The facility does not have any compressor seals.     
                                                                                                                                                                                                                                                       Part II, Section 4 - The quantity of methane used to blanket tank 83-F-1 is calculated based on the standard operating condition that the tank is 50% full of residual crude.  The maximum true vapor pressure for Distillate Fuel Oil, Kerosene-type Jet Fuel, and residual crude oil are not monitored at the facility and the values entered in Table 4-1 were taken from MSDSs. Tanks 83-F-7, 83-F-4 and 83-F-11 are plumbed into a common piping system and product throughput from each tank is not individually metered.  None of the facility tanks have floating roofs.  Only tank 83-F-1 is subject to specific Federal or State air quality regulations.

Part II, Section 5 – Is not applicable to COTP and was intentionally left blank.

Part II, Section 6 – Is not applicable to COTP and was intentionally left blank.

Part II, Section 7 – Is not applicable to COTP and was intentionally left blank.

Part II, Section 8 – Is not applicable to COTP and was intentionally left blank.

Part II, Section 9 – Is not applicable to COTP and was intentionally left blank.

Part II, Section 10 – Is not applicable to COTP and was intentionally left blank.

Part II, Section 11 – All other vents, except the one listed in Table 11-1, are routed to flare F-1.

Part II, Section 12 – Flare F-1 does not have a target assist ratio.

Part II, Section 13 – Is not applicable to COTP and was intentionally left blank.

Part II, Section 14 – Is not applicable to COTP and was intentionally left blank.

Part II, Section 15 - Is not applicable to COTP and was intentionally left blank.

Part II, Section 16 – Part II, Section 16 – The loading throughput is calculated based on the annual capacity of the facility.  The loading rack is open and available to load trucks 24 hours per day, 365 days per year but the facility loads an average of 18 trucks per month.  The loading rack loads tanks owned by the facility owner and 3rd party contractors, but the majority of the tanks belong to 3rd party contractors.

Part III – The facility did not have any recorded non-routine or excess emission events during 2010.

Part IV – The facility is not submitting cost data for air pollution control devices.

Part V – The qualified 2010 CMS excel data file for flare F-1 is included with this database.  The throughput information in the data table represents the daily amount of gas sent to the flare.


energy_management_plan_description:
Performance checklists for projects, fired heater combustion system management program, preventive maintenance and repair program, routine cleaning.

notes:
General Information Notes:  The facility is owned by the following:  ConocoPhillips – 59.3%; BP – 39.2%; Chevron – 5.1%; ExxonMobil – 0.4%.  The number of facility employees reflects the entire oil processing facility; the topping plant itself only requires one operator at a time.  The annual revenue figure represents all of ConocoPhillips US R&M Revenue.

Energy Management Note:  Electricity is "allocated" between divisions of the facility, rather than actually "purchased."

Flare Note:  The facility flare information is not included in this reporting; the topping plant does not vent any vapors to flare during normal operations (rather, the topping plant gas is routed to a fuel gas system where the gas is used primarily for either fuel in an adjacent facility or is reinjected into the producing reservoirs. The only flares on the pad where the topping plant is located service the crude oil processing facility and are located outside the topping plant. As such, we interpret Star Enterprise; Texaco INC. v. USEPA (235 F.3d 139; 2000 U.S. App.LEXIS 31748; 51 ERC (BNA) 1705; 31 ELR 20348) to exclude such processing facility flares from our topping plant.


notes:
Annual revenue given is for all of Petro Star operations.


notes:
Throughout this report, values entered as "-99" represent unknown values, values entered as "-88" indicate that the question asked does not apply to the unit or equipment, and values entered as "-90" represent items that Tesoro considers to be Confidential Business Information (CBI) but the EPA Reporting Tool does not contain a means to report the item as CBI.  

PART I:  In the Process Units tab, the Unit Throughput Capacity and Unit Actual Throughput are marked as “-88” (not applicable) for 0700 – Utilities and the Wastewater Treatment System, as these are not truly production units.   TF – Asphalt production capacity depends on demand, and so that field is input as “-88” as well.  Asphalt is a product of the vacuum unit, thus the Vacuum unit capacity may apply.  Capacity and actual throughput for 0600 – Tank Farm is unknown, and both fields are marked “-99”.  The steam consumption field is not applicable for TF – marine loading, TF – Truck Loading, or the Wastewater Treatment System, and is marked “-88” for those units.  The 2010 total steam consumption for 0600 – Tank Farm and TF – Asphalt is unknown (“-99”).  The Amine Unit capacity is given in terms of the amine circulation rate in gallons per minute, rather than bbl/cd.

PART II:
PART II, Section 1. Energy Management: In the 2010 Fuel Consumption tab, several fuel types, which are not used at the Tesoro Kenai Refinery due to permit requirements, have been entered as “-88.”  In the Electricity and Steam Generation Information tab, several boiler heat input capacities were reported as "-88" to indicate that the boiler is a waste heat boiler, and that no supplemental heat is added to the boiler. The generation units so marked are D-1703, E-1101, E-1102/9, E-1704A, E-1704B, H2U Net Export, and V405. 

PART II, Section 2. Process Heaters: In the General tab for process heater H-704, the number of operating hours at less than 25% of rated capacity and hours operating between 25 and 50% of rated capacity are unknown, and have been entered as “-99”.

PART II, Section 3. Equipment Leaks: In the LDAR tab of both the Process Units subsection and the Gas Systems subsection, the average methane concentration in the process fluid is entered as “-99” for all process units, as this information is not tracked at the refinery.  No equipment leak information has been entered for 0600 – Tank Farm, TF – Asphalt, TF – marine loading, TF – Truck Loading, 0700 – Utilities, or the Wastewater Treatment System, as the LDAR requirements do not apply to these non-process areas.   The "Other" equipment tab (in the LDAR tab of the Process Units subsection) has been filled out to reflect that this section is not applicable to any of the process units.

PART II, Section 5. Catalytic Cracking Units: This section does not apply to the Tesoro Kenai Refinery, and is intentionally left blank.

PART II, Section 6. Fluid Coking Units: This section does not apply to the Tesoro Kenai Refinery, and is intentionally left blank.

PART II, Section 7. Delayed Coking Units: This section does not apply to the Tesoro Kenai Refinery, and is intentionally left blank.

PART II, Section 10. Hydrogen Plant Vent: In the General tab for 1000 – Hydrogen unit, the Reformer Deaerator Vent Flow Rate has been entered as “-99”, because this information is unknown.

PART II, Section 12. Flares: Target assist ratio is not applicable to either of the Refinery’s flares, and therefore has been reported as “-88”.

PART II, Section 13. Fuel Gas Treatment Units: The fuel gas flow rate at treatment unit capacity and the average fuel gas flow rate into the treatment unit are given in terms of the amine circulation rate in gallons per minute, not the fuel gas flow rate (scfm).  No data are available to predict the fuel gas flow rate capacity into Amine Unit.  No data are available to predict the fuel gas total sulfur content (only H2S has been measured), and this has been entered as “-99”.

PART II, Section 15. Wastewater Collection and Treatment: No data exists to calculate the VOC content of the tank water draws nor the VOC and organic HAP concentrations in the wastewater from any process unit.  The code "-99" has been entered in each case in the Facility-Level Questions subsection to indicate that these values are unknown.


energy_management_plan_description:
The 2010 energy plan includes targeted reduction for process heater excess O2 measurements.  In addition, a multidiscipline team was created to identify and evaluate other energy reduction opportunities.   This team meets on a regular basis.

notes:
Refer to the cover letter, "RE: Flint Hills Resources Alaska, LLC North Pole Refinery - Component 1 Information Collection Request (ICR) Response", dated May 31, 2011, that accompanied the database response.  The document attached to the letter is intended to supplement FHR’s answers to Component 1 of the ICR (the “Supplement”).  In the Supplement, FHR provides an explanation of how specific Parts/Sections/Question numbers (“Question Numbers”) were answered by FHR for the ICR.  The explanations may include a discussion of FHR’s specific process and its understanding or interpretation of the question followed by an in depth discussion of the data or information used in FHR’s response to that question.  FHR intends that its electronic responses to Component 1 of the ICR and any accompanying certification of that information be read in conjunction with any information contained in the Supplement.


energy_management_plan_description:
The objective of the Energy Management System at a Unit Level is to understand the longer-term energy trend of the units in order to drive continual improvement.  Implementation of HVGO steam generator,

notes:
All releases that do not include mass quantities were exceedances of concentration permit limits.  Total mass calculations were not required and were not performed.


notes:
Part 3 - Non-Routine Emissions:  The refinery is a minor source of air pollutiants and is not required to monitor emissions.  Therefore, they have no "non-routine emissions".
Part 4 - Cost Data:  The refinery opted not to report cost data.
Part 5 - Emission Testing:  As a minor source of air pollutants, the refinery is not required to perform emission testing.


physical_address:
1855 Fairlawn Road, Tuscaloosa, AL 35401

notes:
Section 1: The output value reported for Distillate Fuel Oil – 15 ppm sulfur and under includes barge fueling. 
The output value reported for Still Gas is in scf. 
The output value reported for asphalt and road oil includes asphalt and cutback asphalt
The throughput capacity value reported for the Coke Pulverizer is in LT/cd
The actual throughput and throughput capacity values reported for the DMS Plant are in LT/cd
The actual throughput and throughput capacity values reported for the Fuel Gas Treatment Unit #1 (#1 Amine Unit) and Fuel Gas Treatment Unit #2 (#2 Amine Unit) are in MMscf/day and gpm, respectively.
The actual throughput and throughput values reported for #1 and #2 Hydrogen Plants are in MMscf/day
The throughput capacity value reported for Sour Water Stripper is in Mgal/day
The unit throughput capacity values reported for the #1 and #2 Sulfur Recovery Unit are in LT/day
The unit throughput capacity value reported for the Wastewater Treatment Plant is in Mgal/day

Section 2-3: The values reported for ‘Crude Unit’ for Pump Seals, Valves, and Flanges & Connectors and for PRDs include those for the Closed Vent System
The values reported for ‘Coker Unit’ for PRDs include those for the Closed Vent System
The values reported for ‘Naphtha Hydrobon Unit’ for PRDs include those for the Closed Vent System
The values reported for ‘Naphtha Hydrobon Unit’ include those for the Closed Vent System
The value reported for #1 MEROX Unit is the aggregate number for MEROX Units #1, #2, and #3
The values reported for 'Coker Unit’ include those for the Closed Vent System
#1 Platformer was shut down in May 2010
# 2 Platformer converted to ISOM Unit in 2010

Section 2-4: Maximum true vapor pressure of hydrocarbons in stored liquid in 2010 is not applicable to Tank ID 101. 

Section 2-7: The typical quench water flow rate during the quenching cycle is not metered. However, maximum flow rate is 2,000 gpm based on pump rating for the Coker Unit
The average quench water make-up rate is not metered. It is normally zero, except for seal flush, at which time it is 7 gpm for the Coker Unit

Section 2-8: the average annual regeneration frequency is continuous for the CCR Platformer
The coke burn-off cycle duration per cycle is reported in units of days for #1 and #2 Platformer Units

Section 2-10: The reformer deaerator vent flow rate is recorded as 2500 lbs/hr for #1 Hydrogen Plant and as 500 lb/hr for #2 Hydrogen Plant

Section 2-12: The Target Assist Ratio is variable to prevent visible emissions for Crude Unit Area Flare, Gas Oil Hydrobon Area Flare, Coker Unit Area Flare, and Hydocracker Area Flare

Section 2-13: The fuel gas flow rate at treatment unit capacity is equivalent to 500 gpm for #1 and #2 Amine Units at the Fuel Gas Treatment Unit

Section 2-15: No test data available for the average concentration of organic HAP or VOC for Crude Unit Desalter, Coker Unit Desalter, Sour Water Stripper, Crude Unit, Merox Unit, Stoddard Unit, Coker Unit, Coker Unit-Crude Draw, Loading Racks
Benzene Concentration for Crude Unit Desalter, Coker Unit Desalter, Sour Water Stripper, Crude Unit, Merox Unit, Stoddard Unit, Coker Unit, Coker Unit-Crude Draw, Loading Racks are from the December 2010 BWON Report

Section 2-16: Products loaded at the Gasoline Truck Rack include Gasoline, Mineral, Spirits, 1K and JetA Kerosenes.
Products loaded at the Diesel/Jet loading rack include Gas Oils, Diesel, and JP-8. 

Section 3: Incinerator Excess Emissions occur for the #1 and #2 Sulfur Recovery Units when the rolling 12 hour average is greater than 250 ppm SO2. 

Section 5: Also have to test No. 2 Sulfur Recovery Unit incinerator for Nox at least once every 5 years (last test 4/28/2010)
Also have to test refinery fuel gas for H2S and analyzer RATA annually (last test 11/18/2010)
Also have to perform VE tests on three asphalt tank vent filter systems at least once every 5 years (last test 6/28/2006 for 6 Tank, 5/5/2009 for 40 Series, and 5/5/2009 for 99 Tank)
Also have to perform CO and Nox testing on Ops Shelter generator at least once every 5 years (last test 6/24/2010)
Also have to perform Nox testing on H-501 at least once every 5 years (last test 4/27/2010)


energy_management_plan_description:
The refinery utilizes good combustion practices for heater and boiler combustion efficiency. Also a condensate return program and recovery of waste heat where it is economical to do so.

notes:
CCR (Continuous Catalyst Regenerator) moves coke laden catalyst continuously from the reformer reactors to the regenerator where the atmosphere changes from a hydrogen rich to slightly oxygenate.  Once the coke has been burned off, the catalyst is then reduced in a hydrogen rich environment and transported back to the Reformer reactors.  The Regenerator consists of a catalyst regenerator zone where the coke burning takes place, a chlorination zone where platinum is re-dispersed and chloride is added, and a flow control system.   Our Regenerator can move approximately 1,675 LB/HR of catalyst and can effectively remove about 100 LB/HR of coke build up on the catalyst.  Unlike a CCR, Semi-Regen units  loads catalyst in a set of reactors and can only regenerate during a unit shutdown.  Our Reformer is always regenerating catalyst and is burning coke continuously.  It takes anywhere from 3-7 days to complete a cycle on our regenerator, therefore we perform approximately 120 cycles per year.  A cycle is defined as the total pounds of catalyst in the system being regenerated once.                                                                                                                                                                                                                                                     Part II - Section 1:  Steam usage information included with Unit No. 7 FCC.                                                                                                                                                                                                                                                      Part V. Monitoring Data ID RFG-N and RFG-S: Redundant CEMS Data for common refinery fuel gas system.


notes:
Table 16-1 Product Loading Information: Both company and non-company trucks are loaded at the CPT-Bulk Loading Facility but the database only allowed either Yes or No but not both responses 

Table 16-1 Product Loading Information: Three (3) petroleum coke loading operations are included P2S8&9(D128), P2S9(D147), and P2S12(D2627) but capacities are not noted on the table because solid material is loaded which is typically presented as tons/day.  The capacity loading throughput in tons/day are 3200, 3200, and 6000 respectively.

Table 12-1: The facility interpreted the request for flare operating hours to include hours that the facility was sending purge gas to the flare

Table 3-1 Equipment and Leak Detection Information for Process Units: CPT is not subject to SCAQMD Rule 1173, however an equivalent monitoring program was established and is in place per Consent Decree with AQMD settled in 1991.

Table 15-3 Wastewater Vent Information: Information regarding the type of controls of any on the drain system vents is not readily available and therefore this field has been left blank.


energy_management_plan_description:
Performing on-the-run furnace maintenance and tuning, ongoing energy project efficiency gains and rebates, cogen efficiency improvements, steam system optimization, improving condensate return, puting power recovery turbines back in service.

notes:
PART I.  GENERAL FACILITY INFORMATION:
•	Flares throughput capacity-- was based on a "relief study" that looked at worst case scenarios with very specific molecular weights of flaring flows.  Data is not readily available for "typical" flaring capacity.  For actual throughput-- Our facility only has mmscf/yr of flaring flow throughput for each flare.  Because we do not flare continuously, this mmscf/yr flaring flow cannot be equally dividided into mmscf/day.  For steam consumption for each flare-- see comments for capacity and actual throughput. For most loading "process units," used a "-99" to denote "unknown" since the loading capacity varies based on actual production capacity at the plant/unit, line diameters, and pump restrictions.                                                                                                                
•	For all the Process Units, all except the following Throughput Capacities and Actual Throughputs are given in bbl/cd (as requested):  
	P12-2H2S (mmscf/day)
	P12-4H2S (mmscf/day)
	P12-5H2S (mmscf/day)
	P12-6H2S (mmscf/day)
	P13-SRU-10 (LT/day)
	P13-SRU-20 (LT/day)
	P13-SRU-70 (LT/day)
	P13-TailGas (LT/day)
	P17-COGEN-A (mlb/hr)
	P17-COGEN-B (mlb/hr)
	P17-COGEN-C (mlb/hr)
	P18-AUXBLR (mlb/hr)

•	For process units that includes various process and/or locations (i.e. Refinery Wide or P12-DEA-H2SPLT-Merox-YDRC), a “-88” not applicable is used as this data is not readily available or applicable to those units/locations.
PART II.  SECTION 5.  CATALYTIC HYDROCRACKER—Process Unit P7-Isomax is a catalytic hydrocracker, but information in this section does not apply to this process unit, therefore this is no information listed.
PART II. SECTION 4.  STORAGE TANKS.  For LPG spheres and ammonium polysulfide tank-- no data available for TVP (only available data is VP).  Since there is no TVP, the "temperature field at which maximum true vapor pressure was calculated" is "-88" or not applicable.  For aqueous ammonia tanks, shape of tanks are "bullet-like" vessels, so even though diameter would be the same as height, it is not a sphere. No place to enter the length of the tank/vessel.  For some LPG spheres, the total throughput was not readily available (i.e. need mass balance on plant/unit).                                                                                                                 
PART II.  SECTION 7.  DELAYED COKING UNIT.  Quench Water section Average Quench Water Make-up Rate (gal/day) is per drum.                                                                                                                       

PART II.  SECTION 8.  CCR.  "coke burn-off cycle duration per cycle" is written as "-88" as not applicable, because facility has a continuous process.                                                                                                                    
PART II.  SECTION 9.  SRUs.  SRU Back-up Controls/Reduction Measure—additional code is 4 for P13-SRU-10, P13-SRU-20, and P13-SRU-70.    
PART II.  SECTION 12.  FLARES.  Data for "typical Lower Heat Value of waste gas (btu/scf at 60F) is given a "-99" unknown, because this data on waste gas is on a high heat value basis, not a low heat value.


notes:
Pt. I – General Facility Information, Question 16:  The Cogeneration Plant is comprised of two Cogenerations Units, but is reported as one.

Energy Management:  The steam consumption for each process unit is an average for a typical year.  The data shown is a net steam consumption/generation since the majority of the process units in the Refinery consume/generate steam.

Equipment Leaks:  Values for Gas Sampling Connections and Liquid Sampling Connections are included in either Pump Seals, Valves or Flanges and Connectors

Catalytic Cracking Unit:  CCU data requested is only applicable to the FCC process unit.  No information was listed for TKN/ISO process unit.

Fluid Coking Unit:  The Chevron Richmond Refinery does not have a fluid coking unit or a delayed coking unit.

Hydrogen Plant Vent:  Methanol emissions based on source test results.  A Train = 0.006 lbs per day, B Train = 0.0005 lbs per day

Flares:  D&R Flare is out of service.

Fuel Gas Treatment:  No speciation on sulfur compounds other than H2S.

Wastewater Treatment & Collection:  The following are number of components that make up part of the Wastewater Collection and Treatment:

Drains – 2,419
Catch Basins - 2,724
Manholes – 915
Junction Boxes – 31
Cleanouts – 862

These items are listed as one line items in the ICR tool.

Loading Operations:  The refinery has an additional Berth, Berth 4 which is only used for unloading crude oil to tanks.  This Berth was not included in this ICR since no material is loaded at this location.  Berth 1, Berth 2, Berth 3, Berth 9 & Berth 11 capacity is actual quantity loaded + 40% of actual quantity loaded.

Non Routine Emissions: Process Unit is unknown for flaring events dated: 5/7/10, 5/10/10, 7/19/10, 10/18/10, 10/19/10, 10/28/10, 10/29/10, 12/10/10, 12/12/10 and  12/17/10.  The duration of spills was not reported due to not readily available.  For spills dated 1/16/10, 3/5/10, 5/6/10, and 10/20/10 were not associated with a process unit.

Part V – Log of Source Tests and Monitoring Data Provided – No. 22 Boiler NOx CEMS includes Boilers 1, 3, 4, 5, 7 CEMS data.


legal_address:
6451 Rosedale Highway, Bakersfield, CA 93308

notes:
Part 1 Facility info question 16: 
The refinery temporarily suspended crude oil refining in 2008.  Since that time the refinery has undergone a sale to Alon in June 2010, a maintenance turnaround, and integration with Alon’s refinery in Paramount, California.  For these reasons, throughput in 2010 is indicated as 0, or very low for those units that did run for part of the year. No estimate is provided for ‘expected normal 2010 operations’ because the “new” normal or expected operating parameters have not been experienced.   

Unit S-34-20-6 petroleum coke storage. Capacity is represented in Lt Tons/day

Units S-33-49-7 and S-33-54-1 (Atmospheric Crude distillation and Vacuum distillation, respectively) has been out of service with no plan to bring back into service. The capacity of these units is therefore zero. 

Unit S-34-1-13 and unit S-34-2-12 (atmospheric crude distillation and vacuum distillation respectively) are and have been out of service with no plan to bring back into service. The capacity of these units is therefore zero. 

PART II, SECTION 1. ENERGY MANAGEMENT
TABLE 1-1. 2010 Fuel Consumption
Due to change in ownership of this refinery in June of 2010 many of the natural gas invoices are unavailable for those months prior to June. The natural gas usage is an approximation based on the known usage during June 2010 – December 2010, and those invoices that were available from Pre-June. 

PART II, SECTION 3.  EQUIPMENT LEAKS 
TABLE 3-1.  Equipment and Leak Detection Information for Process Units
S-33-2-6, S-33-370-1, S-33-371-1, S-34-25-4, S-34-26-4, S-34-27-3 and S-33-401-1– components for these racks were unknown. Estimation was made based on the component count of another rack, and the ratio of the number of loading hoses. 

Note: the counts for 'other' include both the drains and 'other' category from LeakDas for all services, including heavy liquid for those that have the counts available

For those loading racks listed that have a count of 0 pumps, it is because pumps are typically considered part of the tank farm component count. For these purposes tanks are not a process unit, and therefore these components are not accounted for. 

Units S-33-2-6, S-33-49-7, S-33-54-1, S-34-1-13, S-34-2-12 are out of service. Component counts are unavailable. 

Gas sampling connections are zero for every unit because these are accounted for in the ‘valves’ count.

PART II, SECTION 8.  CATALYTIC REFORMING UNITS 
TABLE 8-1. Catalytic Reforming Unit Information
Average Annual Regeneration Time (hours/year) and Coke Burn-off Cycle Duration per Cycle
A zero is entered here for all catalytic reforming units because the catalyst is sent off and regenerated off-site. 

Unit S-33-52-14 has no information listed because at this time it is planned to remain shut down. 

PART II, SECTION 10.  HYDROGEN PLANT VENT
TABLE 10-1.  Hydrogen Plant and Vent Information
Steam Generation Rate (lb/hr)
The hydrogen generation unit has an amine unit for CO2 removal in addition to a methanator, so all steam that is produced is consumed. The total sum of steam produced is entered here, however all of the steam is consumed by the unit and there is no steam production for use in other units.
 
The steam balance on the HGU is:

Producers: Process waste heat boiler, Flue Gas waste heat boiler, Shift Converter waste heat boiler.  Consumers of steam are Process Feed Steam, Furnace ID Fan, and the Amine regenerator.  When the unit is at full production, the producers and consumers balance out, and there is no net steam production.  The sum of the producers and the sum of the consumers are each 100,000 lb/hr at full rates.  

PART II, SECTION 15.  WASTEWATER COLLECTION AND TREATMENT
TABLE 15-2.  Wastewater Generation Information
The units listed here are those units that routinely generate wastewater. The facility was down in 2010 and therefore these streams did not have a flowrate. The typical flowrate and benzene concentration for these streams is unknown due to the process changes the facility has undergone in preparation for 2011 startup.  

PART III. NON-ROUTINE EMISSIONS
The events listed in this table were reported as emissions incidents, however the calculated emissions for each of these events is less than 1 pound.


legal_owner_name:
Equilon Enterprises LLC (dba Shell Oil Products US)

energy_management_plan_description:
Maintain a 5yr GHG & energy plan, implement GHG & energy management option to achieve set targets. Project activity ongoing.

notes:
NOTES for ICR – Component 1
Part 1 -General Section – Annual revenue – this is for the company listed as the legal owner
Part 1 Process Units – Unit Throughput Capacity – this is our Title V permit limit for the process unit where there is one.  
Part 1 Process Units - Steam Consumption – this is the net steam consumption for each unit
Part 1 Process Units – DCU Coke Loading capacity and throughput are in tons/cd and not bbl/cd; all other process units have units as described on the tool.
Part 1 Process Units – “Utilities”, “SWS” and “Tanks” included here for use in Section 3 - Equipment Leaks and Section 15 – Wastewater Section.  Capacity and throughput information not really applicable.

Part II Sections 1 and 2 – Energy Management and Process Heaters - Heat capacities listed in Higher Heating Value (HHV)
Part II Section 1 Table 2 – Electricity and Steam Generation Information – provided % blowdown to steam not % steam to blowdown
Part II Section 2 – Process Heaters- the two heaters listed as “balanced draft” can also operate on natural draft without the air preheater
Part II Section 7 - DCU –Quench water flow rate:  Quench water flow ranges from [CBI] over quench time with average of [CBI]
Part II Section 15(a) – Several of each WWTU type are grouped under each WWTS (e.g. there are 3 oil-water separators included under the WWTU type: Oil Water Separator).  Some of the units are subject to the full BWON and some are subject to BWON but exempt from control requirements so both are listed as applicable.
Part II Section 16 – Loading – Provided 2010 throughput for “Capacity loading throughput”.  T	ypical annual operating hours provided for loading operations only since unloading emissions are captured at the receiving tank.  

Part V CEM Data – the CEM data is provided on a dry basis. We have chillers on the sample lines to knock out condensate before the sample reaches the analyzer.


notes:
General Comments

Per EPA’s suggestion, Tesoro Los Angeles Refinery has elected to use “-99” to indicate “unknown”.  The following codes were also used in the ICR databases: 

-70 = See Notes section in database
-88 = Not applicable
-90 = Confidential Business Information (CBI)
Where Tesoro has determined that a drop-down field is entitled to confidential treatment, Tesoro has intentionally left that drop-down field blank in its Non-CBI submittal, i.e., Database Version 3, to reflect CBI claim.  

Additionally, the Sulfur Recovery Plant and the Long Beach Marine Terminal are not part of the refinery because Tesoro considers these as separate facilities.  However, information for these facilities was included in Tesoro’s response to this ICR under Unit IDs SRU300, SRU600, SRU700, SRU750, SRP Fuel Gas Treatment (V-1256), Liquid Sulfur Tank Truck Loading and LBT (Long Beach Marine Terminal).  The Sulfur Recovery Plant and Long Beach Marine Terminal have their independent Title V permits.

1.	 Part I, General Facility Information, Annual revenue in 2010

Tesoro Response:  Tesoro has provided the total combined annual revenue for all of its facilities in operation in the USA. 

2.	 Part I, Process Units, Unit ID Bensat1  

Tesoro Response:  Process Unit ID Bensat was originally created but had an issue and could not be deleted since it didn't show up on the drop down menu.  Tesoro re-created it as Bensat1.  It is acceptable to delete process unit ID Bensat.

3. Part I, Process Units, Unit ID Other Non-Process Units For Equipment Leak Reporting  

Tesoro Response:  The unit ID “Other Non-Process Units For Equipment Leak Reporting” was created to include Equipment Leak data related to tanks and other process areas that are not covered by the Process Units.  Therefore, there are no throughput capacity, throughput actual or steam consumption values reported.


4. Part I, Process Units, Unit ID Coke Loading  

Tesoro Response:  The coke loading throughput capacity and throughput actual numbers are reported in tons per calendar day.

5.	  Part I, Process Units, Process Type Product Loading

Tesoro Response:  The loading throughput capacity and loading actual throughput values reported are only loading values.  This is the case for Process Unit IDs: LBT (Long Beach Marine Terminal), Liquid Sulfur Tank Truck Loading, Spent Caustic Rail Car Loading, LPG Rail Car Loading, LPG Tank Truck Loading, Coke Loading, and Fresh and Spent Acid Tank Truck Loading.

Additionally, the loading throughput capacity represents Tesoro’s best estimate based on the presently available information and may not be construed as the maximum feasible operation of the unit.  These values were estimated with the assumption that loading operations took place 24 hours per day, which may not be operationally feasible.  This estimate may be adjusted should new information become available.  

6.	  Part I, Process Units, Process Type Fuel Gas Treatment  

Tesoro Response: For fuel gas treatment, throughput is defined as the quantity of fuel gas input to the unit. Throughput units are million standard cubic feet per calendar day.

7.	  Part I, Process Units, Steam Consumption For The Processing Unit in 2010 (tons/yr)  

Tesoro Response: The steam consumption values provided are design numbers and not actual steam consumption.  Tesoro does not have meters at each process unit.    

8.	  Part II, Section 1, Energy Management, Electricity and Steam Generation Information  

Tesoro Response: The Percent to Blowdown is unknown, entered as -99 in the database, for the following Generation Unit IDs: H-1601, H-1602, and H-43 Boiler.

9. Part II, Section 2, Process Heaters, Rated Heat Input Capacity (MMBtu/hr)

Tesoro Response:  The rated heat input capacity reported excludes pilot gas heat input.  

10. Part II, Section 2, Process Heaters, Average Heat Input Rate in 2010 (MMBtu/hr)

Tesoro Response:  The average heat input reported excludes pilot gas heat input. 

11.	  Part II Section 2, Process Heaters, Process Heater ID B-1 (start-up heater)  

Tesoro Response:  Process Heater ID B-1 (start-up heater) is an air preheater, therefore, the “Air preheat use” question is left blank for this heater.  Also, the “Typical air preheat temperature when used” was entered as -88 for this heater.

12.	  Part II, Section 3, Equipment Leaks, “Average Methane Concentration In Process Fluid That Contacts Equipment In Gas Service Throughout The Process (ppmv)”

Tesoro Response:  The average methane concentration will vary significantly across the plant and cannot be estimated. Tesoro does not monitor methane concentration at the facility.

13.	  Part II, Section 3, Equipment Leaks, “Is The Average Methane Concentration Based On Sampling And Analysis Results Or Estimated (e.g., Based On Process Knowledge)”

Tesoro Response:  The average methane concentration will vary significantly across the plant and cannot be estimated.  Tesoro does not monitor methane concentration at the facility.

14.	  Part II, Section 3, Equipment Leaks, Open-Ended Lines

Tesoro Response:  For purposes of this response, Tesoro will define “open ended line” as it is defined in the NSPS.  Under NSPS, open-ended line (“OEL”) “means any valve, except safety relief valves, having one side of the valve seat in contact with process fluid and one side open to the atmosphere, either directly or through open piping.” Throughout 2010, Tesoro had no equipment designed or operating as an OEL. For regulated valves that are otherwise open to the atmosphere, Tesoro meets the NSPS by applying a cap, blind flange, plug, or second valve, which effectively changes the design to no longer meet the OEL definition. If the cap, blind flange, plug, or second valve is found to not be properly installed, the refinery takes steps to replace it. 

15.	  Part II, Section 3, Equipment Leaks, Unit IDs SRU300, SRU600, SRU700, SRU750, SRP Fuel Gas Treatment (V-1256), Liquid Sulfur Tank Truck Loading  

Tesoro Response: All Sulfur Recovery Plant equipment leaks are reported on Unit ID SRU300.  Therefore, Tesoro has reported in its response to the ICR 0 for Unit IDs SRU600, SRU700, SRU750, SRP Fuel Gas Treatment (V-1256), and Liquid Sulfur Tank Truck Loading.  The reported values are for the entire Sulfur Recovery Plant, which includes all four SRUs, the fuel gas treatment, and liquid sulfur tank truck loading reported in this ICR, in addition to other units.  

16.	  Part II, Section 3, Equipment Leaks, Unit IDs DCU (Atmospheric Distillation), DCU (Vacuum Distillation), DCU (Delayed Coking), DCU Fuel Gas Treatment

Tesoro Response: All DCU equipment leak data is reported under Unit ID DCU (Atmospheric Distillation).  Therefore, Tesoro has reported in its response to the ICR 0 for Unit IDs DCU (Vacuum Distillation), DCU (Delayed Coking), and DCU Fuel Gas Treatment.  

17. 	 Part II, Section 3, Equipment Leaks, Unit IDs HCU Fuel Gas Treatment (V-1011), HCU Fuel Gas Treatment (V-1621)

Tesoro Response: All Hydrocracker (HCU) equipment leak data is reported under Unit ID Hydrocracker.  Therefore, Tesoro has reported in its response to the ICR 0 for Unit IDs HCU Fuel Gas Treatment (V-1011) and HCU Fuel Gas Treatment (V-1621).  

18. Part II, Section 3, Equipment Leaks, Unit ID FCCU Fuel Gas Treatment

Tesoro Response: The Equipment Leak data for the FCCU Fuel Gas Treatment is reported under Unit ID FCCU Equipment Leak data.

19.	  Part II, Section 3, Equipment Leaks, Unit ID HTU4 Fuel Gas Treatment

Tesoro Response:  The Equipment Leak data for the HTU4 Fuel Gas Treatment is reported under Unit ID HTU4 Equipment Leak data.

20.	  Part II, Section 3, Equipment Leaks, Fuel Gas Systems

Tesoro Response:  The LDAR values for the Fuel Gas System are included in the LDAR counts for each Process Unit.  The Fuel Gas System counts are not separated out in our LDAR database.

21.	  Part II, Section 4, Storage Tanks, General Information

Tesoro Response:  Tesoro has not included information for spheres or pressurized tanks used for storage of compressed Propane and Butane.

Additionally, Tesoro has listed out of service tanks, but has not provided information since they were out of service. 

22.	  Part II, Section 4, Storage Tanks, Maximum True Vapor Pressure Of Hydrocarbons In Stored Liquid In 2010 (psi)

Tesoro Response:  The true vapor pressure (“TVP”) reported applies to the material stored in 2010 only and tanks may be capable of storing higher TVP materials.

Additionally, for its response, Tesoro is reporting the average TVP for its external floating roof with geodesic dome roof tanks because EPA's Tanks 4.09 database does not provide a maximum TVP.

23.	  Part II, Section 4, Storage Tanks, Total Throughput For All Materials Stored In The Tank In 2010 (bbl)

Tesoro Response:  Tesoro’s tank throughput is based on change in tank levels as used in Emissions Inventory Calculations. 

24.	  Part II, Section 5, Catalytic Cracking Unit, 2010 Weighted Average Sulfur Concentration In Combined Feed (wt%) 

Tesoro Response: The weighted average sulfur concentration value reported for Unit ID FCCU was calculated using lab results for the last 6 months of 2010.

25. 	 Part II, Section 5, Catalytic Cracking Unit, 2010 Weighted Average Nickel Concentration In Combined Feed (wt%) 

Tesoro Response: The weighted average nickel concentration value reported for Unit ID FCCU was calculated using lab results for the last 6 months of 2010.

26. Part II, Section 5, Catalytic Cracking Unit, 2010 Weighted Average Vanadium Concentration In Combined Feed (wt%) 

Tesoro Response: The weighted average vanadium concentration value reported for Unit ID FCCU was calculated using lab results for the last 6 months of 2010.

27.	  Part II, Section 5, Catalytic Cracking Unit, Unit ID Hydrocracker

Tesoro Response: Tesoro did not provide a response to Section 5 for Unit ID Hydrocracker since the questions in this section were geared towards a Fluid Catalytic Cracking Unit.  

28.	  Part II, Section 7, Delayed Coking Unit, Coke Drum Depressurization Vent Time (hr)

Tesoro Response:  Tesoro interprets this to mean the input average time to depressure the drum from when the vent is opened to when the drum pressure reaches atmospheric pressure.

29.	  Part II, Section 8, Catalytic Reforming Unit, Operating Pressure (psig) 

Tesoro Response:  Tesoro is reporting the average reactor pressure, which is defined as (lead reactor inlet pressure + lag reactor outlet pressure) ÷ 2

30.	  Part II, Section 8, Catalytic Reforming Unit, Coke Burn-off Cycle Duration Per Cycle 

Tesoro Response:  Tesoro is reporting the Coke Burn-off Cycle Duration Per Cycle in hours per cycle.

31.	  Part II, Section 12, Flares, Typical Lower Heating Value Of Waste Gas (Btu/scf @ 60 °F) 

Tesoro Response:  The typical lower heating value of waste gas for all flare IDs (Flare 1, Flare 2, and SRP Flare) reported is the average.  

32.	  Part 2, Section 15, Wastewater Collection and Treatment, Average Wastewater Generation Rate (gallons/operating day), Unit IDs DCU (Atmospheric Distillation), DCU (Vacuum Distillation), DCU (Delayed Coking) 

Tesoro Response:  The Average Wastewater Generation Rate for the DCU is reported under Unit ID DCU (Atmospheric Distillation) and is the total for all of the following DCU Unit IDs: DCU (Atmospheric Distillation), DCU (Vacuum Distillation) and DCU (Delayed Coking).  Therefore, Tesoro has reported in its response to the ICR 0 for Unit IDs DCU (Vacuum Distillation) and DCU (Delayed Coking).

33.	  Part 2, Section 15, Wastewater Collection and Treatment, Average Wastewater Generation Rate (gallons/operating day), Unit IDs SRU300, SRU600, SRU700, SRU750 

Tesoro Response:  The Average Wastewater Generation Rate for the SRUs is reported under Unit ID SRU 300 and is the total for all of the following Unit IDs: SRU300, SRU600, SRU700, and SRU750.  Therefore, Tesoro has reported in its response to the ICR 0 for Unit IDs SRU600, SRU700, and SRU750.

34.	  Part 2, Section 15, Wastewater Collection and Treatment, Average Wastewater Generation Rate (gallons/operating day), Unit IDs Fuel Gas Treatment (V-1640), Fuel Gas Treatment (V-598)

Tesoro Response:  The Average Wastewater Generation Rate for the Fuel Gas Treatment is reported under Unit ID Fuel Gas Treatment (V-1640) and is the total for all of the following Unit IDs: Fuel Gas Treatment (V-1640) and Fuel Gas Treatment (V-598).  Therefore, Tesoro has reported in its response to the ICR 0 for Unit ID Fuel Gas Treatment (V-598).

35.	  Part 2, Section 15, Wastewater Collection and Treatment, Average Benzene Concentration (ppmw), Unit IDs DCU (Atmospheric Distillation), DCU (Vacuum Distillation), DCU (Delayed Coking) 

Tesoro Response:  The Average Benzene Concentration for the DCU is reported under Unit ID DCU (Atmospheric Distillation) and is the total for all of the following DCU Unit IDs: DCU (Atmospheric Distillation), DCU (Vacuum Distillation) and DCU (Delayed Coking). Therefore, Tesoro has reported in its response to the ICR 0 for Unit IDs DCU (Vacuum Distillation) and DCU (Delayed Coking).  

36.	  Part 2, Section 15, Wastewater Collection and Treatment, Average Benzene Concentration (ppmw), Unit IDs SRU300, SRU600, SRU700, SRU750 

Tesoro Response:  The Average Benzene Concentration for the SRUs is reported under Unit ID SRU 300 and is the total for all of the following Unit IDs: SRU300, SRU600, SRU700, and SRU750.  Therefore, Tesoro has reported in its response to the ICR 0 for Unit IDs SRU600, SRU700, and SRU750.

37.	  Part 2, Section 15, Wastewater Collection and Treatment, Average Benzene Concentration (ppmw), Unit IDs Fuel Gas Treatment (V-1640), Fuel Gas Treatment (V-598)

Tesoro Response:  The Average Benzene Concentration for the Fuel Gas Treatment is reported under Unit ID Fuel Gas Treatment (V-1640) and is the total for all of the following Unit IDs: Fuel Gas Treatment (V-1640) and Fuel Gas Treatment (V-598).  Therefore, Tesoro has reported in its response to the ICR 0 for Unit ID Fuel Gas Treatment (V-598).

38.	  Part II, Section 15, Wastewater Collection and Treatment, Average Concentration Of Organic HAP (ppmw)

Tesoro Response:  Tesoro has not analyzed average concentration of organic HAP (ppmw) and does not have a good method for estimating the value.  As a result, Tesoro has entered -99, code for unknown, in the database.

39.	  Part II, Section 15, Wastewater Collection and Treatment, Average VOC Concentration (ppmw)

Tesoro Response:  Tesoro has not analyzed VOC concentration (ppmw) and does not have a good method for estimating the value.  As a result, Tesoro has entered -99, i.e., code for unknown, in the database.  

40.	  Part II, Section 16, Product Loading Operations, Capacity Loading Throughput (gal/yr)

Tesoro Response: The loading throughput capacity represents Tesoro’s best estimate based on the presently available information and may not be construed as the maximum feasible operation of the unit.  These values were estimated with the assumption that loading operations took place 24 hours per day, which may not be operationally feasible.  This estimate may be adjusted should new information become available.  

41.	  Part II, Section 16, Product Loading Operations, Typical Annual Operating Hours (hr/yr)  

Tesoro Response: The typical annual operating hours vary year to year.  As a rough estimate, Tesoro assumed loading for 12 hours a day to generate the typical annual operating hours.  This value may not be construed as the actual operating hours.  This estimate may be adjusted should new information become available. 

42.	  Part II, Section 16, Product Loading Operations, Unit ID Coke Loading  

Tesoro Response: Section 16 asks for capacity loading throughput to be reported in gallons per year.  Tesoro reported capacity throughput for Unit ID Coke Loading in tons per day in Part I, Process Units.  In order to obtain an estimated annual loading capacity, multiply the capacity throughput value provided in Part I, Process Units, Unit ID Coke Loading by 365.  Also refer to Tesoro’s Note’s section on throughput capacity for loading operations.  

43.	  Part III, Non-Routine Emissions

Tesoro Response:  Tesoro will meet this requirement by submitting all agency reportable emissions that occur during periods of startup/shutdown and component malfunction for the year 2010.

44.	  Part V, Emissions Monitoring and Source Test Data, Qualified CEMS Data

Tesoro Response:  Tesoro has submitted data for all CEMS that fall under the purview of Federal regulations.  Continuous monitors required by state agencies that do not meet federal CEMS testing and compliance assurance requirements are not included in Tesoro’s ICR


notes:
•	Part I, Facility Information, Question 11: basis is U. S. Downstream (Refining and Fuels/Lubes Marketing) earnings after income tax
•	Part II, Section 1, Question 4: 
ExxonMobil’s energy management system for Downstream and Chemical operations, entitled Global Energy Management System, or GEMS, utilizes international best practices and benchmarking to identify energy efficiencies at our refineries and chemical plants.  The system utilizes a common methodology to identify and close performance gaps, sustain progress, and drive plants toward leading-edge energy performance.  Since 2000, we have used GEMS to systematically identify and address operational efficiency opportunities. We have identified ways to improve energy efficiency at our refineries and chemical plants by 15 to 20 percent and have captured over 60 percent of these opportunities to date.

GEMS is based on a three-step approach to performance improvement:
• Address base case performance opportunities by operating existing facilities optimally and efficiently through application of best practices.
• Identify economic investment opportunities above an optimized base for step-change improvement to address structural differences.
• Implement strong management systems to provide the rigor and discipline necessary to sustain progress and drive continuous improvement.

GEMS is a layered approach to energy management.  It starts with the identification of key energy variables and establishes targets for safe, reliable, energy-efficient operations.  Secondly, diagnostic indicators focus on system health and implementation of
improvement plans.  A key measure is “lost opportunity”, which is the economic value of the gap between a key energy variable and its target value.  Monetizing gaps helps prioritize work and focus resources.  And finally, Global Measures summarize bottom 
line performance for corporate and plant management. 

As part of the energy management process ExxonMobil conducts GEMS Assessments at sites to deliver best practices and measures.  The Assessment progresses through three stages:
• It takes several months to prepare for a GEMS Assessment.  A key step is selection of a team of technical specialists from across the global organization and plant personnel familiar with local operations and practices.
• Execution of the Assessment can take anywhere from a couple of weeks to a couple months depending on site size and complexity.  During the assessment the team looks at process units, major equipment, and utilities systems to identify gaps.  The team
also looks at plant configuration to identify project opportunities such as advanced controls and optimization, heat integration, and waste heat recovery projects.
• The Assessment deliverables include gap-closing options and a cost/benefit analysis for each item identified in the gap assessment.  A multi-year plan is then established that balances the portfolio of operational improvement and facilities enhancements 
along with other business and investment needs.  All ExxonMobil refineries in the U.S. are in the GEMS program, and the initial energy management Assessments were performed a number of years ago.  Our sites are now in the implementation phase of
this process.  
•	Part II, Section 1, Table 1-2, Column-“Percent Steam to Blowdown”: Note: steam is not sent to blowdown. % reported is condensate to blowdown.
•	Part II, Section 2, Table 1-3, Column-“Steam consumption for the processing unit in 2010 (tons/yr)”:
U01-Crude	75# Steam = 117,597; 
175# Steam = 104,832; 
450# Steam = 8,103
U01-Vacuum Tower	175# = 270,379
U21-NCoker	450# steam = 12,760; 
175# steam = 12,536
U22-Scoker	450# steam = 8,307;
175# steam = 17,449
U02-FCC	1200# Steam = 886,536
450# Steam = 5,605
175# Steam = 204,705
U03-HDC	175# = 35,040 ;
450# = 218,835
U19-PTR	175# = 26,280;
450# = 32,850
U04-H2Plant1	45# = 31,750
175# = 236,520
450# = 616,251
U24-H2Plant2	55# Steam = 82,744; 
175# Steam = 27,528; 
450# Steam =  1,088,021; 
1200# Steam =  1,269,909
U05-Alky	450# = 328,171;
175# = 337,835;
45# = 457,856
U20-PrTr	450# = 66,648
U06-CHD	0
U25-HDT	55# Steam = 42,165; 
175# Steam = 93,257; 
450# Steam = 313,875
U29-TrainA	45# Steam = 229,715; 
55# Steam = 59,557
U29-TrainB	45# Steam = 207,220; 
55# Steam = 47,534
U50-ResidLoad	0
U52-LPGLoad-Rail	0
U52-LPGLoad-Truck	0
U51-GasLoad	0
U55-WOM	0
U07-SatGas	175# Steam = 37,014;
450# Steam = 273,424
U08-UnsatGas	1200# Steam = 388,937
175# Steam = 3,060)
•	Part II, Section 4, Storage Tanks, Column “Minimum height of floating roof above the floor at the shell when landed”: units are in ft. estimated between 4’-8’
•	Part II, Section 5, Cat Cracking Unit, Column-“2010 Weighted Average Nickel Concentration in Combined Feed (wt%)”: Value is <0.00001.
•	Part II, Section 5, Cat Cracking Unit, Column-“2010 Weighted Average Vanadium Concentration in Combined Feed (wt%)”: Value is <0.00001.
•	Part II, Section 7, Table 7-1, Column- “Coke Production Capacity (tons/cd)”: Value is in short tons/day.
•	Part II, Section 9, Table 9-1, Column – “Primary Sulfur Pit Maintenance Time in 2010 (hr/yr)” Basis is hours of pit maintenance with vent emissions.
•	Part II, Section 12, Table 12-1, Column “Typical Lower Heating Value of Waste Gas (Btu/scf @ 60°F)”: Values reported are HHV, we do not track LHV.
•	Part II, Section 12, Table 12-1, Column- “Flare Management Plan” Site is not subject to any Flare Management Plan requirements but is providing the information per EPA's list of comments.
•	Part II, Section 13, Table 13-1, Column “Fuel Gas Treatment Unit ID” Note:  
	All three gases combine in the main refinery fuel mix drum.
	A slipstream of 8C-5 can be used as fuel in U24 H2 Plant reforming heater. 
	A slipstream of FGT vent gas is sent to U30 boilers and U24 Gas Turbine Generator (GTG).
•	Part III, Non-Routine Emissions, Event- “8K-2 Trip” on 5/12/2010:  The non-routine emissions from the trip of compressor 8K-2 were opacity >20% for approximately 23 minutes.  Opacity has no EPA CAS # and could not be reported in EPA’s database..
•	Part III, Non-Routine Emissions, Events- “4/19-7K-2 Shutdown, 5/12-Planned UnsatGasplant Startup, 5/18-Planned Alky Startup, 6/12-HDC Pump Shutdown, 11/10-7K-2 Shutdown”:  Please note these startup and shutdown events were allowable emissions and did not violate any emission standards.


energy_management_plan_description:
Produced oilfield gas is used as much as possible to provide fuel to the heaters and boilers.


legal_owner_name:
Valero Refining Company – California, a Delaware corporation

name_of_parent_company:
Valero Energy Corporation, a Delaware corporation

notes:
Facility Information 1-Question 1 through16:
1.FacilityInformation.Question11 – Annual revenue is readily available through other sources

Process Heaters – 2-2:
2.2. 399-H-4 serves all loading operations at the facility (Asphalt Tank Truck and Railroad Car Loading)

Fuel Gas Treatment 2-13:
2.13. This unit serves both crude and vacuum distillation units (399-T-1 and 399-T-2).

Loading Operations – 2-16:
2.16. The capacity throughputs are based on permit limits.

2.16. For Gas Oil/Naphtha loading there are no controls for gas oil.  There is VRU and incineration for naphtha.
         
Emission Monitoring and Source Test Data 5-1 through 5-5
5.4. Wilmington refinery does not have any biological treatment unit; therefore, no biodegradation rate test or complete mixing test is performed.

5.5. No ambient and remote sensing test was conducted around the refinery on or after January 2000. 

5.6. Facility does not use any site-specific correlations for equipment leaks.


notes:
This facility does not have any catalytic cracking units, fluid coking units, nor delayed coking units.


plant_name:
ConocoPhillips Los Angeles Refinery Carson

energy_management_plan_description:
The refinery has an evergreen Energy Plan which includes energy reduction projects which the facility intends to complete.  See the notes field for the full description.

notes:
-99 in numeric field indicates information is unavailable, unknown, or not applicable

SCAQMD - South Coast Air Quality Management District

Part 1 Annual revenue in 2010 ($): Annual Revenue figure for 2010 represents ConocoPhillips U.S. Refining and Marketing operations

Part 1 Degree of independence from parent company: Although this question is somewhat incomprehensible to ConocoPhillips  in that the "facility" does not have a Board of Directors and for other reasons, we believe that this statement "best" applies to the three statements offered

Part 1 Products Produced: EIA 810 reports LARC and LARW refinery production combined.  Production is reported by each Refinery based on the location of the ultimate product disposition.

Part I-Process Units: Actual 2010 steam consumption is provided, not consumption at capacity

Part 1 Process Units: Steam consumption for the H2Plant includes DHT steam consumption

Part II-Section 1: The text field for describing the energy management plan was limited so the full description of the plan is included here: The refinery has an evergreen Energy Plan which includes energy reduction projects which the facility intends to complete.  It also includes any operational practice improvements which the facility intends to implement.  The facility has ongoing energy reduction/ optimization programs as follows: 1) Program to monitor and optimize excess oxygen in process heaters and boiler, 2) Program to monitor and optimize fuel gas usage, 3) Program to test and repair facility steam traps, 4) Program to identify and repair steam leaks, 5) Program to monitor pump operation for motors vs steam turbines operation (vent to atmosphere) and expedite repairs, 6) Program to review and ensure new projects for energy efficiency, 7) Program to monitor facility heat exchangers and clean for improved heat recovery.

Part II-Section 1: Emergency ICE (internal combustion engine) driven electricity generators are included in this section.  The generation unit ID assigned to these generators have ICE included in the unit ID.

Part II-Section 3: Table 3-2.  Equipment and Leak Detection Information for Fuel Gas and Natural Gas Systems was left blank because this table accounts for FG/NG systems not captured in process units in Table 3-1 and all FG/NG system components were captured in Table 3-1. / Tables 3-1 and 3-3: The component numbers listed are based on the definitions of gas, light liquid, and heavy liquid defined in local regulation SCAQMD Rule 1173 / Table 3-1: Open ended lines were estimated based on an estimate of cap and plug components (i.e. not actual open ended lines but lines with caps or plugs) / Table 3-1: No number of pieces of equipment monitored, monitoring frequency, or leak definition is provided for open ended lines because these equipment leak components (i.e. caps or plugs) are included in the numbers provided for flanges and connectors 

Part II-Section 7:  The coke drum height is tangent to tangent and outage and water heights are from the top tangent and bottom tangent respectively / For Coke Drum Depressurization Vent Time (hr) the time reported includes the entire depressuring time and not only the  atmospheric venting period

Part II-Section 10: Deaerator vent flow rate was determined from source test data and is on a dry basis

Part II-Section 13: Fuel gas flow rate at treatment unit capacity represents both fuel gas flow and process gas flow to treatment unit in some cases.  Average fuel gas rate into the treatment unit includes only the fuel gas rate and does not include the process gas rate.

Part II-Section 13: For the Coker Amine Contactor the average fuel gas flow rate into the treatment unit figure provided is flow out of the treatment unit because this is where flow is meatured.

Part II-Section 13: The estimated annual average H2S concentration in the treated fuels gas exiting the treatment unit figures for the HDT/Recovered Fuel Gas Amine Contactor, DHT-3 Amine Contactors HP-275 and HP-276, and H2 Plant Amine Contactor are based on data for the blended fuel gas system.  The figures for the Coker Amine Contactor and Flasher Amine Contactor are anticipated to be 0 but there are no samples available to verify. 

Part II-Section 15: Wastewater flow is estimated from data related to 40 CFR 61 Subpart FF (BWON) and previous water studies / Benzene concentration estimated from 40 CFR 61 Subpart FF (BWON) TAB data / Sour Water Stripper effluent flow is included in the SRU Unit ID / Organic HAP and VOC is estimated using Table 7-8 of the emissions estimating protocol using estimated benzene concentration / Concentration and flow data is based process unit wastewater from all sources within the unit that is discharged to the  process sewer system (e.g. effluent from sour water stripper and from benzene stripper)


plant_name:
ConocoPhillips Los Angeles Refinery Wilmington

notes:
-99 in numeric field indicates information is unavailable, unknown, or not applicable

SCAQMD - South Coast Air Quality Management District

Part 1 Annual revenue in 2010 ($): Annual Revenue figure for 2010 represents ConocoPhillips U.S. Refining and Marketing operations

Part 1 Degree of independence from parent company: Although this question is somewhat incomprehensible to ConocoPhillips  in that the "facility" does not have a Board of Directors and for other reasons, we believe that this statement "best" applies to the three statements offered

Part 1 Products Produced: EIA 810 reports LARC and LARW refinery production combined. Production is reported by each Refinery based on the location of the ultimate product disposition

Part 1-Process Units: For unit throughput capacity of the W-ORU (wastewater treatment system) there is not a maximum flow permit limit so no capacity number is provided

Part 1-Process Units: The refinery has two Naphtha Hydrotreaters Units 79 and 99 that are not listed as separate process units in the ICR response.  These units and related equipment are incorporated into Units U80-Reformer and U100-Reformer for the ICR response. 

Part I-Process Units: Actual 2010 steam consumption is provided, not consumption at capacity

Part II-Section 1: The text field for describing the energy management plan was limited so the full description of the plan is included here: The refinery has an evergreen Energy Plan which includes energy reduction projects which the facility intends to complete.  It also includes any operational practice improvements which the facility intends to implement.  The facility has ongoing energy reduction/ optimization programs as follows: 1) Program to monitor and optimize excess oxygen in process heaters and boiler, 2) Program to monitor and optimize fuel gas usage, 3) Program to test and repair facility steam traps, 4) Program to identify and repair steam leaks, 5) Program to monitor pump operation for motors vs steam turbines operation (vent to atmosphere) and expedite repairs, 6) Program to review and ensure new projects for energy efficiency, 7) Program to monitor facility heat exchangers and clean for improved heat recovery.

Part II-Section 3: Table 3-2,  Equipment and Leak Detection Information for Fuel Gas and Natural Gas Systems was left blank because this table accounts for FG/NG systems not captured in process units in Table 3-1 and all FG/NG system components were captured in Table 3-1. / Tables 3-1 and 3-3: The component numbers listed are based on the definitions of gas, light liquid, and heavy liquid defined in local regulation SCAQMD Rule 1173 / Table 3-1: Open ended lines were estimated based on an estimate of cap and plug components (i.e. not actual open ended lines but lines with caps or plugs) / Table 3-1: No number of pieces of equipment monitored, monitoring frequency, or leak definition is provided for open ended lines because these equipment leak components (i.e. caps or plugs) are included in the numbers provided for flanges and connectors 

Part II-Section 1: Emergency ICE (internal combustion engine) driven electricity generators are included in this section.  The generation unit ID assigned to these generators have ICE included in the unit ID.

Part II-Section 5: Unit 120-UK is shown on the pull is one of two choiced in the Unit ID for CCR field pulldown menu but Unit 120-UK is a hydrocracker unit and not an catalytic cracking unit

Part II-Section 10: Deaerator vent flow rate was determined from source test data and is on a dry basis

Part II-Section 15: Wastewater flow is estimated from data related to 40 CFR 61 Subpart FF (BWON) and previous water studies / Benzene concentration is estimated from 40 CFR 61 Subpart FF (BWON) TAB data, not direct measurements / Sour Water Stripper effluent flow is included in the U138-SRU Unit ID / U141-Sulfuric Acid Plant is included in the U138-SRU / Organic HAP and VOC is estimated using Table 7-8 of the emissions estimating protocol using estimated benzene concentration for calculating HAPS and VOC / Concentration and flow data is based process unit wastewater from all sources within the unit that is discharged to the  process sewer system (e.g. effluent from sour water stripper and from benzene stripper)


plant_name:
ConocoPhillips San Francisco Refinery at Rodeo

energy_management_plan_description:
Optimization of utility consumption (e.g. heater O2, steam/carbon ratio, steam consumption, compressor spillback, etc)
1) Steam trap inspection and replacement.
2) Robust Energy Improvement Plan list is developed each year as a 5-yr plan.


energy_management_plan_description:
Project energy performance checklists, fired heater/boiler O2 management, steam trap leak & repair, heat exchanger cleaning, waste heat steam generation, flare gas recovery, compressed air survey to reduce leakage, energy efficiency tracking

notes:
Part I, Question 11: Annual Revenue in 2010:  This number is considered CBI.
Part I, Question 13: Part of a larger Corporate entity/Jt. Venture? Although this question is somewhat incomprehensible to ConocoPhillips in that the "facility" does not have a Board of Directors and for other reasons, we believe that the response provided to this statement "best" applies of the three statements offered (i.e ConocoPhilllips is fully integrated).
Part I, Question 15: Cumulative 2010 production, % used on site, % shipped by tank ship, % shipped by rail car and % shipped by pipeline CBI.
Part 1, Question 16: Unit Actual Throughput considered CBI. Throughput capacity for crude, vacuum, coker, SRU, from 2010 Solomon data, or from permit. Amine capacities in MMSCFD. WWTP capacity in MMGal/day. Tank Farm Unit ID consists of storage tanks and areas not otherwise listed. Boilers Unit ID contains steam generation equipment. CP-CS includes internal combustion engines used throughout the facility. Units for Truck load/unload and Rail load/unload are in FOEB/CD.  Units for Purchased Natural Gas (Ut-NG) are in MMCF/CD. Units for Utility Boiler Power and Utility Electrical Power (Ut-BP and Ut-EPG) are in MPPD
Part I, Question16: Units for Fuel gas Treatment (AA/AB) are in MMCF/CD).  Units for Truck load/unload and Rail car load/unload are in FOEB/CD.  Units for Purchased Natural Gas (Ut-NG) are MMCF/CD.  Units for Utility Boiler and Electrical Power (Ut-BP and Ut-EPG) are MPPD.
Part II, Table 1-1: Fuel consumption considered CBI.
Part II, Question 3: Hydrogen purchased considered CBI.
Part II, Table 1-2: Air Preheat use, air preheat temperature, disposition of electricity, steam pressure, disposition of steam and percent steam to blowdown considered CBI. Also note: steam doesn't go to blow down, water does so question is not applicable (N/A). Waste heat generators do not have heat input capacity nor steam generating capacity.
Part II, Table 1-3: Steam consumption for processing considered CBI. These are net values.
Part II, Table 2-1: Process heater average heat input rate, total operating hours, air preheat use, typical air preheat temp, other efficiency measures, % total operating hrs fired on primary fuel, % total operating hrs fired on secondary fuel, operating hrs fired <25% of capacity and operating hrs fired between 25% and 50% considered CBI.
Part II, Table 3-1: Per response from EPA, Potential OEL components are listed as "OEL" assuming these are located on 1" line that is either capped or plugged. Also note: no Open Ended Lines are allowed for equipment in VOC service.
Part II, Table 3-2: Number of components in natural gas service are estimated.
Part II, Table 3-3: Total number of PRD, number of controlled gas PRD, number of controlled liquid PRD, number of atmospheric gas PRD, number of atmospheric gas PRD with rupture disk, number of atmospheric liquid PRD and number of atmospheric liquid PRD with rupture disk are considered CBI.
Part II, Question 2a and 2b: Quantity of unstabilized crude oil and pressure considered CBI.
Part II, Table 4-1: Total throughput, year tank last degassed and year anticipated for next degassing considered CBI.
Part II, Table 7-1: Delayed Coking Unit Information is all considered CBI.
Part II, Table 7-2: Delayed Coking Unit Feed Information is all considered CBI.
Part II, Table 15-2: WWT: Concentration HAP/VOC if left blank = no available data
Part II, Table 16-1: Type of control device or control technique is based on the highest level of control available.

Part III-Non-Routine Emissions: Dec 5, Dec. 11 and Dec. 12 Events Loosened wiring was later found at high level switch assembly that likely caused these breakdowns.  Correction of this resolved intermittent false indications of high liquid levels to shutdown G212A(result in flare).

Part IV, Table 1: Demolition cost, primary equipment cost, auxiliary equipment cost, instrumentation & monitor cost, sales tax and freight costs, total purchased equipment costs, installation costs, total installed cost, operating labor cost, maintenance labor cost, electricity cost, water cost, steam cost, liquid chemical cost, solid chemical cost, compressed air cost, other costs, total utility costs, waste disposal cost, supplies and parts replacement costs, other annual costs and total operating and maintenance costs considered CBI.
Part IV, Table 2: Number of days process shutdown, total capital costs and change in total annual operating costs considered CBI.

Part V. Emissions Monitoring: 
--Identification is COPSMR-category analyzer tag-pollutant.
--Categories are: ST-Source Test, RATA-Relative Accuracy Test, CGA-Calibrated Gas Accuracy test, DAMD-Daily Average Monitoring Data
--CEMS AN1600s (A/B) are dual-range SO2 monitors on each SRU incinerator stack.  During normal operation, these monitor emissions from the respective SRU sulfur pit (A or B).  During process upset, the analyzers monitor sulfur plant process upsets. During periods of startup/shutdown these monitor may record tail gas emissions. 
--CEM AN170709 monitors TRS emissions from TGTU combustor stack.  During normal operations, the stack is operated on low fire.  During periods of upset, the stack is ramped up to combust H2S and treat process upsets.  
--CEM titled "SRPAMP" represents emissions calculated as the molar average of the entire Sulfur Recovery Plant per the Alternate Monitoring Plan(AMP) submitted to EPA on Sept. 8, 2006 entitled "AMP for TGU outages and monitoring sulfur pit vent emissions from the Santa Maria Refinery Sulfur Recovery Plant"
--CMS AN603 is the refinery fuel gas H2S monitor.

Part V. Emissions Monitoring and Source Test Data: Daily Average Emission Monitoring Template includes Daily Production/Average Rate Throughput Rate.  This rate is considered CBI.


notes:
Facility Information 1-Question 1 through 16:
1.FacilityInformation.Question16 – Unit capacities and throughputs were provided for traditional units.  In some cases, collections of equipment were grouped together to facilitate data entry in the ICR reporting tool, e.g. Utilities – Cooling Towers.  Capacities and throughputs were not provided for these non-traditional units or unit groups.

Catalytic Cracking Units – 2-5:
2.5. Since FCC uses Recylce/Resid only during the start up, the unit capacity for Recylce/Resid assumed to be 0.

Flares 2-12:
2.12. Flares lack flow meters so a target assist ratio is reasonably practical.  No assist ratio is listed in manufacturer’s documents or permits.

2.12. Flare coordinates from Google maps

Fuel Gas Treatment 2-13:
2.13. The treated gas by each of the fuel gas treatment units is mixed at a mix drum at unit 88 and then distributed among the combustion sources at the facility. The total sulfur and H2S content of the fuel gas is measured after mixing the treated gas at the mix drum.  

Emission Monitoring and Source Test Data 5-1 through 5-5
5.4. Wilmington refinery does not have any biological treatment unit; therefore, no biodegradation rate test or complete mixing test is performed.

5.5. No ambient and remote sensing test was conducted around the refinery on or after January 2000. 

5.6. Facility does not use any site-specific correlations for equipment leaks.


legal_owner_name:
Valero Refining Company - California, a Delaware corporation


notes:
Lunday-Thagard Company does not have a breakdown of steam usage per process unit, only total production.


energy_management_plan_description:
Albeit an unwritten plan, the refinery generally uses the lowest cost energy and the most efficient steam generators in accordance with good operating practice.

notes:
For Part I General Information (Products Produced)- The Delaware City Refinery was idled for all of the year 2010.  No products were produced during the year 2010.

For Part II Section 2 Process Heaters - None of the process heaters at DCR were operating in 2010.

For Part II Section 3 Equipment Leaks (Process Units) - Average methane content is not measured and there is no inventory of open-ended lines, gas sampling connections, or liquid sampling connections.

For Part II Section 3 Equipment Leaks (PRD on process units) - DCR only has an inventory of the number of PRD at the refinery with no inventory of atmospheric or controlled PRD nor an inventory of gas versus liquid service PRDs. There is also no inventory of PRD with rupture disk or other non-reclosing device.

For Part II Section 3 Equipment Leaks (Gas systems) - DCR has no inventory of equipment counts on the fuel gas or natural gas systems.



For Part II Section 10 Hydrogen Plant Vents - At DCR the hydrogen plant is a steam methane reformer that does not use pressure swing absorption; therefore, the PSA purge/off gas flow rate is not applicable.

For Part II Section 12 Flares - For both flares, the target steam assist ratio varies to ensure smokeless operation.  Also, the typical lower heating value of waste gas to both flares varies greatly (1000 to 2600 Btu/scf).


For Part III - There were no non-routine emissions events during 2010 at DCR.


notes:
**Part 1 parent company: while the parent company is NuStar Energy LP, the 1492 employees is for NuStar GP LLC, which is the entity that employs all US employees that provide service to the NuStar companies in the US.  **Part 2 Section 3: equipment leaks info is for entire plant. Part 2 Section 11: D103 is associated with D001 and D002.   **Part 2 Section 16: The facility owns some of the rail cars being loaded, but not all. **Part 3: There were no non-routine emissions events during 2010.


energy_management_plan_description:
Key elements: Analyse the energy systems; Track and improve energy efficiency; Maintain inventories and plans for conservation of fuel and natural resources.  Key energy reductions:  Reduced use of cooling tower fans and FCC fin-fans.

notes:
(1)	Part I:  Process units that did not use bbl/d for unit throughput capacity and unit actual throughput are as follows:  62 [LT/d], 67 [KW]
(2)	Part I: Process Unit 57 is reported in bbl/d for unit throughput capacity and unit actual throughput
(3)	Part I:  Process Unit 60 was not in operation in 2010
(4)	Part II: Section 3, various unit component counts are combined
(5)	Part II: Section 16, ships receiving material may be Chevron owned or by another company


energy_management_plan_description:
1.	The refinery has an energy improvement plan consisting of three parts, Operational Energy Improvement (furnace efficiency improvements and process changes), Maintenance work and Projects, including several energy improvements since 2009.

notes:
General Comments
The following codes were used in the ICR database:
-88 = Not applicable
-90 = Confidential Business Information (CBI)
-99 = Unknown
1.	Part I, General Facility Information, Annual revenue in 2010.

Tesoro Response:  Tesoro has provided the total combined annual revenue for all of its facilities in operation in the USA. 


2.	Part II, Section 2, Process Heaters, Rated heat input capacity (MMBtu/hr)

Tesoro Response:  Pilot gas heat input is not considered in rated heat capacity.  

3.	Part II, Section 2, Process Heaters, Average heat input rate in 2010 (MMBtu/hr)

Tesoro Response:  Unlike most refineries, Tesoro Hawaii does not have natural gas.  Consequently, refinery fuel gas is used for pilot gas and is included as part of the average heat input. 

4.	Part II, Section 3, Equipment Leaks, “Do you own or have ready access to an optical or thermal imaging device for detecting equipment leaks?”

Tesoro Response:  Tesoro Hawaii does not own  optical or thermal imaging devices for detecting leaks, however, the facility has in the past borrowed such devices from sister Tesoro facilities for use during turnarounds.

5.	Part II, Section 3, Equipment Leaks, “Average methane concentration in process fluid that contacts equipment in gas service throughout the process (ppmv)”.

Tesoro Response:  The average methane content will vary significantly across the plant and is stream specific, therefore we cannot estimate it by process unit. 

6.	Part II, Section 3, Equipment Leaks, “Is the average methane concentration based on sampling and analysis results or estimated (e.g., based on process knowledge).

Tesoro Response:  The average methane content will vary significantly across the plant and is stream specific, and therefore, we cannot estimate it by process unit.

7.	Part II, Section 3, Equipment Leaks, Pump Seals – Light liquid.

Tesoro Response:  Tesoro has identified the number of pumps (i.e., not the number of seals) in the table. 

8.	Part II, Section 3, Equipment Leaks, Pump Seals – Heavy liquid.

Tesoro Response:  Tesoro has identified the number of pumps (not the number of seals) in the table. Tesoro interprets this data collection requirement for those facilities that are under fugitive monitoring program under State or Federal requirements to monitor heavy liquids components. For Tesoro Hawaii, heavy liquid pumps and valve leaks are subject to LDAR standards upon evidence of a leak, pursuant to NSPS and Refinery MACT standards. There is no regulatory requirement to maintain a database or routinely monitor these sources for fugitive emission leaks.  Consequently, the number of heavy liquid pumps and valves is based on equipment lists and on correlation-based estimates, and not from a well-maintained fugitive emissions database.

9.	Part II, Section 3, Equipment Leaks, Open-ended lines.

Tesoro Response:  For purposes of this response, Tesoro will define “open ended line” as it is defined in the NSPS.  Under NSPS, open-ended line (“OEL”) “means any valve, except safety relief valves, having one side of the valve seat in contact with process fluid and one side open to the atmosphere, either directly or through open piping.” Throughout 2010, Tesoro had no equipment designed or operating as an OEL. For regulated valves that are otherwise open to the atmosphere, Tesoro meets the NSPS by applying a cap, blind flange, plug, or second valve, which effectively changes the design to no longer meet the OEL definition. If the cap, blind flange, plug, or second valve is found to not be properly installed, the refinery takes steps to replace it. Instances where a line was found to be open during an interim period in 2010 when it was designed to be capped does not make it an OEL design throughout 2010.

10.	Part II, Section 3, Equipment Leaks, Heavy Liquid – covering Pump Seals, Valves and Flanges & Connectors

Tesoro Response:  Tesoro interprets this data collection requirement for those facilities that are under fugitive monitoring program under State or Federal requirements to monitor heavy liquids components. For Tesoro Hawaii, heavy liquid pumps and valve leaks are subject to LDAR standards upon evidence of a leak, pursuant to NSPS and Refinery MACT standards. There is no regulatory requirement to maintain a database or routinely monitor these sources for fugitive emission leaks.  Consequently, the number of heavy liquid pumps and valves is based on equipment lists and on correlation-based estimates, and not from a well-maintained fugitive emissions database.

11.	Part II, Section 3, Equipment Leaks, Compressor Seals.

Tesoro Response:  Tesoro has indicated the number of compressors (i.e., not the number of seals) in the table.

12.	Part II, Section 3, Equipment Leaks, Atmospheric PRD-Gas-Monitoring of Releases-Number of PRD monitored using a system designed to measure the duration of a release and/or the quantity of compounds released.

Tesoro Response:  Tesoro does not have a specified system to monitor measure flow rate specific to PRD monitoring.

13.	Part II, Section 4, Storage Tanks, Storage Tank General Information.

Tesoro Response:  Tesoro has not included information in Table 4-1 for spheres or pressurized tanks used for storage of compressed Propane and Butane.

14.	Part II, Section 4, Storage Tanks, Type of secondary rim seal.

Tesoro Response:  Where Tesoro has identified some of its tanks having rim-mounted seals whereby the primary seal is not a mechanical-shoe seal, no selection is made for secondary seals. For the Tesoro Hawaii Refinery, this includes Tanks 103, 104, 107, 201, 204, 401, 402, 403, 404, 405, 406, 501, 502, and 504. 

15.	Part II, Section 4, Storage Tanks, Maximum true vapor pressure of hydrocarbons in stored liquid in 2010 (psi).

Tesoro Response:  True vapor pressure (“TVP”) reported applies to the material stored in 2010 only, and that the tanks may be capable of storing higher TVP materials. 

16.	Part II, Section 4, Storage Tanks, Total throughput for all materials stored in the tank in 2010 (bbl).

Tesoro Response:  Tesoro’s tank throughput is based on change in tank levels as used in Emissions Inventory Calculations. For tanks that are drawn down and filled at the same time (like intermediary tanks TK610 and TK611), the roof is relatively constant in level.  Tanks TK608 & TK609 are internal floating roof tanks but their primary seals were removed in 2010.  TK605 is listed as a vertical fixed roof tank because its roof was not removed until 2011.   All tanks that are referenced in Title V permit are listed for completeness, even when not in service for 2010.


17.	Part II, Section 8, Catalytic Reforming Unit, Operating Pressure (psig).

Tesoro Response:  Tesoro is reporting the average reactor pressure [i.e., (Lead + Lag) ÷ 2] due to the pressure measurement location not being defined in the ICR. 

18.	Part II, Section 15, Question No. 5, Table 15-2, Average HAP concentration (ppmw).

Tesoro Response:  Tesoro has not analyzed for all organic HAPs and therefore does not have a good estimate to report.  As a result, Tesoro has left this field blank.  It should be noted, however, that the Tesoro Hawaii Refinery does routinely test for benzene, toluene, ethylbenzene, and xylene for the CDU desalter wastewater, TK-517 spent caustic, TK-111 water draw, and the SSS (stainless steel sump process wastewater).  


19.	Part II, Section 15, Wastewater Collection and Treatment, Average VOC concentration (ppmw).

Tesoro Response:  Tesoro has not analyzed VOC concentration (ppmw) and therefore does not have a good estimate to report.  As a result, Tesoro has left this field blank. 

20.	Part II, Section 16, Question No. 2, Marine Vessels.

Tesoro Response:  The Tesoro Hawaii Refinery has two methods of marine vessel loading operations at separate locations.  Barbers Point Harbor (the most representative of facility operations and emissions) is best described as “Marine vessel loading operations are conducted on-shore but are not contiguous with the refinery”.  However, operations at the Single Point Mooring (less representative, therefore not selected) is best described as “Marine vessel loading operations are conducted off-shore (i.e., more than 0.5 miles from the coast).”  

21.	Part II, Section 16, Question No. 4, Table 16-1, Capacity loading throughput (gal/yr).

Tesoro Response:  Product Loading Barbers Point Harbor (BPH) capacity based on permit limits for each fuel type (light & heavy liquids).


22.	Part III, Non-Routine Emissions

Tesoro Response:  Tesoro will meet this requirement by submitting all agency reportable emissions that occur during periods of startup/shutdown and component malfunction for the year 2010.

23.	 Part V, Emissions Monitoring and Source Test Data, Qualified CEMS Data.

Tesoro Response:  Tesoro will submit data that for all CEMS that fall under the purview of Federal regulations, continuous monitors required by state agencies that do not meet federal CEMS testing and compliance assurance requirements are not included in Tesoro’s ICR response. The Tesoro Hawaii Refinery has not submitted SO2 CEMS for the H1353 because the incinerator is used as an indicator during abnormal situations and is not required by permit or regulation.


energy_management_plan_description:
Ongoing key elements include ongoing steam trap maintenance, periodid burner maintenance, and use of stack O2 monitors to optimize heater/boiler operation.  An Energy Mgmt team has been formed to identify & institutionalize other reduction opportunities.

notes:
Component 1, Part I, General.
1.  Annual revenue is the corporate-wide revenue.

Component 1, Part I, Process Units.
1.  Unit 112 capacity.  U112 capacity is listed as fresh feed.

2.  Unit 123 capacity.  Unit 123 has two sections, a Hydrodesulfurizer (hydrotreater) section and a Catalytic Reforming section.  The Catalytic Reforming section capacity is approximately 60% of the total unit capacity.

3.  Unit 123 actual throughput.  All of Unit 123 throughput in 2010 went through the both the Hydrodesulfurizer section and the Catalytic Reforming section.

Component 1, Part II, Section 1, Fuel Consumption.
1.  Basis is Solomon 2010 report.

Component 1, Part II, Section 2, Process Heaters.
1.  Heater 116B-1.  This heater was retrofit with Ultra-Low NOx (ULNB) burners May 2011.

2.  Heater 116B-2.  This heater was retrofit with Ultra-Low NOx (ULNB) burners May 2011.

3.  Federal Air Regulations.  All process heaters and boilers are required to comply with NSPS J for fuel gas combustion, pursuant to a Consent Decree with U.S. EPA.  However, only the following heaters actually triggered NSPS J applicability -- 102B-2, 103B-1, 106B-1, 107B-21, 108B-41, 108B-42, 109B-62, 113B-3, and boiler 431B-20.  590H-1 and 590H-2 triggered applicability of NSPS Ja for those two heaters.  NSPS J (or Ja) is indicated for those heaters that actually trigggered applicability of the requirement.

Component 1, Part II, Section3, Equipment Leaks.
1.  The reported average methane concentration for each process unit does not include those LDAR components handling refinery fuel gas in the process unit.   

2.  The average methane concentration for refinery fuel gas is reported in Section 3 – Equipment Leaks – Gas Systems. 

3.  Valves associated with sample systems, sight glasses, gauges, diaphragms, and other instrumentation are included in the valve counts.  A count of the sampling systems could not be extracted from the LDAR database.  

4.  Heavy liquid valves and pumps are tagged and incorporated in the LDAR database.
  
5.  For the majority of process units, the number of flanges and screwed fittings is based on the number of valves using a valve to flange ratio.   For the HON Process Units 311 and 703, the number of flanges is based on actual tagged components.  

6.  There should be no open ended lines.  All open ended lines not in use are immediately closed.  

7.  The valve count for light liquid and gas valves includes pressure relief valves.  

8.	  Refinery fuel gas components are included in the process units and an exact count could not be made using the LDAR database.   The total number of valves reported in refinery gas service is an estimate based on limited field surveys.  This number includes those components associated the refinery fuel gas system downstream of the fuel gas mix drums and does not include components associated the process unit make gas streams or the fuel gas treatment units.  

9.  Natural gas components were not included in the fugitive equipment monitoring program in 2010, so the total number of valves reported in natural gas service is an estimate based on limited field surveys and the partial data from beginning the incorporation of these components into the fugitive equipment monitoring program in 2011.
 
10.  The total number of Pressure Relief Valves in liquid service only includes those valves that are in light liquid service.   Heavy liquid PRDs are not included.  

11.  Most of the PRDs that can release to the atmosphere can be monitored by the pressure indicator for the vessel or line being protected with the quantity of the compound released determined by the size / configuration of the PRD.

12.  All PRDs not going to the atmosphere are either directed to the flare systems or fuel gas.  See also Note 13 in this section.

13.  PRD releases recovered through a flare gas recovery system (process units 102, 103, 106, 107, 108, 109, 111, 112, 113, 114, 115, 116, 118, 119, 121, 122, 123, 125, 2112, 217, and 590) are routed to the fuel gas system except when the releases result in flows greater than the flare gas recovery system capacity.  

Component 1, Part II, Section 4.  Storage Tanks.
1.  Per instructions in Help documentation, only those hydrocarbon tanks greater than 10,000 gallon capacity and storing hydrocarbon materials greater than 0.1 psi are reported.  Since no hydrocarbon products with a vapor pressure greater than 0.1 psi are storage in fixed roof tanks vent to the atmosphere, no such tanks are reported or coded as such.  

2.  Tanks that are believed to permanently out of service are not reported.

3.  Tanks that were out of service but are expected to return to service are reported with the throughput shown as zero.

4.  Tank contents.  Lemont Refinery produces both reformulated gasoline and conventional gasoline.  The same blendstocks are used to produce both types of gasoline.  Accordingly, a category “Motor Gasoline Blending Components - Reformulated/Conventional Mix” was created to reflect this. 

5.  Tank contents.  Lemont Refinery is in a region where reformulated gasoline is required.  Because ethanol is mixed with the gasoline at the loading rack, tanks that contain reformulated gasoline (reformulated basic oxygenated blendstock – or RBOB) have been categorized as containing a “Motor Gasoline Blending Component-Reformulated”, even though the only other additive is ethanol, because until the ethanol is added, it is not “finished”.

6.  Tank contents.  The contents of tanks 331 TK-515, 601, and 612 are listed as “Petrochemical Feedstocks – Naphtha <401F end-point.  These tanks contain oils purchased from other industries for further processing as a feedstock in petrochemical production.  The refinery does not produce these materials.  These tanks contents could also have been listed as “Unfinished Oils – Naphthas and lighter.”

7.  Maximum vapor pressure.  Tank 331 TK-432.  This tank is a pressurized sphere in Alky feed service.     This feed (a mixture of propylenes and butylenes).  The maximum vapor pressure indicated in the database is the vapor pressure of the material’s primary constituents, and does not account for the vapor pressure contribution from the small levels of methane, ethane, and hydrogen that may also be present.

8.  For horizontal pressure tanks (“Other – Pressurized/horizontal bullet tank”), the horizontal length is reported has the tank height.  And the maximum liquid height is the maximum distance along the diameter that the tank was filled.

9.  All pressurized tanks were noted as dry drain tanks since these tanks vapor dry to flare system as part of the degassing process. 

10.  Tank degassing.  Tanks 331 TK-065, 066, 067, 068, 069, 080, 081, 090, 432, and 488 are pressurized tanks.  These tanks initially depressure to a flare preceded by a flare gas recovery system, and then the final depressurization is to atmosphere.  This is shown in the database by “Other (specify)”, but the database does not allow entry of the description in the “If other, specify” box.

11.  Tank degassing.  Tank 331 TK-488.  The tank installation date was used as the last degassing date since it has not been taken out of service since being put in service.   

12.  Federal Regulations.  Tank 331 TK-505.  This tank has periodically switched between being subject to HON (40 CFR 63 F) and RMACT1 (40 CFR 63 CC).


Component 1, Part II, Section 5.  FCCU.
1.  The control sequence downstream of the FCCU (Unit 112) regenerator is:  CO Boiler, SCR, Wet Gas Scrubber (WGS), and Wet Electrostatic Precipitator (WESP).  The WESP is immediately downstream and integral with the WGS.

2.  E-cat results are included for Sb, Pb, Ni, and V.  Results are not included for As, Be, Cd, Cr, Co, Mn, Hg, and Se; the catalyst vendors do not routinely analyze for these metals.

Component 1, Part II, Section 6.  Fluid Coking Units.
1.  Lemont Refinery does not operate a Fluid Coking Unit.

Component 1, Part II, Section 7.  Delayed Coking Units.
1.  Unit 108.  Typical data is based on 2008.  No coke was produced at Unit 108 in 2010.

2.  Unit 108.  The requested periods for the coke cycle do not include all of the steps n the coke cycle, therefore the total of the periods requested may not equal the feed step.  Also, the vent time includes the cutting time, so it gets double counted.  Some steps in the coke process are variable and the values listed are typical, when the unit is operated to produce sponge coke.

3.  Unit 108.  No Federal Regulation is applicable.  Refinery MACT 1 specifically excludes coke drum vents from the definition of miscellaneous process vent so long as the depressurization occurs at < 15 psig; Unit 113 depressures at well below 5 psig.  No modification has been made that would make NSPS Ja applicable.

4.  Unit 108.  There are no Illinois regulations specific to delayed cokers.

5.  Unit 113.  Typical drum pressure and temperature when Unit 113 coke drums are first vented to atmosphere are < 5 psig and < 400 F, respectively.  The values entered in the database are based on the average data resulting from a detailed review of 3-months of operations at Unit 113 (April-June 2010).

6.  Unit 113.  No Federal Regulation is applicable.  Refinery MACT 1 specifically excludes coke drum vents from the definition of miscellaneous process vent so long as the depressurization occurs at < 15 psig; Unit 113 depressures at well below 5 psig.  No modification has been made that would make NSPS Ja applicable.

7.  Unit 118.  There are no Illinois regulations specific to delayed cokers.

Component 1, Part II, Section 8.  Catalytic Reforming Units.
No comments.

Component 1, Part II, Section 9.  Sulfur Recovery Units.
1.  NSPS J is applicable to all four trains because of NSR Consent Decree between CITGO and U.S. EPA.  Process modifications made to Unit 121 in 2009 and 2010 triggered NSPS Ja applicability for the entire SRP (all four trains).  So both NSPS J and NSPS Ja are currently applicable, even though there are conflicting limits (excess emissions from a train under NSPS J may not be excess emissions when considered across all 4 trains under NSPS Ja).

Component 1, Part II, Section 10.  Hydrogen Plant Vents.
1.  No Federal Regulation is applicable.  Refinery MACT 1 specifically excludes hydrogen production plant vents through which carbon dioxide is removed from process streams or through which steam condensate produced or treated within the hydrogen plant is degassed or deaereated.  The Unit 109 plant vent is a deaerator vent. 

Component 1, Part II, Section 11.  Atmospheric Vents.
No comments.

Component 1, Part II, Section 12.  Flares.
1.  Management Plan.  Flares C-1, C-2, C-3, and C-4 are equipped with flare gas recovery, so the monitoring of Btu and sulfur content of flared gas is accomplished through routine periodic sampling of the recovered flare gas.  For flaring events, this is supplemented by engineering evaluations.  Flare C-5 is a flare dedicated to the HF Alkylation Unit, Unit 120.  Per NSPS J, HF Alkylation Units are presumed sulfur-free.

Component 1, Part II, Section 13.  Fuel Gas Treatment Units.
1.  During 2010 Lemont Refinery converted its fuel gas treatment solvent from MEA (monoethanolamine) to MDEA (methyldiethanolamine).

2.  General.  The annual average total sulfur concentration in the fuel gas leaving fuel gas treatment units is not monitored.

3.  Process Unit.  111D-401.  This fuel gas treatment unit receives vent gas from the Unit 111 vacuum vent gas compressor.  The gas is then sent to the flare gas recovery system, where it, along with other gases is recovered and directed to the fuel gas treatment unit 217D-4.

4.  Process Unit.  212D-601.  This fuel gas treatment unit receives fuel gas from Unit 212 (Unsaturated Gas Plant associated with FCCU Unit 112), and from 113D-401C, which is the fuel gas treatment unit at the Coker 1 (Unit 113).  113D-401C has historically been used only during turnarounds of the FCCU; late in 2010, 113D-401C was put into service for normal operations.

5.  Process Unit.  844DE-401.  This fuel gas treatment unit receives vent gas from the 844C-1 (North Plant Flare) Flare Gas Recovery Compressor for Units 118, 122, and 123.  The recovered gas is sent though this fuel gas treatment unit, where it is directed to the Unit 123 fuel gas system.  The maximum flow rate at throughput capacity is based on 1.18 vol % H2S, 10 gpm amine, and 157 grains H2S / gallon of lean amine.  This value is far outside of where the treatment unit typically runs (and is probably more than the vessel can handle).  The flow meter is ranged to 695 scfm and that upper range has been reached only a few times in the last 5 years.

Component 1, Part II, Section 14.  Heat Exchanger Systems.
1.  420E-7 (Alky Cooling Tower).  Besides the sodium hypochlorite listed in the database, five additional additives are used at this cooling tower.  Individual rates during 2010 for these other non-sodium hypochlorite additives were Corrosion inhibitor - 15,431 lb/yr; Anti-scalant -- 64,554 lb/yr; Bio-dispersant -- 3,369 lb/yr; Passivation chemical -- 2868 lb/yr; and sulfuric acid -- 253,020 lb/yr.  These non-sodium hypochlorite additives aggregate to 339,242 lb/yr.

Component 1, Part II, Section 15.  Wastewater Treatment Units.
1.  VOC and HAP data by process unit were not reported since this data was not available. 

2.  Benzene data by process unit was based on Subpart FF BWON End of Line sampling. 
  
3.  Minor miscellaneous sources not associated with process units were not included in wastewater generation information. 
 
4.  Wastewater generation information does not include slop oil sent to the slop oil system but does include sour water processed through the sour water strippers.  
  

Component 1, Part II, Section 16.  Product Loading.
1.  For Product Loading Unit 333 (Barge Dock), the thermal incinerator control is used only for benzene loading, to comply with 40 CFR 61 Subpart BB.

2.  Product Loading Unit 333 (Barge Dock).  The annual operating hours reflect the hours when product loading onto barges occurred.  This is less than the operating schedule for the dock, as loading can occur at any time during the day, and the barge can also received shipments of various feedstocks.  The off-loading of barges is not reflected in the annual hours of product loading operations.

3.  Product Loading Unit 334 (Santa Fe Rail).  Rail cars are loaded with LPG, so are closed systems.

4.  Product Loading Unit 335 (bulk terminal) is a contiguous truck terminal adjacent to the Lemont Refinery and is owned by CITGO but not operated by the refinery.
5. Product Loading Unit 335 (bulk terminal) is operated 24 hours a day every day of the year.

6.  Product Loading Unit 335 (bulk terminal).  The control (enclosed flare) is used for loading gasoline tank trucks and distillate fuel tank trucks.

7.  Truck and rail loading of sulfur and petroleum coke was not reported in this section.

8.  Product Loading Unit 337 (ICG rail rack), Federal Regulations.  HON (existing sources) is applicable to the parts of the rack that load HON-regulated materials.

9.  Product Loading Unit 339 (solvent truck rack).  Federal Regulations.  For Product Loading Unit 338 (solvent truck rack), HON (existing sources) is applicable to the parts of the rack that load HON-regulated materials.

Component 1, Part III.  Non-routine Releases.
1.  These event based non-routine releases are reported on an event-basis. So one “event” could be comprised of excess emissions at numerous sources.  Accordingly, these event emissions represent emissions from flaring (non-routine, as flares are equipped with flare gas recovery), and excess emissions from Units 112, 119 A-train, 119B-train, 121C-train, 121 D-train, process heaters with monitored excess CO, and process heaters associated with excess fuel gas H2S.   The excess emissions are those emissions reflecting pollutant (CO, NOx, SO2) or parameter (H2S) concentrations above the permitted concentration levels.

Component 1, Part IV.  Cost Data
1.  APCD Costs, U119 TGU.  Unit 119 TGU electricity cost for 2010 could not be easily broken out, as the metering is on a feeder that supplies several units.

2.  APCD Costs.  112-WGS.  This represents the cost of the WGS/WESP and the PTU to manage the solids in the WGS effluent.  Hours for Maintenance are an approximation.

3.  For 112-WGS, "Other Utility" is used for [CBI].  In the database, under "Other Utility", when the Units/yr are entered the database automatically populates the same value in the cost/unit; this is a flaw in the database.  If the database were functioning correctly, that data that would be shown is [CBI].

4.  Cost Data for Process and Equipment Changes.  119-Amine Treatment.  The change in annual operating cost due to converting from MEA to MDEA is an estimate for MDEA, Filters, Antifoam, Ion Exchange, Carbon Beds, etc.

Component 1, Part V.  Emissions Monitoring and Source Test Data. 
1. Process heater and boiler data was not included in the ICR based on the exclusion statement for these sources.

2.  RATAs for continuous emission monitors were not include with the emission monitoring data since daily CEMS data is being provided, and RATAs are part of the QA associated with CEMS.

3.  For FCCU Unit 112, the most recent Method 5B testing (a worst case operating scenario for our Wet Gas Scrubbers) and 2007 testing (normal operations for our Wet Gas Scrubbers).

4.  No emissions testing was available for the delayed coking units. 

5.  The most recent Subpart UUU compliance testing (Method 26A) for both reformers (Unit 116 and Unit 123) is included.  

6.   For our four (4) Sulfur Recovery Unit Tail Gas Unit CEMS, the sulfur production was allocated based on engineering judgment based on available process data.


notes:
•	Part I, Facility Information, Question 11:  Annual revenue in 2010:  $770 (millions of dollars); basis is U. S. Downstream (Refining and Fuels/Lubes Marketing) earnings after income tax.
•	Part I, Facility Information, Question 13:  Parent company employee headcount reported is for 2010 year end.
•	Part I, Facility Information, Question 16:  General Note on Column F " Unit Throughput Capacity (bbl/cd)" - whenever applicable, Unit Throughput Capacity in units of bbl/cd is as quoted in Oil & Gas Journal's International Refining Survey.
•	Part I, Facility Information, Question 16:  For Units 10E and 10W - A note on unit configuration - These are two parallel Claus units that vent tailgas which is combined and fed to a single tailgas cleanup unit.  This unit vents to two parallel thermal oxidizers.  These two thermal oxidizers exhaust to a single stack with a single CEMS.
•	Part II, Section 1, Question 4:
ExxonMobil’s energy management system for Downstream and Chemical operations, entitled Global Energy Management System, or GEMS, utilizes international best practices and benchmarking to identify energy efficiencies at our refineries and chemical plants.  The system utilizes a common methodology to identify and close performance gaps, sustain progress, and drive plants toward leading-edge energy performance.  Since 2000, we have used GEMS to systematically identify and address operational efficiency opportunities. We have identified ways to improve energy efficiency at our refineries and chemical plants by 15 to 20 percent and have captured over 60 percent of these opportunities to date.

 GEMS is based on a three-step approach to performance improvement:
• Address base case performance opportunities by operating existing facilities optimally and efficiently through application of best practices.
• Identify economic investment opportunities above an optimized base for step-change improvement to address structural differences.
• Implement strong management systems to provide the rigor and discipline necessary to sustain progress and drive continuous improvement.

GEMS is a layered approach to energy management.  It starts with the identification of key energy variables and establishes targets for safe, reliable, energy-efficient operations.  Secondly, diagnostic
indicators focus on system health and implementation of improvement plans.  A key measure is “lost opportunity”, which is the economic value of the gap between a key energy variable and its target
value.  Monetizing gaps helps prioritize work and focus resources.  And finally, Global Measures summarize bottom line performance for corporate and plant management. 

As part of the energy management process ExxonMobil conducts GEMS Assessments at sites to deliver best practices and measures.  The Assessment progresses through three stages:
• It takes several months to prepare for a GEMS Assessment.  A key step is selection of a team of technical specialists from across the global organization and plant personnel familiar with local
operations and practices.
• Execution of the Assessment can take anywhere from a couple of weeks to a couple months depending on site size and complexity.  During the assessment the team looks at process units, major
equipment, and utilities systems to identify gaps.  The team also looks at plant configuration to identify project opportunities such as advanced controls and optimization, heat integration, and waste
heat recovery projects.
• The Assessment deliverables include gap-closing options and a cost/benefit analysis for each item identified in the gap assessment.  A multi-year plan is then established that balances the portfolio of
operational improvement and facilities enhancements along with other business and investment needs.  All ExxonMobil refineries in the U.S. are in the GEMS program, and the initial energy management
Assessments were performed a number of years ago.  Our sites are now in the implementation phase of this process.
•	Part II, Section 1, Question 6, Table 1-3:  Steam Demand by Process Unit:  General Note - there are additional steam consumers in the refinery, but they are not process units (e.g., flares) as defined in the instructions and steam usage has not been provided in this table.
•	Part II, Section 3, Table 3-1:  Equipment and Leak Detection Information for Process Units, column titled "Flanges & Connectors, Gas & Light Liquid" - the count does not include monitored connectors. All monitored connectors are listed under 'Other' components.
•	Part II, Section 5, Catalytic Cracking Units, Table 5-1:  "Fresh Feed Capacity" (bbl/cd) is as quoted in Oil & Gas Journal's International Refining Survey.
•	Part II, Section 5, Catalytic Cracking Units, Table 5-1:  For the SCR specified as the NOx control, the control device began operations in November 2010.
•	Part II, Section 7, Delayed Coking Units, Table 7-1:  "Feed Capacity" (bbl/cd) is as quoted in Oil & Gas Journal's International Refining Survey.
•	Part II, Section 7, Delayed Coking Units, Table 7-1:  "Coke Production Capacity" (tons/cd) is as quoted in Oil & Gas Journal's International Refining Survey.
•	Part II, Section 8, Catalytic Reforming Units, Table 8-1:  "Feed Capacity" (bbl/cd) is as quoted in Oil & Gas Journal's International Refining Survey.
•	Part II, Section 9, Sulfur Recovery Units, Table 9-1:  For Units 10E, 10W and 11, the combined capacity (as reported in Oil & Gas Journal) is 580 long tons / calendar day.
•	Part II, Section 9, Sulfur Recovery Units, Table 9-1:  "Primary Sulfur Pit Maintenance Time in 2010 (hr/yr)" is as reported to EPA NSR Consent Decree Semi-Annual Reports in Attachment 2 "Identification of Any Exceedances of Emission Limitations or Standards".
•	Part II, Section 9, Sulfur Recovery Units, Table 9-1:  For Units 10E and 10W - A note on unit configuration - These are two parallel Claus units that vent tailgas which is combined and fed to a single tailgas cleanup unit.  This unit vents to two parallel thermal oxidizers.  These two thermal oxidizers exhaust to a single stack with a single CEMS.
•	Part II, Section 12, Flare Information, Table 12-1:  Regarding the column entitled "Flare Management Plan", The site flares are not subject to "Flare Management Plan" requirements but is providing the information per EPA's list of comments.
•	Part II, Section 14, Heat Exchange (Cooling Water) Systems, Table 14-1:  Regarding Gas or Chemical Addition Rate Value, note that that the addition rate for each cooling tower is based on a flow weighted average of throughput. No individual rate information was available.  In addition, chemical additives besides sodium hypochlorite are used, but the database only allows for a single chemical to be identified.  The other chemicals (e.g., corrosion inhibitors) are used in lesser quantities.
•	Part II, Section 15, Wastewater Collection & Treatment, Table 15-1:  Regarding average steam usage rates for Unit 38, this Benzene Removal Unit has an air stripper and does not use steam.
•	Part II, Section 15, Wastewater Collection & Treatment, Table 15-2:  Regarding Wastewater Generation Rate, there are additional wastewater generators in the refinery, but they are not process units (e.g., flares) as defined in the instructions and wastewater generation rates have not been provided in this table.
•	Part III, Non-Routine Emissions:  There were no planned turnaround events for the refinery in 2010.  As such, several unit startup/shutdown scenarios are not represented for the requested timeframe.
•	Part V, Log of Source Tests and Monitoring Data Provided:  General Footnote regarding source tests - Engineering tests not conducted in accordance with EPA methods have not been included in this submittal.


plant_name:
Marathon Petroleum Company LP, Illinois Refining Division

name_of_parent_company:
Prior to and including June 30, 2011: Marathon Oil Corporation; After June 30, 2011: Marathon Petroleum Company LP

notes:
PART I - GENERAL FACILITY INFORMATION

- General:  The 2010 Marathon Oil Corporation revenue was $72,321 million.  The 2010 Refining, Marketing & Transportation segment revenue was $62,487 million.
- Parent Company:  Number of employees in parent company:  29,677 employees including subsidiary companies.
- Process Units:  12-Gasoline Blending; Capacity is an estimate based on process knowledge and historical operation (Products).
- Process Units:  12-Gasoline Blending; Actual Throughput was obtained from the PACE-CTR software system (Products).  Actual throughput does not include ethanol, which is blended at off-site terminals.
- Process Units:  71-MTBE; MTBE is no longer manufactured at the Robinson refinery.  Equipment in the old MTBE process unit is being used to condition feedstocks for other process units.
- Process Units:  71-MTBE; Capacity is based on Depropanizer feed.  ORU feed capacity is 11,688 bbl/day (Technical Services).
- Process Units:  83-Unsat Gas/Light Ends Plant; Capacity (total) is the design gasoline rate (39,740 bbl/day) plus the design LPG rate (13,492 bbl/day) (Technical Services).
- Process Units:  83-Unsat Gas/Light Ends Plant; Actual throughput (total) is the gasoline production plus LPG production (Technical Services).
- Process Units:  83-Unsat Gas/Light Ends Plant; Steam demand is included with the steam demand reported for 82-FCCU.

SECTION 1. ENERGY MANAGEMENT

- Energy Management Plan:  Marathon is constantly evaluating a wide range of projects and programs to maintain and improve energy performance.  Economically attractive projects are incorporated into the strategic and business planning process at each location.  We have a corporate Energy Technologist and Energy Engineers at each of our refinery sites dedicated to these activities.  Marathon promotes and tracks energy efficiency improvement within our operations.  In 2009, we instituted a new metric, the Marathon Energy Index to more effectively measure progress and improve communications to employees.  This has had a positive impact on elevating the energy awareness of all employees.  In 2009, Marathon became an EPA ENERGY STAR partner company.  This is a higher level corporate commitment to energy efficiency.  Marathon has made this broader commitment to energy efficiency in both the upstream and downstream operations.  A corporate energy team was created in early 2009 and has been focusing on opportunities throughout Marathon’s operations.  In addition, Marathon instituted a new energy intitiative in 2010.  The Focus on Energy program is designed to identify specific and actionable metrics in daily operations and to make energy incentives more visibile to refinery operations personnel.  The intitative is also expected to identify additional medium and long-term improvements available for implementation.  We completed 86 detailed unit reviews, identifying over 1,500 potential energy metrics and over 600 items for potential projects andoperations modifications.  During the balance of 2011, these will be condesnsed to the most critical items and tracked by daily reports to operations and management.

- Electricity and Steam Generation Information:  Steam generating capacities (lb/hr) for 59F-3, 59F-4, and 59F-6 are estimates (Technical Services) based on 1 lb of 600# steam produced per 1,500 Btu.
- Electricity and Steam Generation Information:  Steam generating capacities (lb/hr) for 66E-1 and 67E-1 are estimates (Technical Services) based on 1 lb of 50# steam produced per 1,025.7 Btu [973.3 Btu/lb to vaporize boiler feed water + 52.4 Btu/lb to superheat from 250oF (1180.3 Btu/lb) to 350oF (1232.7 Btu/lb)].

SECTION 2. PROCESS HEATERS

- General:  The total combined rated heat input capacity for 3F-1 and 3F-2 is 315 MMBtu/hr.
- General:  The total combined rated heat input capacity for 16F-3A, 16F-3B, 16F-3C, and 16F-3D is 625 MMBtu/hr.

SECTION 3. EQUIPMENT LEAKS - PROCESS UNITS

- Data for 73-No. 1 Amine Regeneration is included with 69-Distillate Hydrotreater.  This is due to the configuration of the FELDAR database.
- Data for 16-Naphtha Hydrotreater is included with 16-Platformer.
- LDAR:  Average methane concentrations were estimated by Technical Services and are provided in mole percent.
- LDAR:  Number of pumps/valves in light liquid service was obtained from the FELDAR database.
- LDAR:  Number of compressor seals was obtained from the FELDAR database.
- LDAR:  Number of valves in gas service was obtained from the FELDAR database.  Valves in fuel gas and natural gas services were then manually backed out and reported in Table 3-2.  Component counts for valves in fuel gas and natural gas services are estimates based on the number of cylindrical/box heaters and SIS fuel gas skids.
- LDAR:  Number of pumps/valves in heavy liquid service was estimated based on the type and size of the process unit.
- LDAR:  Number of flanges and connectors in gas/light liquid service was estimated by multiplying the total number of gas/light liquid valves by 2.5.
- LDAR:  Number of flanges and connectors in heavy liquid service was estimated by multiplying the total number of heavy liquid valves by 2.5.
- LDAR:  Number of open-ended lines was estimated by multiplying the total number of ¾”-valves in gas and light liquid service by 0.54.  This assumption is based on an industry study that correlates the number of ¾”-bleeder valves to open-ended lines.
- LDAR:  Gas and liquid sampling connections were obtained from the refinery’s laboratory sample list.
- Pressure Relief Devices; Atmospheric PRDs in Gas Service, Describe your monitoring system:  All pressure relief devices in gas service are monitored via Method 21 quarterly for venting and for leaking components.  If any component is found leaking, repairs are completed within the 5-day and 15-day requirements.  Any PRD in gas service found venting in excess of 500 ppm will be monitored and repaired according to the requirements of NSPS GGG/GGGa, MACT CC, and the Illinois Administrative Code.
- Pressure Relief Devices;  Atmospheric PRDs in Liquid Service, Describe your monitoring system:  All pressure relief devices in liquid service are monitored via Method 21 quarterly for venting and for leaking components.  If any component is found leaking, repairs are completed within the 5-day and 15-day requirements.  Any PRD in liquid service found venting in excess of 500 ppm will be monitored and repaired per the refinery’s Enhanced LDAR program.

SECTION 3. EQUIPMENT LEAKS - GAS SYSTEMS

- Data for 73-No. 1 Amine Regeneration is included with 69-Distillate Hydrotreater.  This is due to the configuration of the FELDAR database.
- LDAR:  Average methane concentrations were estimated by Technical Services and are provided in mole percent.
- LDAR:  Component counts for valves in fuel gas and natural gas services are estimates based on the number of cylindrical/box heaters and SIS fuel gas skids.
- LDAR:  For the number of pieces monitored, the refinery is not required to monitor equipment in natural gas service. All valves in fuel gas service (not included difficult-to-monitor) are monitored quarterly.

SECTION 5. CATALYTIC CRACKING UNIT

- 04-Unicracker is NOT a catalytic cracking unit.  There is a non-removable entry for 04-Unicracker in Section 5 which exists due to the description category applied to the unit in Question 16 (Part I - General Facility Information).

SECTION 8. CATALYTIC REFORMING UNIT

- General:  Operating pressure for 03-Ultraformer is 175-210 psig (192.5 psig average).
- General; Average Annual Regeneration Frequency:  For 03-Ultraformer, No. 1 reactor is regenerated every 3-4 wks, No. 2 reactor is regenerated every 2-3 wks, and the other three reactors are regenerated every 2 weeks (Operations).
- General; Average Annual Regeneration Time:  For 03-Ultraformer, 30 hours per cycle (Operations).
- General; Coke Burn-off Cycle Duration per Cycle:  8-12 hours for 03-Ultraformer, or an average of 10 hours (Operations).

SECTION 9. SULFUR RECOVERY UNIT (SRU)

- General; Primary Sulfur Pit Maintenance Time in 2010 (hr/yr):  For 62-No. 1 Sulfur Recovery Unit, the No. 1 sulfur pit (62D-1) was out of service for 22 hours in 2010 due to a mechanical failure.
- General; Primary Sulfur Pit Maintenance Time in 2010 (hr/yr):  For 63-No. 1 Sulfur Recovery Unit, the No. 2 sulfur pit (63D-1) was out of service for maintenance for 21 days during the 2010 turnaround. Turnarounds occur every 4 years for each unit (4 years between 62D-1 maintenance, 4 years between 63D-1 inspection).  The pits are out of service for maintenance each turnaround.

SECTION 12. FLARES

- Flare 84F-1 serves the following process units:  01-Crude Unit, 02-Ultrafiner, 03-Ultraformer, 04-Unicracker, 07-HF Alkylation, 08-No. 1 Sat Gas, 23-No. 2 Sat Gas, 16-Naphtha Hydrotreater/Platformer, 71-MTBE, 82-FCCU, 21-Tank Farm, 69-Distillate Hydrotreater.
- Flare 84F-2 serves the following process units:  74-Gasoline Desulfurization Unit, 77-Penex, 87-Special Coker, 90-Regular Coker.
- Flare 84F-3 serves the following process units:  62-No. 1 Sulfur Recovery Unit, 63-No. 2 Sulfur Recovery Unit, 66/67-Tailgas Treatment Units, 64-Sour Water Stripper, 09/73-Amine Regeneration, 76-Penex Feed Splitter, 82-FCCU, 21-Tank Farm.
- Flare 84F-4 serves the following process units:  62-No. 1 Sulfur Recovery Unit, 63-No. 2 Sulfur Recovery Unit, 66/67-Tailgas Treatment Units, 64-Sour Water Stripper, 09/73-Amine Regeneration, 69-Distillate Hydrotreater.
- Flare 84F-5 serves the following process units:  01-Crude Unit, 02-Ultrafiner, 03-Ultraformer, 04-Unicracker, 07-HF Alkylation, 08-No. 1 Sat Gas, 23-No. 2 Sat Gas, 16-Naphtha Hydrotreater/Platformer, 71-MTBE, 82-FCCU, 21-Tank Farm, 69-Distillate Hydrotreater.
- Flare 84F-6 serves the following process units:  01-Crude Unit, 02-Ultrafiner, 03-Ultraformer, 04-Unicracker, 07-HF Alkylation, 08-No. 1 Sat Gas, 23-No. 2 Sat Gas, 16-Naphtha Hydrotreater/Platformer, 71-MTBE, 82-FCCU, 21-Tank Farm, 69-Distillate Hydrotreater.

SECTION 13. FUEL GAS TREATMENT UNITS

- 09/73-Amine Regeneration consists of two process units, 09-No. 2 Amine Regeneration and 73-No. 1 Amine Regeneration, that must be operated together to treat refinery fuel gas.
- 09/73-Amine Regeneration serves the following process units:  02-Ultrafiner, 04-Unicracker, 08-No. 1 Sat Gas, 16-Platformer, 23-No. 2 Sat Gas, 76-Penex Feed Splitter, 83-Unsat Gas/Light Ends Plant, 90-Regular Coker.

SECTION 14. HEAT EXCHANGE (COOLING WATER) SYSTEMS

- Cooling Tower 1 serves the following process units:  74-Gasoline Desulfurization Unit, 77-Penex, 82-FCCU, 83-Unsat Gas/Light Ends Plant, 87-Special Coker, 88-Coker Naphtha Splitter, 90-Regular Coker.
- Cooling Tower 2 serves the following process units:  01-Crude Unit, 02-Ultrafiner, 03-Ultraformer, 04-Unicracker, 07-HF Alkylation, 16-Naphtha Hydrotreater/Platformer, 62-No. 1 Sulfur Recovery Unit, 63-No. 2 Sulfur Recovery Unit, 66/67-Tailgas Treatment Units, 69-Distillate Hydrotreater, 73-No. 1 Amine Regeneration.
- Cooling Tower 3 serves the following process units:  08-No. 1 Sat Gas, 09-No. 2 Amine Regeneration, 11-Merox Treater, 23-No. 2 Sat Gas, 71-MTBE, 76-Penex Feed Splitter.

SECTION 16. PRODUCT LOADING OPERATIONS

- According to the MPC Terminals Group, the Robinson Terminal can load 3 gasoline tank trucks every 15 minutes (8,500 gallons per truck), 4 kerosene tank trucks every 15 minutes (7,500 gallons per truck), or 4 distillate tank trucks every 15 minutes (7,500 gallons per truck).
- The “Capacity loading throughputs (gal/yr)” for the Robinson Terminal are very conservative estimates based on a hypothetical scenario in which one product (gasoline, kerosene, or distillate) is continuously loaded into tank trucks for 365 consecutive days.


notes:
See attached "IL2A0430 ICR Component 1 Tool Notes_non-CBI.doc"


notes:
Part I - General Facility Information
Steam consumption rates for ARU 200, ARU 300, and ARU 301 are reported as the same because these entities are part of the same "unit," but have separate throughputs reported in Solomon (i.e., the source of the throughput data) and there is no way to conservatively divide the steam consumption.

Steam consumption rates for No. 4 Ultraformer (Hydrotreater) and No. 4 Ultraformer (Reformer) are reported as the same because these entities are part of the same "unit," but have separate throughputs reported in Solomon (i.e., the source of the throughput data) and there is no way to conservatively divide the steam consumption.

Section 3 - Equipment Leaks - Process Units
Sampling connection component counts are not included as they are captured in the gas/vapor or liquid valve counts.  The component counts for Propylene and Asphalt Rail Loading units represent the component counts for the Propylene and Asphalt Truck Loading units, i.e., these units are the same, but the component counts are only represented in once.

Section 3 - Equipment Leaks - Gas Systems
The natural gas system component counts are equivalent to the fuel gas system component counts due to lack of more creditable information.

Section 4 - Storage Tanks
P-1 and P-2 are square pits with dimensions (Length X Width) of 110 feet X 20 feet.  The height represents the depth of the pit.

Section 7 - Delayed Coking Unit
The single coke drum height provided is the tangent to tangent measurement for each drum.  The quench water is also used as coke cutting water (i.e., Code 5 for "Quench Water Disposition").

The average quench water make-up rate is based on engineering judgment as the quench water flow to the unit is not measured.

Section 9 - Sulfur Recovery Unit
The SRU has several back-up controls or reduction measures.  Since the database restricts the ability to enter multiple, the "other" designation was selected and the three controls/reduction measures were input in the appropriate response box.

Section 14 - Heat Exchange (Cooling Water) Systems
In some cases, a unit will be serviced by more than one cooling towers - this is apparent in the "Units Serviced" section.  Please note that cooling towers servicing FCU 500, FCU 600, or 11B Coker may actually or also be servicing the vapor recovery unit associated with these units, i.e., VRU 100, VRU 200, and VRU 300, respectively.

Cooling tower CT-725 services the Sodium Bisulfate (SBS) tail gas unit (TGU) at the SRU.

Section 16 - Product Loading Operations
The sulfur loading operations listed (i.e., truck and rail) have "capacity loading throughput[s]" in units of long tons per year.


energy_management_plan_description:
Insulation on distribution line and heat recovery.

notes:
Table 3-1:  No heavy liquid equipment count is readily available.
Table 16-1:  Truck loading rack capacity is CBI in Part 1 Question 16.
Table 3-1:  No equipment count information is available for the barge facility located off-site.
Table 15-1:  There are two oil water separators and aerated surface impoundments.


legal_owner_name:
Coffeyville Resources Refining & Marketing

plant_name:
Coffeyville Resources Refining & Marketing, LLC

energy_management_plan_description:
The energy management plan includes a heater/boiler team which takes a proactive role in preventative and general maintenance of these units.


notes:
Part I General Facility informantion                                                                                                              -  Process Units - Added Tank Farm (Products, Intermediate, and Crude Oil Storage) as a unit so that Equipment leak information associated with that unit could be included.  Capacity is the entire storage capacity  of the tanks.  Average throughput on a daily basis was the average %inventory for the year multiplied by the inventory capacity.   [stop]                               Part II  Section 3 -  Pump monitoring - Alll monitored pumps are monitored monthly by Method 21 at listed leak detection as well as weekly visual inspection.  Assumed the leak definition was more important.    Refinery procedures dictate operators look for sensory leaks on all hydrocarbon process equipment, therefore equipment was only listed as monitored if inspected by method 21.  All hydrocarbon equipment is reviewed for sensory leaks.  All valves and connectors, even those associated with "open-ended lines" have been accounted for in the appropriate inventories.  Therefore those components were left zero.  Unless it was meant to identify those open-ended valves deemed as non-compliant.  In that case, NCRA works diligently to ensure that those are not present and therefore we have none to report.  [stop] Part II Section 12 - Flares - In 2010 NCRA removed one flare from service PG-1 and started up two new flare NCU-5 and NCU-6.  Information for the two new flares was included because that was the current set up at the time.  [Stop]                                                                      Part II Section 16 - Product Loading Operations - The capacity is an environmental limit included in the construction permit for gasoline loading.  This does not include distillates.  [Stop]                                                                                                                 General Comment:  This information has been gathered and reviewed to the best of our ability in the time allowed.


energy_management_plan_description:
The goal is to minimize energy cost without affecting production or quality through monitoring of energy efficiency with cost benefit analysis & action plan to reduce energy consumption. It reduced steam production, fuel gas consumption & electricity use.


plant_name:
Marathon Petroleum Company - Catlettsburg Refinery

name_of_parent_company:
Before June 30, 2011: Marathon Oil Corporation, After June 30, 2011 Marathon Petroleum Company LP

energy_management_plan_description:
Marathon is constantly evaluating a wide range of projects and programs to maintain and improve energy performance.  Economically attractive projects are incorporated into the strategic and business planning process at each location.

notes:
1.  Component 1 Part 1 Question 16 - Unit 2-035 was broken down into two parts since it is a hydrotreater and isomerization unit combined.  Further sections of the ICR database accounted for this unit as one consolidated unit since other information was not independently tracked for each part.   Also unit 1-066/2-066 is a fuel gas treatment unit.  The throughputs shown are in MMSCFD since this unit is in gaseous service versus liquid service.   2.  Component 1 Part 2 Section 3 - Heavy Liquid equipment leak components for various sources were estimated since true counts were unavailable.   3.  Component 1 Part 2 Section 3 - Some natural gas components were estimated since they are not covered in the LDAR program and exact counts are not available.    4.  Component 1 Part 2 Section 2 - Some of the tank heaters are made up of several small heaters (count 1-3).  The value shown represents the total firing rate combined for those small heaters.   5. Component 1 Part 2 Section 5 - The FCCU has analysis with many levels less than the number shown.  In most cases, the lowest readings are the detection levels for the metal available bia the identified laboratory test method.   6.  Component 1 Part 2 Section 15 - Unit 2-40 is the wastewater benzene recovery unit that uses nitrogen as the stripping agent versus steam which is the closest choice in the database.    7.  Component 1 Part 2 Section 14 -  Several cooling towers are interconnected making chemical addition and makeup water impossible to calculate for each individual tower.  1-8-CT2 and 3 are interconnected.  2-603 CT-3, 4 and 5 are interconnected.  CT-3 shows the combined flow and chemical treatment rate for all three as does 1-8-CT-2 for 1-8-CT2 & 3.


notes:
During the calendar year 2010, the facility operated intermittently until Feb. 10, 2010 when the plant was idled due to lack of adequate crude oil supply.  The plant boiler operated off of purchased natural gas until shutdown on March 19, 2010.  The plant remained idle for the rest of 2010 with intermediate and final product tanks being deinventoried and cleaned out.  Natural gas blankets were maintained in process vessel interiors to mitigate corrosion.                                                                                                                                                                                                                                                 The facility was operational until late 2006 when it was idled.  The facility remained idled during 2007, 2008, and the first half of 2009 during which it went through an ownership change, a bankruptcy filing, and another ownership change.  The facility was restarted during June 2009 and operated for the remainder of that calendar year.                                                                                                                         The facility has remained in idle status during 2011 and is being marketed for sale.                                                                                                                                                                                                                                                        The small wastewater treatment plant which serves the facility is classified as an insignificant activity under the current Title V air permit and as a minor source under the current KPDES discharge permit.  BTEX monitoring (including benzene) was dropped as a KPDES permit requirement in 2006 based on historical data with consistent "BDL" content in discharge point grab samples.  Detailed records are neither required or kept on specific water source points.                                                                                                                                                                                                                                                    There were no non-routine emission events during the 2010 operating period.


physical_address:
4646 LA HWY 3059, LAKE CHARLES, LA 70615

mailing_address:
PO BOX 12653, LAKE CHARLES, LA 70612-2653


notes:
Part II, Section 1: Fuel Consumption
Natural gas: Calculated by using fuel consumption from heaters in GHG calculations and using assumed flare natural gas usage from EIS calculations (GHG calc. not available for flare).
Coal, Purchased Electricity, Purchased Steam: From EIA-820


plant_name:
CITGO Petroleum Lake Charles Manufacturing Complex

energy_management_plan_description:
1.  Energy tracking  2.  Operation & maintenance programs  3.  Capital projects where justified   4.  Process adjustments when applicable  5.  Advanced process controls  6.  Participation in benchmark studies

notes:
Petroleum Refineries Information Collection Request – Component 1 Notes:
LA3C0560 – CITGO Petroleum LCMC

Part I – General Facility Information:

Products Produced Information:

1.	The data was obtained from the Refinery Yield Report which is consistent with the data submitted to EIA (form EIA-810). 

Process Unit Information:

1.	Process Units 304, 342, 343, 346, 3501PR, and 3501 PG are considered storage and/or logistics (oil movement) units and therefore have no reported unit throughput capacity or actual unit throughput.   These units are included in the process units to provide LDAR information.   
2.	Process Units 342A, 342B, 342C, 342D, and 3501 are marine loading docks while process unit 3003 is a truck terminal.  Throughputs for these units are reported in Part II, Section 16 – Product Loading Operations. 
3.	Process unit 453 is the Power and Utilities Area for the refinery.  It has been included since there are LDAR components with this unit.   No throughput or steam use was reported with this unit.  
4.	For those units that are net steam producers, the steam consumption for those process units is shown as a negative value.   
5.	The hydrotreating sections of the Process Units 311, 315, 327, and 357 are considered part of these units and therefore not reported as separate process units. 
6.	The light ends handling section of Process Unit 320 is considered part of this unit and therefore not reported as a separate unit. 
7.	The vacuum tower of Process Unit 459 is considered part of this unit and therefore not reported as a separate unit. 
8.	Process Unit 314 is a centralized amine stripping unit and not a production unit.   Throughput for this unit is therefore not reported. 
9.	Process Unit 336 is a Sulfuric Acid Plant.  This unit is being reported since it has associated heaters and is a steam consumer.   However, process unit throughput was not reported since Sulfuric Acid Plants (40 CFR Subpart H) were not considered part of this request.   
10.	Process Unit 337 is a product treating unit composed of several treatment processes for different processes.   Since there is no production associated with this facility, process unit throughput was not reported. 
11.	Process Unit 424L is the refinery laboratory and was identified as process unit to account for its wastewater and benzene contribution to the wastewater treatment facility.  
12.	The “normal” throughput for Process Units 315 (A Reformer) and 703 (Mixed Xylenes Unit) is typically less than the annual capacity since these units are run based on seasonal gasoline demand or market conditions (for xylenes).   

Part II – Process and Emissions Information: 

Section 1 – Energy Management:

1.	The data is consistent with the data submitted for the EIA-846B -- 2010 Manufacturing Energy Consumption Survey.  
2.	Hydrogen purchased includes process hydrogen from a nearby ethylene production facility owned by another company and pipeline grade hydrogen.   
3.	B Reformer and C Reformer have process heaters (357B403/404/405 and 327B503/504/505, respectively) that produce steam from the convection section of these process heaters.  The reported boiler heat input is the 2010 estimated heat input used to produce steam from these process heaters.  
4.	Most of the waste heat boilers are heat exchangers.   No heat inputs are provided for these exchangers.  The reported steam generating capacity is based on calculated 2010 steam generation.   
5.	Process heaters that have steam coils that superheat steam generated elsewhere are not included in this section.   
6.	Energy efficiency measures are only listed for the steam boilers and process heaters that produce steam.  
7.	Some waste heat boilers involve steam drums with multiple heat sources (exchangers).  These boilers are noted as drums in the description.  

Section 2 – Process Heaters:

1.	Steam boilers are not reported in this section per the ICR instructions.  Only process heaters that serve process units are reported.  
2.	For those single process heaters with multiple stacks (309B101 and 308B1), only one process heater will be reported.
3.	For multiple process heaters with a single stack, the process heaters will be reported as single heater.   If all processes are similar in construction and operation, no notes will be provided.  
4.	Process heaters 315B102/103/104/105/106 are adjacent process heaters located in a same process unit and have a common stack and are considered a single emission point.   Process Heaters 315B102/103/104/104/105 are vertical cylinder heaters with balanced draft and air preheaters used 90% or more of the time while 315B106 is a cabin / box heater with natural draft and no air preheater present.   These heaters were coded as 315B102/103/104/104/105 with vertical cylinder heaters with balanced draft and air preheaters used 90% or more of the time
5.	Process heaters 327B501/5022/506 are adjacent process heaters located in a same process unit and have a common stack and are considered a single emission point.   Process heater 327B501 was operated 8760 hours in 2010 while 327B501/502 was operated 8688 hours in 2010.  These heaters were coded as operating 8760 hours in 2010.  
6.	Process heaters 320B1/2/3/4/5 are adjacent process heaters located in a same process unit and have a common stack and are considered a single emission point.   Process Heaters 320B1/2 are vertical cylinder heaters while 320B106 are a cabin / box heaters.   These heaters were coded as cabin / box heaters.
7.	Process heater downtime hours were not included in Operating Hours.  

Section 3 – Equipment Leaks

1.	The reported average methane concentration for each process unit does not include those LDAR components handling refinery fuel gas in the process unit.   
2.	The average methane concentration for refinery fuel gas is reported in Section 3 – Equipment Leaks – Gas Systems.  
3.	Valves associated with sample systems, sight glasses, gauges, diaphragms, and other instrumentation are included in the valve counts.  A count of the sampling systems could not be extracted from the LDAR database.  
4.	The number of heavy liquid valves is based on the number of heavy liquid pumps and valve to pump ratio of 41 valves per pump. 
5.	For the majority of process units, the number of flanges and screwed fittings is based on the number of valves using a valve to flange ratio.   For the HON Process Units 311 and 703, the number of flanges is based on actual tagged components.  
6.	There should be no open ended lines.  All open ended lines not in use are immediately closed.  
7.	The valve count for light liquid and gas valves do not include the pressure relief valves.  
8.	Refinery fuel gas components are included in the process units and an exact count could not be made using the LDAR database.   The total number of valves reported in refinery gas service is an estimate based on limited field surveys.  This number includes those components associated the refinery fuel gas system downstream of the fuel gas mix drums and does not include components associated the process unit make gas streams or the fuel gas treatment units.   As such, these components are “double counted” since there was no effective way to extract these components from the process unit counts. 
9.	Natural gas component are not included in the fugitive equipment monitoring program and an exact count of these components does not exist.   The total number of valves reported in natural gas service is an estimate based on limited field surveys.  
10.	The total number of Pressure Relief Devices in liquid service only includes those valves that are in light liquid service.   Heavy liquid PRDs are not included.  
11.	Most of the PRDs in process units that can release to the atmosphere can be monitored by the pressure or level indicators for the vessel being protected.  In these cases, the quantity of the compound released can be determined by the size and configuration of the PRD.  
12.	Most liquid PRDs in oil logistics areas are thermal relief devices and can not be monitored.     
13.	All PRDs not going to the atmosphere are either directed to the flare systems or fuel gas.   Process Units 301, 302, and 308 have PRDs that can go to a fuel gas compressor suction header.  
14.	PRD releases now recovered through a flare gas recovery system (Process Units going to 320B12 and 327B11) are routed to the fuel gas system except when the releases result in flows greater than the flare gas recovery system capacity.  

Section 4 – Storage Tanks

1.	Per instructions in Help documentation, only those hydrocarbon tanks greater than 10,000 gallon capacity and storing hydrocarbon materials greater than 0.1 psi are reported.  
2.	Since no hydrocarbon products with a vapor pressure greater than 0.1 psi are storage in fixed roof tanks vent to the atmosphere, no such tanks are reported or coded as such.  
3.	For vertical pressure tanks, the horizontal length is reported has the tank height.  
4.	Tanks that are believed to permanently out of service are not reported.  
5.	Tanks that were out of service but are expected to return to service are reported with the throughput shown as zero.  
6.	If the tank installation date was used as the last degassing date if the tank has not been taken out of service since being put in service.   
7.	All pressurized tanks were noted as dry drain tanks since these tanks vapor dry to flare system as part of the degassing process. 

Section 5 – Fluid Catalytic Cracking Units 

1.	Process Unit 320 is a hydrocracking unit but is listed in the ICR as a catalytic cracking unit.   No data is provided for the process unit.    

Section 7 – Delayed Coking Units 

1.	The height of the drums is based on bottom flange to top flange on the drums.   
2.	The water height in coke drum when first vented to atmosphere is measured from bottom flange.
3.	“Tap” water is refinery well water.

Section 8 – Catalytic Reforming Units

No Comments

Section 9 – Sulfur Recovery Units

1.	The refinery has four sulfur recovery units that receive a common source of sour gas from the amine stripping unit and the sour water strippers.  As such, these multiple SRUs are considered part of single sulfur recovery plant (SRP).  This four SRU, in turn, send off gas to two tail gas units.   

Section 11 – Other Atmospheric Vents 

1.	Atmospheric Vents 316B, 317B, and 318B are associated with blow down drums in the cat cracking units and are primarily used to receive heavy oil components during maintenance activities of process equipments. 
2.	Atmospheric Vent 337F69 is associated a small process tank that stores methanol used in the gasoline caustic treating process in Process Unit 337.  

Section 12 – Flares

No Comments

Section 13 – Fuel Gas Treatment Units

1.	Fuel gas treatment units may have more than one amine contactor.   
2.	The estimated H2S concentration is based on actual H2S CEMS measurement at the fuel drum receiving the treated fuel gas and not exactly represented of the H2S concentration at the outlet of the fuel gas amine treating contactors. 
3.	The estimated total sulfur concentration is based on weekly fuel gas analysis of the fuel gas downstream of the fuel gas drum receiving the treated fuel gas.  

Section 14 – Heat Exchanger Systems 

1.	Circulation rates were based on design data or available flow rates.  
2.	Make up water flow rates were based on actual flow measures or calculations.  

Section 15 – Wastewater Collection and Treatment 

1.	The refinery has a sour water stripping unit which is listed as a separate process unit (359) but is also listed as a separate wastewater treatment process in this section under the wastewater unit (Process Unit 432).  
2.	The sour water stripping unit (359) consists of three separate and identical sour water stripping towers.  The steam usage is for all three sour water stripping towers.   
3.	VOC and HAP data by waste generator (process unit) was not reported since this data is not available. 
4.	The wastewater generation information for each process unit is the best estimate based on available information.  No additional testing was performed as part of this request.   See notes below for further explanation. 
5.	Benzene data by waste generator for the wastewater generation information was based on Subpart FF BWON Total Annual Benzene (TAB) and End of Line data.   This data is based on wastewater flows from the process units sent to wastewater system and includes the estimated hydrocarbon portion of the wastewater.   
6.	The wastewater generation information does not include slop oil sent to the slop oil system or sour water sent to the sour water system.   
7.	Some minor miscellaneous sources not associated with process units was not included in wastewater generation information.

Section 16 – Product Loading Operations 

1.	The refinery has four marine loading docks (noted as 342A, 342B, 342C and 342D).   There is also contiguous marine loading dock at the CITGO owned Clifton Ridge Terminal but not operated by the refinery.    
2.	There is a contiguous truck terminal adjacent to the Lake Charles Manufacturing Complex owned by CITGO but not operated by the refinery.       
3.	The reported capacity loading throughput is based on 2010 products loaded at each marine dock and truck loading rack. 
4.	The typical annual hours of operations for the marine docks is based on the number of hours to load the product during 2010.  
5.	The truck terminal is operated 24 hours a day every day of the year.  
6.	Truck and rail loading of sulfur and petroleum coke was not reported in this section.  

Part III – Non-Routine Emissions

No Comments

Part IV – Cost Data

1.	Capital cost data is being provided.  

Part V – Emission Monitoring and Source Test Data

1.	Process heater data was not included in the ICR based on the exclusion statement for these sources.  
2.	RATAs for continuous emission monitors were not include with the emission monitoring data since daily CEMS data is being provided. 
3.	For our FCCUs, we provided both the most recent Method 5B testing (a worst case operating scenario for our Wet Gas Scrubbers) and 2007 testing (normal operations for our Wet Gas Scrubbers).  
4.	No emissions testing was available for the delayed coking units. 
5.	The Subpart UUU compliance testing (Method 26A) for all three reformers was included along with our most recent Method 26A for C Reformer (Process Unit 327).  
6.	Methods 11, 18, and 22 testing is being provided for our flares if conducted after January 1, 2005.  
7.	Stack testing and CEMS monitoring data for our Sulfuric Acid Plant was not provided since Sulfuric Acid Plants (40 CFR Subpart H) were not considered part of this request.   
8.	For our two (2) Sulfur Recovery Unit Tail Gas Unit CEMS, the sulfur production was allocated based on engineering judgment based on available process data.   Note:  There are two Tail Gas Units that handle the four (4) SRUs.  
9.	The H2S CEMS for the B-11 flare was certified in late 2010.  Only data generated after the CEMS certification data is provided.   
10.	For our fuel gas CEMS, the production data (fuel gas flow rate) is based on available monthly averages which closely represent daily averages.


energy_management_plan_description:
We have in place an energy management system that looks at steam, fuel gas and electricity and balances the imports and exports to reduce the overall cost associated with energy.  This has resulted in utilizing more efficient electric motors in place of t

notes:
ConocoPhilips Lake Charles Component 1 EPA ICR Notes Section-Non-CBI
Part 1 Facility Information: The Lake Charles Refinery Dun and Bradstreet number is 02-337-0872, while the Excel Paralubles number is 01-097-1518
Part 1 Facility Information: The Annual Revenue is from the COP US R&M Revenue figure
Part 1 Facility Information: The number of employees at the Refinery includes employees only and not contractors

Part 1 Facility Information: Question 13 - Note: Although this question is somewhat incomprehensible to ConocoPhillips in that the "facility" does not have a Board of Directors and for other reasons, we believe that this statement "best" applies of the three statements offered
Part 1 Facility Information: Question 16 Process Type – Note: All Truck Loading Units are also Rail Loading

Part 2 Section 3 Table 3-1: General Notes –
1. All gauges, sight glasses & diaphragms are treated as connectors.
2. Hatches are covered by BWON and not subject to LDAR as connector
3. Heavy Liquid counts for connectors & valves on additional tabs

Part 2 Section 3 Table 3-2: General Notes – 
1. All gauges, sight glasses & diaphragms are treated as connectors
2. Hatches are covered by BWON and not subject to LDAR as connector
3. There are no HL components in CVS or FG service

Part 2 Section 4 Storage Tanks: Tanks CL-1, CL-2, CL-4, CL-5, T-5401, T-6002, 6003, 6004, 6009, 6010, 6011, 6012, 6015, 6018, 6020, 2021, T-76004, 76013, 76015, 76016 True Vapor Pressure is N/A because these are open top tanks.

Part 2 Section 4 Storage Tanks: Tank T-30 and T-404-OOS do not have a true vapor pressure because they were OOS in 2010

Part 2 Section 7 Delayed Coking Units: Unit ID’s 30 feed capacity is based on Maximum Demonstrated Capacity

Part 2 Section 9 SRU: Note – No. 6 SRU is permitted but has not been built
Part 2 Section 14 Heat Exchange: HE System ID’s Y1, Y2, Y2801, Y7 Water Make-up Rates are on level controls and not measured. 
Part 2 Section 14 Heat Exchange: All HE Systems gas or chemical addition rate note: Disinfectant (chemical addition) is not metered/ measured while injected. It is monitored by chloride residual and when the residual decreases, the pump stroke/ chemical injection is increased.
Part 2 Section 15 Wastewater Systems: If there are any issues viewing Wastewater process vent federal regulations, please refer to the Excel Spreadsheet version of Component 1.
Part 3 Section 1 Non-Routine Emissions: Releases on 2/1/2010, 4/12/2010, 4/22/2010, 4/26/2010, All 4/29/2010 Releases, All 5/4/2010 Releases, 5/6/2010, 5/7/2010, and 5/14/2010 H-3232 Bact Exceedance, 5/18/2010, All 5/25/2010 Releases, All 5/26/2010 Releases, 6/5/2010, 6/7/2010, 6/8/2010, 6/11/2010, 6/13/2010, 6/15/2010, 6/16/2010, 7/19/2010, 9/12/2010 Note the following:
“ For this particular heater, LCR is required to continuously monitor and record flue gas oxygen concentrations in accordance with "Use of Flue Gas Oxygen Monitors as BACT for Combustion Controls".  Anytime the heater operates outside of the "BACT Box", it is assumed that the permitted limits for Nox and CO were exceeded. There is no basis to calculate actual emissions”
Part 3 Section 1 Non-Routine Emissions:  The 4/9/2010 Release had ≤4 tons SO2 /ton acid produced
Part 3 Section 1 Non-Routine Emissions:  All Releases on 9/10/2010 have released  <1 lb of H2S each.


plant_name:
ExxonMobil Refining & Supply Baton Rouge Refinery

notes:
ICR RRR Baton Rouge Notes

Part 1 Question 11. Revenue is millions of dollars and the basis is U. S. Downstream (Refining and Fuels/Lubes Marketing) earnings after income tax.

Part 2 Section 1 Number 4. 
ExxonMobil’s energy management system for Downstream and Chemical operations, entitled Global Energy Management System, or GEMS, utilizes international best practices and benchmarking to identify energy efficiencies at our refineries and chemical plants.  The system utilizes a common methodology to identify and close performance gaps, sustain progress, and drive plants toward leading-edge energy performance.  Since 2000, we have used GEMS to systematically identify and address operational efficiency opportunities. We have identified ways to improve energy efficiency at our refineries and chemical plants by 15 to 20 percent and have captured over 60 percent of these opportunities to date.

 GEMS is based on a three-step approach to performance improvement:
• Address base case performance opportunities by operating existing facilities optimally and efficiently through application of best practices.
• Identify economic investment opportunities above an optimized base for step-change improvement to address structural differences.
• Implement strong management systems to provide the rigor and discipline necessary to sustain progress and drive continuous improvement.

GEMS is a layered approach to energy management.  It starts with the identification of key energy variables and establishes targets for safe, reliable, energy-efficient operations.  Secondly, diagnostic indicators focus on system health and implementation of improvement plans.  A key measure is “lost opportunity”, which is the economic value of the gap between a key energy variable and its target value.  Monetizing gaps helps prioritize work and focus resources.  And finally, Global Measures summarize bottom line performance for corporate and plant management. 

As part of the energy management process ExxonMobil conducts GEMS Assessments at sites to deliver best practices and measures.  The Assessment progresses through three stages:
• It takes several months to prepare for a GEMS Assessment.  A key step is selection of a team of technical specialists from across the global organization and plant personnel familiar with local operations and practices.
• Execution of the Assessment can take anywhere from a couple of weeks to a couple months depending on site size and complexity.  During the assessment the team looks at process units, major equipment, and utilities systems to identify gaps.  The team also looks at plant configuration to identify project opportunities such as advanced controls and optimization, heat integration, and waste heat recovery projects.
• The Assessment deliverables include gap-closing options and a cost/benefit analysis for each item identified in the gap assessment.  A multi-year plan is then established that balances the portfolio of operational improvement and facilities enhancements along with other business and investment needs.  All ExxonMobil refineries in the U.S. are in the GEMS program, and the initial energy management Assessments were performed a number of years ago.  Our sites are now in the implementation phase of this process.  
Part 2 Table 3-1.  Methane concentration is the percent calculated using a straight arithmetic average for the methane in gas streams by process unit.

Part 2 Table 3-1.  Gas sample stations include those used for LPG for LEU1, LEU3, ALKY, and AFHLA.

Part 2 Table 3-1.  
PSLA10 has 2 Agitators listed in ‘Other’ components monitored column.
PSLA9 has 1 Agitator listed in ‘Other’ components monitored column.
ALKY has 5 Agitators listed in ‘Other’ components monitored column.
AFPLA has 4 Agitators listed in ‘Other’ components monitored column.
KDLA has 1 Agitator listed in ‘Other’ components monitored column.
Oil Movements has 74 Agitators listed in ‘Other’ components monitored column.

Part 2 Table 3-1.  Fuel Gas is included in table 3-1 by process unit. Fuel gas can not be easily separated from process streams.

Part 2 Table 3-2.  Fuel Gas is included in table 3-1 by process unit. Fuel gas can not be easily separated from process streams, so it is not reported in table 3-2.

Part 2 Table 9-1. There are 3 claus trains. They are considered 1 unit and 1 sulfur plant. They use the same control devices and have the same emission points.

Part 2 Table 9-1. Primary Sulfur Pit Maintenance Time in 2010 (hr/yr) is based on the unit having a turnaround where maintenance was performed.

Part 2 Table 11-1 
CKRW/FD101 DECOKE operates less than 50 hours per year.
PSLA10/D-20 operates less than 50 hours per year.
PSLA10/FD10 operates less than 50 hours per year.
PSLA9/D-19 operates less than 50 hours per year.
PSLA9/FD29 operates less than 50 hours per year.

Part 2 Table 12-1. Flare No. 7 is used primarily by the ExxonMobil Baton Rouge Chemical Plant.

Part 2 Table 12-1. Flare No. 5, 8, 9, 17, 19, 20, 23, and 24 are refinery flares that most process units could use.

Part 2 Table 13-1. RGCU is a fuel gas collection system. Significant fuel gas treatment occurs on units prior to the collection system. Those units primary purpose is not fuel gas treatment. The towers on those units are listed here for completeness. The data provided is by tower not by unit.

Part 2 Table 14-1
In addition to sodium hypochlorite these chemicals are used to prevent corrosion and fouling of the process equipment.
HE System ID  or Description ,  	Unit IDs for Process Units Serviced by Cooling Water System	, Gas or Chemical Additive/ Disinfection Method, 	Gas or Chemical Addition Rate Units (volume or mass per time),  	Chemical Addition Location
HCN/CT-11, 	HCN, 	AEC3153, 	5.4, 	CT Basin
T210/CT-12, 	T210, 	AEC3153	, 6.1	, CT Basin
PSLA10/CT-17, 	PSLA10, 	AT206, 	11.3, 	CT Basin
PSLA9/CT-18	, PSLA9	, AT206	, 11.3, 	CT Basin
PSLA8/CT-19	, PSLA8, 	AT206	, 14.7, 	CT Basin
PSLA7/CT-20, 	PSLA7	, AT206, 	3.9, 	CT Basin
PSLA7/CT-21	, PSLA7, 	AT206	, 6.2, 	CT Basin
KDLA/CT-22	, KDLA, 	MS6206	, 4.2, 	CT Basin
KDLA/CT-22	, KDLA, 	AEC3198	2, 3.7, 	CT Basin
HHLA/CT-23E, 	HHLA, 	AEC3153, 	6.5	CT, Basin
PCLA3/CT-23W, 	PCLA3, 	AEC3153	, 15.5	CT, Basin
HCLA/CT-24	, HCLA, 	AEC3145, 	10.8, 	Central Make-up
HCLA/CT-24	, HCLA	, AZ8104	, 1.5, 	Central Make-up
LEU2/CT-25S	, LEU2	, AEC3198	, 8.5	, CT Basin
LEU2/CT-25S	, LEU2, 	MS6206	, 1.5	, CT Basin
PCLA2/CT-25N, 	PCLA2, 	AEC3145	2, 6.1	, Central Make-up
PCLA2/CT-25N, 	PCLA2, 	AZ8104, 	3.6, 	Central Make-up
PCLA2/CT-26	, PCLA2, 	AT206	, 13.7, 	CT Basin
LEU2/CT-27	, LEU2, 	AEC3198	, 13.9	, CT Basin
LEU3/CT-28, 	LEU3, 	AEC3198	, 10.6	CT Basin
LEU3/CT-28, 	LEU3, 	MS6206	, 1.9	, CT Basin
ALKY/CT-29	, ALKY, 	AT206	, 10.9, 	CT Basin
ALKY/CT-30	, ALKY, 	AEC3145	1, 7.4, 	Central Make-up
ALKY/CT-30, 	ALKY, 	AZ8104	, 2.4	, Central Make-up
LEU4/CT-31	, LEU4	, AEC3145, 	6.2, 	Central Make-up
LEU4/CT-31	, LEU4	AZ8104	, 0.1	, Central Make-up
LEU4/CT-32, 	LEU4, 	AEC3145	1, 2.3	, Central Make-up
LEU4/CT-32, 	LEU4	, AZ8104	, 1.7	, Central Make-up
LEU5/CT-33	, LEU5, 	AEC3145	1, 3.9	, Central Make-up
LEU5/CT-33	, LEU5, 	AZ8104	, 1.9, 	Central Make-up
LELA/CT-34E	, LELA	, AEC3145	, 3.1	, Central Make-up
LELA/CT-34E	, LELA, 	AZ8104, 	0.4, 	Central Make-up
LELA/CT-34W	, LELA	, AEC3145	, 3.2, 	Central Make-up
LELA/CT-34W,	 LELA, 	AZ8104, 	0.4	, Central Make-up
LEU6/CT-35, 	LEU6, 	AEC3145	, 5.4, 	Central Make-up
LEU6/CT-35	, LEU6	, AZ8104	0.7, 	Central Make-up
AFPLA/CT-36	AFPLA	AT206	14.3	CT Basin
CKRE/CT-37, 	CKRE	, AEC3198	, 13.1	, CT Basin
CKRE/CT-37	, CKRE, 	MS6206, 	2.4	, CT Basin
CKRE/CT-37, 	CKRE, 	MS6206, 	2.4, 	CT Basin
PHLA2/CT-38, 	PHLA2, 	AEC3153	1, 5.0, 	CT Basin
LEU1/CT-39, 	LEU1, 	AEC3198	1, 8.4, 	CT Basin
LEU1/CT-39, 	LEU1, 	MS6206, 	3.3, 	CT Basin
CKRFE/CT-44, 	CKRFE, 	AEC3198,	 9.2	, CT Basin
CKRFE/CT-44	, CKRFE, 	MS6206	, 1.6 	CT Basin
RHLA2/CT-45, 	RHLA2, 	AEC3153, 	6.9, 	CT Basin
CKRE/CT-50	CKRE	AT206	5.0	CT Basin
HHLA/CT-52, 	HHLA	, AEC3153, 	5.4, 	CT Basin
HULA/CT-53	, HULA, 	AEC3153, 	7.0	, CT Basin
ICN/CT-55	, ICN, 	AEC3107, 	9.3, 	CT Basin
ICN/CT-55, 	ICN	, DN2761	, 6.3, 	CT Basin


Part 2 Table 15-1. BRLA-1 and BRLA-2 use natural gas as stripping medium.

Part 2 Table 15-2. Average benzene concentration (ppmw) counted from sources going to BRLA, so BRLA does not have additional water.

Part 2 Table 16-1. 
The Sulfur Loading Rack capacity loading throughput is in the units of long tons/year.
The Coke Terminal capacity loading throughput is in the units of tons/year.

Part 3 Where there is not a CAS pollutant listed in the database, the event is listed in the table below.

1/4/2010 – Leak was discovered coming out of insulation near a leg support to Control Valve Station L-715 on PS7   [Material Released = 1 gallon Crude] - 2-PROPENAMIDE, 79-06-1, 1.20 lbs, Calculated
PSEUDOCUMENE, 95-63-6, .002 lb, Calculated

1/10/2010 - safety valve lifted when switching drum to blow down - Hydrogen, 1333-74-0, .13, Calculated
Methane, 74-82-8, 7.3, Calculated

2/3/2010 - Corrosion caused the thermo well to fail exposing the thermocouple to line pressure. – ISOPROPANOL, 67-63-0, 3336.116, Calculated

4/14/2010 – PCLA-2 Shutdown – Hydrogen, 1333-74-0, 1.35, Calculated
Carbon Dioxide, 124-38-9, 3.70, Calculated
N2, 7727-37-9, 6.97, Calculated
Methane, 74-82-8, 21.47, Calculated
C4H6 1 3 (Butadiene), 109-99-0, .57, Calculated
C4H8 MXT (Butenes), 25167-67-3, 66.49, Calculated
C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, 103.68, Calculated
C7H14, 68526-53-4, .01, Calculated
NO, 10102-43-9, 46.42, Calculated
Opacity, N/A, N/A, Calculated

5/3/2010 - T-1 Safety Valve lifted during a unit upset - 2-METHYLHEPTANE, 592-27-8, 31, Calculated
2-METHYLPENTANE, 107-83-5, 148, Calculated
DECANE, 124-18-5, 1, Calculated
HYDROGEN, 1333-74-0, 1715, Calculated
METHANE, 74-82-8, 1589, Calculated

5/4/2010 - Flaring due to PCLA2 Shutdown - H2, 1333-74-0, .06, Calculated
N2, 7727-37-9, .06, Calculated
CH4, 74-82-8, .56, Calculated
C4H6 1 3 (Butadiene), 109-99-0, 0, Calculated
C4H8 MXT (Butenes), 25167-67-3, .17, Calculated
C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, .04, Calculated
NO, 10102-43-9, .86, Calculated

5/5/2010 - Flaring due to PCLA instrument malfunction – Hydrogen, 1333-74-0, .68, Calculated Carbon Dioxide, 124-38-9, .97, Calculated
N2, 7727-37-9, 2.11, Calculated
Methane, 74-82-8, 7.17, Calculated
C4H6 1 3 (Butadiene), 109-99-0, .20, Calculated
C4H8 MXT (Butenes), 25167-67-3, 21.89, Calculated
C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, 30.64, Calculated
C7H14, 68526-53-4, .01, Calculated
NO, 10102-43-9, 17.07, Calculated
Opacity, N/A, N/A, Calculated

5/12/2010 – reboiler leak - 1,3-PENTADIENE, 504-60-9, 2.5, Calculated

5/14/2010 - PCLA Fractionator flare valve lifted - Hydrogen, 1333-74-0, .62, Calculated
Carbon Dioxide, 124-38-9, .03, Calculated
N2, 7727-37-9, .67, Calculated
Methane, 74-82-8, 6.06, Calculated
C4H8 MXT (Butenes), 25167-67-3, 1.85, Calculated
C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, .42, Calculated
C7H14, 68526-53-4, .03, Calculated
NO, 10102-43-9, 9.21, Calculated

5/17/2010 - ICN Venting due to tower shutdowns – Hydrogen, 1333-74-0, .06, Calculated
N2, 7727-37-9, .06, Calculated
Methane, 74-82-8, .56, Calculated
C4H8 MXT (Butenes), 25167-67-3, .17, Calculated
C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, .04, Calculated
NO, 10102-43-9, .86, Calculated

5/25/2010 - Leak in over head line after overhead condenser – PSEUDOCUMENE, 95-63-6, .91, Calculated

5/25/2010 - Flaring due to RHLA shutdown – Hydrogen, 1333-74-0, .02, Calculated
N2, 7727-37-9, .02, Calculated
Methane, 74-82-8, .23, Calculated
C4H8 MXT (Butenes), 25167-67-3, .07, Calculated
NO, 10102-43-9, .34, Calculated

6/11/2010 – Flaring due to Poly Shutdown – Hydrogen, 1333-74-0, .08, Calculated
N2, 7727-37-9, .08
Methane, 74-82-8, .73, Calculated
C4H8 MXT (Butenes), 25167-67-3, .22, Calculated
C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, .05, Calculated
C7H14, 68526-53-4, 0, Calculated
NO, 10102-43-9, 1.12, Calculated

6/14/2010 – ICN Shutdown caused MGO tanks to vent – Hydrogen, 1333-74-0, 94.23, Calculated Methane, 74-82-8, 966.89, Calculated

7/28/2010 – Flaring due to exchanger shutdown – Hydrogen, 1333-74-0, .29, Calculated
Carbon Dioxide, 124-38-9, .01, Calculated
N2, 7727-37-9, .31, Calculated
Methane, 74-82-8, 2.82, Calculated
C4H8 MXT (Butenes), 25167-67-3, .86, Calculated
C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, .20, Calculated
C7H14, 68526-53-4, .01, Calculated
NO, 10102-43-9, 2.06, Calculated

8/2/2010 - tower leaked crude oil to concrete and sewer - 2-PROPENAMIDE, 79-06-1, .02, Calculated
PSEUDOCUMENE, 95-63-6, .04, Calculated

8/21/2010 - Flaring due to HCLA D-105 Level Malfunction – Hydrogen, 1333-74-0, .11, Calculated Carbon Dioxide, 124-38-9, .03, Calculated
N2, 7727-37-9, .19, Calculated
Methane, 74-82-8, 1.79, Calculated
C4H8 MXT (Butenes), 25167-67-3, .21, Calculated
NO, 10102-43-9, 9.06, Calculated

8/22/2010 – Flaring due to HCLA Startup Issues – H2, 1333-74-0, .31, Calculated
Carbon Dioxide, 124-38-9, .11, Calculated
N2, 7727-37-9, .78, Calculated
Methane, 74-82-8, 1.81, Calculated
C4H8 MXT (Butenes), 25167-67-3, .87, Calculated
NO, 10102-43-9, 3.20, Calculated

8/24/2010 - Flaring due to Alky Startup & PHLA T-30 Venting – H2, 1333-74-0, .08, Calculated
Carbon Dioxide, 124-38-9, .03, Calculated
N2, 7727-37-9, .19, Calculated
Methane, 74-82-8, .45, Calculated
C4H8 MXT (Butenes), 25167-67-3, .22, Calculated
NO, 10102-43-9, .79, Calculated

8/27/2010 – Hydrogen Leak on compressor flange - Hydrogen, 1333-74-0, 29, Calculated Methane, 74-82-8, 10, Calculated

9/10/2010 – Flaring due to Alky shutdown – Hydrogen, 1333-74-0, .31, Calculated
Carbon Dioxide, 124-38-9, .11, Calculated
N2, 7727-37-9, .78, Calculated
Methane, 74-82-8, 1.80, Calculated
C4H8 MXT (Butenes), 25167-67-3, .87, Calculated
C7H14, 68526-53-4, 0, Calculated
NO, 10102-43-9, 3.18, Calculated

9/21/2010 - Pin hole leak in suction Inter-stage piping- Hydrogen, 1333-74-0, .04, Calculated Carbon Dioxide, 124-38-9, .01, Calculated
N2, 7727-37-9, .09, Calculated
Methane, 74-82-8, .22, Calculated
C4H8 MXT (Butenes), 25167-67-3, .11, Calculated
NO, 10102-43-9, .39, Calculated

9/26/2010 – distillate pump seal leak – Methane, 74-82-8, .42, Calculated
Neopentane, 463-82-1, 18.45, Calculated
Water, 7732-18-5, .04, Calculated

9/28/2010 – Hydrocarbon leak on reactor overhead line – Carbon Dioxide, 124-38-9, .03, Calculated
Methane, 74-82-8, .29, Calculated
Pseudocumene, 95-63-6, .3, Calculated

10/1/2010 – Leak in piping weld – Hydrogen, 1333-74-0, 157.5, Calculated
Methane, 74-82-8, 101.24, Calculated
Nitrogen, 7727-37-9, 1.23, Calculated

10/9/2010 - Flaring due to PSLA Shutdown for turnaround – Hydrogen, 1333-74-0, .03, Calculated
Carbon Dioxide, 124-38-9, .01, Calculated
Methane, 74-82-8, .19, Calculated 
C4H8 MXT (Butenes), 25167-67-3, .09, Calculated
NO, 10102-43-9, .33, Calculated

10/11/2010 – Flaring due to shutting down meter for maintenance – NO, 10102-43-9, .33, Calculated

10/14/2010 – leak from a weld on the top of unit – PSEUDOCUMENE, 95-63-6, 1.1, Calculated

10/28/2010 – Flaring due to BRLA Startup – Hydrogen, 1333-74-0, .44, Calculated
Carbon Dioxide, 124-38-9, .02, Calculated
N2, 7727-37-9, 2.26, Calculated
Methane, 74-82-8, 6.96, Calculated
C4H8 MXT (Butenes), 25167-67-3, .13, Calculated
NO, 10102-43-9, 4.09, Calculated

12/1/2010 – Flaring due from Poly – C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, .03, Calculated NO, 10102-43-9, .93, Calculated

12/15/2010 – Pencil Size Leak in Pulldown Line – Sulfuric Acid, 7664-93-9, 1818, Calculated

12/17/2010 – Hydrogen leak on cylinder flange – Hydrogen, 1333-74-0, 2100, Calculated Methane, 74-82-8, 720, Calculated

12/20/2010 – Flaring due to Alky Depressurization – NO, 10102-43-9, 36.09, Calculated

12/30/2010 – Flaring due to safety leaking – Methane, 74-82-8, .28, Calculated
C4H8 MXT (Butenes), 25167-67-3, Calculated
C5H10 MXT, 109-67-1, 646-04-8, 627-20-3, .09, Calculated
NO, 10102-43-9, .22, Calculated





Part 5 - PDF summary
Test Test or Monitoring Data ID	 -  Unit ID(s)  	     -            Bates IDs
		
R 1.1.02.05.005c	         -             PHLA2	      -       EM-BRRF-00001 to EM-BRRF-00057
R 1.5.03.1.10.002       -       	PCLA2 & PCLA3   -    EM-BRRF-00058 to EM-BRRF-00258
DEQ Project Completion Report	-Perimeter Monitoring Report	-EM-BRRF-00259 to EM-BRRF-00278
Final Project Completion Letter -Perimeter Monitoring Report	-EM-BRRF-00279 to EM-BRRF-00280


notes:
NOTES:

Part II, Section 1 Energy Management 

4.  CRLLC’s energy management system, entitled Global Energy Management System, or GEMS, utilizes international best practices and benchmarking to identify energy efficiencies at our refineries and chemical plants.  The system utilizes a common methodology to identify and close performance gaps, sustain progress, and drive plants toward leading-edge energy performance.  Since 2000, we have used GEMS to systematically identify and address operational efficiency opportunities. We have identified ways to improve energy efficiency at our refineries and chemical plants by 15 to 20 percent and have captured over 60 percent of these opportunities to date.

GEMS is based on a three-step approach to performance improvement:
• Address base case performance opportunities by operating existing facilities optimally and efficiently through application of best practices.
• Identify economic investment opportunities above an optimized base for step-change improvement to address structural differences.
• Implement strong management systems to provide the rigor and discipline necessary to sustain progress and drive continuous improvement.

GEMS is a layered approach to energy management.  It starts with the identification of key energy variables and establishes targets for safe, reliable, energy-efficient operations.  Secondly, diagnostic indicators focus on system health and implementation of improvement plans.  A key measure is “lost opportunity”, which is the economic value of the gap between a key energy variable and its target value.  Monetizing gaps helps prioritize work and focus resources.  And finally, Global Measures summarize bottom line performance for corporate and plant management. 

As part of the energy management process CRLLC conducts GEMS Assessments at sites to deliver best practices and measures.  The Assessment progresses through three stages:
• It takes several months to prepare for a GEMS Assessment.  A key step is selection of a team of technical specialists from across the global organization and plant personnel familiar with local operations and practices.
• Execution of the Assessment can take anywhere from a couple of weeks to a couple months depending on site size and complexity.  During the assessment the team looks at process units, major equipment, and utilities systems to identify gaps.  The team also looks at plant configuration to identify project opportunities such as advanced controls and optimization, heat integration, and waste heat recovery projects.
• The Assessment deliverables include gap-closing options and a cost/benefit analysis for each item identified in the gap assessment.  A multi-year plan is then established that balances the portfolio of operational improvement and facilities enhancements along with other business and investment needs.  CRLLC is in the GEMS program, and the initial energy management Assessment was performed a number of years ago.  Our sites are now in the implementation phase of this process.


notes:
Author:  Dave Elder – ddelder@marathonpetroleum.com

Part I - Facility Information
10.  The Dun & Bradstreet number shown is for the Louisiana Refining Division/Garyville Refinery and not Marathon Petroleum Company as a whole.
11.  Annual revenue in 2010 of $72,321,000,000 is noted for the Marathon Oil Corporation as a whole while the Refining, Marketing & Transportation segment is $62,487,000,000 and is a portion of that whole.  
12.  The number of employees noted is only those employees at the Louisiana Refining Division who are Marathon Petroleum Company LP employees as of April 30, 2011.  On-site contractors and day contractors are not included in this number.
13.  On June 30, 2011, Marathon Oil Corporation and Marathon Petroleum Company LP will split forming two separate entities.
15.  Production values for 2010 as listed in the table differ slightly from shipping numbers due to storage and transportation logistics.  Shipping percentages listed were determined based on actual shipping amounts per transport method for 2010.
16. Unit throughput capacities in Table 16 for major processing units at the Louisiana Refining Division (LRD) are based on the calendar day throughput capacities as of December 31, 2010.  Current stream day capacities and permitted capacities are in some cases higher than the capacities listed.  
For some listed units there is no unit throughput capacity as this term does not apply to the particular unit listed.  These are typically non-production units and many of the components of these units are covered in other sections of this ICR.  For units without a listed unit throughput capacity, a “-99” has been inserted into the column for that unit.
Additionally, a “-99” has been inserted into this column for some units listed which are closely associated with other units yet don’t have their own individual unit throughput capacity.  These units are listed below:
Master Unit:  Unit 010 (#1 Crude Unit)   Associated Units:  U10 Desalter Flash Column; Unit 022 (Sats Gas Plant)
Master Unit:  Unit 019 (Amine/Sour Water Stripper)   Associated Unit:  Sour Water Stripper (19-1105)
Master Unit:  Unit 020 (#1 SRU)     Associated Unit:  Unit 021 (Tailgas Unit)
Master Unit:  Unit 025 (FCCU)      Associated Units:  Unit 016 (FCCU Gasoline Merox Unit); Unit 017 (FCCU Unsaturated LPG Merox); Unit 026 (FCCU Gas Con Unit); Unit 030 (FCCU Wet Gas Scrubber)
Master Unit:  Unit 033 (Sour Water Stripper)   Associated Unit:  Sour Water Stripper (33-1103)
Master Unit:  Unit 048 (Sour Water Stripper)   Associated Unit:  Sour Water Stripper (48-1101)
Master Unit: Unit 050 (Marine Docks #1 & #2)    Associated Units: Unit 50 Coke (Marine Dock #4); Unit 50 Controlled (all Marine Docks), Unit 50 Uncontrolled (all Marine Docks), Unit 071 (Barge Dock #3)
Note the entire marine loading capacity is listed as being associated with Unit 050.
Master Unit: Unit 060 (Wastewater Treatment Plant)   Associated Units (components of the Wastewater Treatment Plant): AIS #1 (60-2207), AIS #2 (60-2241), API #1 (60-2213), API #2 ((60-2239-01/02), Digester #1 (60-2211), Digester #2 (60-2240), East Bio (60-2218), East Clarifier (60-2219), East DAF (60-2216), IGF #1 (60-2233), IGF #2 (60-2242), Middle Bio (60-2205), Middle Clarifier (60-2209), Tank 100-2 (60-1932), Veolia CPI (60-2226), West Bio (60-2206), West Clarifier (60-2210), West DAF (60-2205) 
Master Unit: Unit 065 (Refinery Truck Rack)   Associated Units: Unit 065 – Propane; Unit 065 - Sulfur
Master Unit:  Unit 210 (#2 Crude Unit)     Associated Units:  U210 Benzene Stripper (210-1110); Unit 222 (Sats Gas Plant)
Master Units:  Unit 220 & Unit 234 (#4 & #5 SRUs)    Associated Unit:  Unit 221 (Tailgas Regeneration Unit)
Master Unit:  Unit 233 (Sour Water Stripper)   Associated Unit:  Sour Water Stripper (233-1103)
Part II – Section 1 – Energy Management
3.  The hydrogen amount purchased includes hydrogen utilized, but not combusted, in Hydrotreater units.
4.  MPC’s Energy Management Plan:  Marathon constantly evaluates a wide range of projects and programs to maintain and improve energy efficiency.  Economically attractive projects are incorporated into the strategic and business planning process at all locations including the Garyville Refinery.  In addition to having a corporate Energy Technologist, the Garyville Refinery has a dedicated Energy Engineer at the refinery.  MPC tracks energy efficiency through our Marathon Energy index.  A new initiative was rolled out in 2010 – the “Focus on Energy” program.  This program identified specific and actionable energy impacting metrics which will be tracked daily by operations and management.  This initiative is expected to identify additional medium and long-term improvements available for implementation which would save even more energy.  
5. Table 1-2 does not include steam economizers or steam coils included as part of process heaters.  Those devices are noted in Table 2-1 (Process Heaters) as an “other energy efficiency measure”.  Pumparound waste heat boilers were also not included as their energy came from another source – a heater for example.
6.  Table 1-3 includes steam usage data for those process units which are significant steam users for LRD.  Except for the sour water stripping units listed in the WWTP section of the ICR, all other unit consumptions are shown as “ND” as no good data exists for these units which typically have either zero or relatively small steam consumptions rates.
Part II – Section 2 – Process Heaters
No notes.
Part II – Section 3 – Equipment Leaks
3.  For Table 3-1 - Unit 060 (Wastewater) and all its sub-units are listed in this section; however, LDAR data is not provided as stated in the directions.  
3.  For Table 3-1, “Total Valves” includes difficult to monitor valves as well as unsafe to monitor valves.
3.  Gas and light liquid flange & connectors counts for Chapter 51 units include only those components greater than or equal to 1”.  For all other flange & connector counts, including heavy liquids, the count is an estimate (2.5 times the valve count).


Part II – Section 4 – Storage Tanks
4.  Storage tanks in asphalt, heavy oil, diesel, and kerosene service were not included in Table 4-1 as these products do not have a maximum true vapor pressure greater than 0.1 psi at LRD.
Part II – Section 5 – Catalytic Cracking Units
Table 5.2 Unit 215 is a Hydrocracker Unit and not a Catalytic Cracking Unit; therefore data for that unit has not been included in this submittal.
Table 5.2 – Metals concentrations are for spent FCCU catalyst and are an average of 2010 data.
Part II – Section 6 – Fluid Coking Units
LRD does not have any Fluid Coking Units.
Part II – Section 7 – Delayed Coking Units
2.  Information presented in Table 7-1 is based on operation of the Coker Units at the end of 2010.  In Table 7-1, the “Height of a single coke” drum is based on the height from tangent to tangent and the “Typical water ht in coke drum when first vented to atmosphere” is based on the height from the bottom tangent of each coke drum.  “Typical quench water flow rate during Quenching cycle” ramps from 150 gpm to 1600 gpm for the Unit 005 Coker Unit drums and from 150 gpm to 2250 gpm for the Unit 205 Coker Unit drums.  Maximum quench water rates are shown in Table 7-1.  
Part II – Section 8 – Catalytic Reforming Units
2.  For Table 8-1, both the “Coke burn-off cycle vent” and the “Rejuvenation cycle vent” are controlled with the same control device – a caustic scrubber skid which scrubs the chlorides in a two method approach.  First a venture scrubber removes 70% of the chlorides then the packed tower removes the remaining chlorides down to <10 ppm.  This is true for both CCRs at LRD.  
Part II – Section 9 – Sulfur Recovery Units
2.  For Table 8-1, “primary sulfur pit maintenance” hours are based the number of hours that maintenance was performed on the sulfur pit eductors and thus not being controlled.  
Part II – Section 10 – Hydrogen Plant
LRD does not own and operate a Hydrogen Plant.  There is an adjacent co-located Hydrogen Plant owned and operated by Air Products.
Part II – Section 11 – Other Atmospheric Vents
No notes for the section.
Part II – Section 12 – Flares
2.  In Table 12-1, the “equivalent diameter” of 59-1402 Marine Vapor Combustor is based on the equivalent open area of the rectangular top opening for this enclosed ground flare combustion device.
2. In Table 12-1, the “equivalent diameter” of 259-1401 & 259-1402, the two open ground flares, is based on the total of the open area of the burners in the first four rows (steam-assisted) of each ground flare.  The open area of the additional pressure-assisted rows is considered proprietary information and is not available to LRD.  Also note the burner open area of a ground flare (the rows) open only as needed with increasing pressure (as designed).  These ground flares do have a 40’ radiation fence around both of them.
Part II – Section 13 – Fuel Gas Treatment
Treated fuel gas from the various fuel gas treatment units listed along with occasional supplemental natural gas are co-mingled in two fuel gas mixing drums prior to being utilized in refinery fuel combustion devices such as heaters.
Part II – Section 14 – Heat Exchanger (Cooling Water ) Systems
No notes for this section.
Part II – Section 15 – Wastewater Collection and Treatment
2a)  No units were stated; response was given in “bbls/day”.  

Part II – Section 16 – Loading Operations
4. In Table 16-1, Loading Information, “Typical annual operating hours” is the hours during the year that the rack is open, available, and utilized.  
4.  Refinery Sulfur Truck Loading Rack – the “capacity loading throughput” is based on the permitted sulfur make at the refinery.  
4.  Refinery Marine Loading Dock – light products are loaded into ships and barges with the expelled vapors controlled in a vapor combustor.  Heavy products (distillates and heavier) are not controlled.  The “capacity loading throughput” for the marine loading docks is based on the permitted marine loading throughputs.
4.  Refinery Propane Truck Loading Rack – propane is typically not loaded at the refinery except under highly unusual circumstances (pipeline shutdown).  The propane truck rack capacity was based on the maximum loading capability of 40 trucks per day at 200 bbls (8400 gals) per truck.  The flare is only used when bleeding off the propane left in the loading hose.  
4.  Refinery Asphalt Railcar Loading Rack – asphalt is typically not railcar loaded at the refinery.  If asphalt railcars are loaded, they are loaded during daylight hours (12 hours/day), four days a week.  This results in 2496 hours of loading per year.  The loading capacity was based on loading 7 cars per day, 4 days a week, at 500 bbls/railcar.  
4.  Unit 300 – Gas/Dist – This is the Garyville Terminal Light Product Truck Rack – the “capacity loading throughput” of the terminal is based on the permitted terminal throughput on a 12-month rolling average.  Please note the Garyville Terminal is not under direct control of the Garyville Refinery but is located adjacent to the refinery. 
4.  Unit 400 – Asphalt – This is the Garyville Asphalt Terminal Truck Rack – the “capacity loading throughput” of the terminal is based on the permitted terminal throughput on a 12-month rolling average.  Please note the Garyville Terminal is not under direct control of the Garyville Refinery but is located adjacent to the refinery.  

Non-routine Emissions
Unit shutdown emission times are estimates and include the time it takes to de-pressure the unit as well as steaming out the vessels to the flare.


energy_management_plan_description:
The Convent energy management plan is developed to identify, measure, monitor and optimize energy generated and consumed at Convent and enhance the ability of the 24/7 Production Group to optimize large energy-consuming equipment on a daily basis.


energy_management_plan_description:
Annual and long range energy performance goals.  5-yr plan includes capital projects and initiatives to improve performance.  Targets for energy related process parameters are established, reviewed and reported.  Maintnenance programs to conserve energy.

notes:
Sulfur plant production heavily influenced by crude unit operations in 2010.  Historically Norco would run [CBI] when economics favor high sulfur feed stock.  

Note that benzene TAB for 2010 includes wastes from an unanticipated spill.  The TAB was below 6 Mg excluding this event.


energy_management_plan_description:
Crude preheat train modifications have resulted in significant reduction in heater fuel gas usage.

notes:
All Parts and Sections – We have used the following codes throughout the database to represent information that is not applicable or unknown:
•	“-88” Not applicable
•“-99” = Unknown
Regulatory applicability is as of the current Title V operating permit issued to the refinery.
Part I, Process Units – Unit throughput capacities are unknown for some process units.  Steam consumption represented for HC includes steam consumption for HT.  Steam consumption at the boilers process unit (B) is at the boiler deaerator.  Reformer “PR” represents the regeneration section of reformer “P”.

Part II, Section 15: Wastewater Collection & Treatment - No total HAP sampling data exists.  To estimate HAP concentration, Table 7-8 of EPA's Emissions Estimating Protocol was used.  No VOC sampling data exists and only benzene data exists as associated with the facility TAB.  To estimate VOC concentration, a multiplier of 81 times the benzene concentration is used, as referenced in Table 7-9 of EPA's Emissions Estimating Protocol. Benzene is sampled only at the inlet to the wastewater treatment plant, which represents the combined effluent from all referenced process units.  Table 7-8 of EPA’s Emissions Estimating Protocol was used to estimate benzene concentration of each wastewater stream.
Plant includes multiples of several units (2 sour water strippers, 3 equalization basins/tanks, 2 DAF, 2 activated sludge biological treatment units, 2 primary clarifiers).  Database shows only one of these items because duplicate entries cannot be created.
Part III: Non-Routine Emissions - Emissions listed for this exercise are excess emissions.  Pollutants during an event that do not exceed reporting thresholds are not included.


legal_owner_name:
Valero Refining, New Orleans, L.L.C., a Delaware limited liability company


energy_management_plan_description:
The unit has been shutdown for several years.  However, we have energy management displays to monitor energy consumption per barrel of crude.  We also monitored the performance of heat exchangers to understand which ones require cleaning.


energy_management_plan_description:
Heat Exchanger cleaning, steam trap repair/surveys, steam leak repairs, fired heater and boiler O2 management, excess steam venter, and compressor recycle reduction are all monitored in the energy management plan. In addition, energy performance checklist

notes:
Part I, Question 11: Represents ConocoPhillips US R&M Revenue; Part I, Question 13b: Although this question is somewhat incomprehensible to ConocoPhillips in that the "facility" does not have a Board of Directors and for other reasons, we believe that this statement "best" applies of the three statements offered.; Part I, Question 16: The Unit Throughput Capacity and Unit Actual Thorughput provided for Unit 7991 is the liquid feed in bbl/cd.  The gaseous Unit throughput Capacity is 11 MMscf/day and the gaseous Unit Actual Throughput is [CBI].  The Unit Throughput Capacity and Unit Actual Thorughput provided for Unit 301 is in MMBtu/hr and the Unit Throughput Capacity and unit Actual Throughput provided for Unit 308F is in MMscf/day; Part II, Section 1, Question 4 - ran out of character space:  should state "In addition, energy performance checklists are used for projects"; Part II, Section 1, Question 5: Percent Steam to Blowdown is not applicable; Part II, Section 1, Question 6: This table represents steam demand by unit for calendar year 2010; Part II, Section 2, Question 1: Operating hours while operating less than 25% of rated capacity in 2010 and Operating hours while operating less than 50% of rated capacity in 2010 is not available for 100-H-1 because this heater does not have a flow meter; Part II, Section 3, Question 2: LA3C0690 also uses the thermal imaging device to find leaks following non-routine operations; Part II, Section 3, Question 3: Monitored Open Ended Lines is a double count of the monitored valves listed in this table and in Table 3-2.  Potential Open Ended Lines are monitored as part of the associated valve; Part II, Section 5, Question 2:  Arsenic, Beryllium, Cadmium, Chromium, Cobalt, Manganese, Mercury and Selenium concentrations are not available for E-cat and Arsenic, Beryllium, Cadmium, Chromium, Cobalt, Lead, Manganese, Mercury and Selenium concentrations are not available for fines; Part II, Section 7, Question 2: Height of Single Coke Drum (ft) is from tangent to tangent and Typical Water Height in Coke Drum when first vented to Atmosphere (ft) is from Top Tangent to Bottom Tangent; Part II, Section 9, Question 2: Units 591 and 592 use a single SCOT unit.


plant_name:
Calumet Lubricants Company Cotton Valley Refinery

notes:
Tank Farm is not a processing unit, but included to be able to add fugitives.  Section 4. Storage Tank, past tank cleaning reports unavailable. Section 4.  no tank cleanings are scheduled.  Section 12. Flare target assist ratio is unavailable.  Section 14.  Another additiive.  ST-70 (bromide based oxidizing biocide), 0.4 gal/day, cold water basin.


plant_name:
Calumet Lubricants Company Princeton Refinery

notes:
On Process Units, Asphalt Oxidation production is in tons/year;  On Process Uniits, Tank Farm included to be able to add fugitive components.  Section 11.  Ejector Vents are in the process of being routed to a flare.  Section 12, Crude Flare, target assist ratio is unavailable.  Section 15 Sumps are in the process of having covers installed.


legal_owner_name:
Calumet Shreveport Lubricants and Waxes, LLC

notes:
Flow Rates of the Reformer Deaerator vents in the Hydrogen Plants are not known/not measured since this vent expels only steam.  "Tanks" have been added as a process unit (even though not meeting the "process unit" definition) in order to not exclude steam consumption, wastewater generation, and equipment leaks data for the tanks at the refinery.  No equipment leak counts are given for Unit ID "87" (Fuel Blending) since this would be a double-count from the "Tanks" equipment leak counts.


notes:
11 H 1 is only operated on start-up of the FCCU.


plant_name:
Flint Hills Resources Pine Bend LLC Pine Bend Refinery

energy_management_plan_description:
Publish a quarterly Energy Scorecard with a specific list of included metrics. 
Complete a defined Energy Performance Analysis.
Develop a method to include energy efficiency considerations in TA planning process. 
More detail available upon request.

notes:
Refer to the cover letter, "RE: Flint Hills Resources Pine Bend, LLC Pine Bend Refinery - Component 1 Information Collection Request (ICR) Response", dated May 31, 2011, that accompanied the database response.  The document attached to the letter is intended to supplement FHR’s answers to Component 1 of the ICR (the “Supplement”).  In the Supplement, FHR provides an explanation of how specific Parts/Sections/Question numbers (“Question Numbers”) were answered by FHR for the ICR.  The explanations may include a discussion of FHR’s specific process and its understanding or interpretation of the question followed by an in depth discussion of the data or information used in FHR’s response to that question.  FHR intends that its electronic responses to Component 1 of the ICR and any accompanying certification of that information be read in conjunction with any information contained in the Supplement.


energy_management_plan_description:
SPPRC is constantly evaluating a wide range of projects and programs to maintain and improve energy performance.  Economically attractive projects are incorporated into the strategic and business planning process.

notes:
Supplemental Information Overview
On March 31st 2011, St. Paul Park Refining CO. LLC (SPPRC) received a letter from the United States Environmental Protection Agency (USEPA) requesting a vast array of information( Refinery ICR). USEPA stated as the basis for this information request, that under Clean Air Act sections 111 and 112, USEPA must review and revise as necessary promulgated emissions standards every 8 years. USEPA has requested data for four different components of the overall Refinery ICR. As USEPA did not address many questions to clarify specifically what they were looking for in many areas, SPPRC has answered all questions to the best of our ability. This supplemental information document is to help clarify responses to the Component 1 survey where clarification was not directly addressed.
Each section of the Component 1 Survey of the Refinery ICR is represented in this document. If there is a question for a given section that SPPRC feels further clarification is needed, the question number will be given and followed by any additional comments or clarification.
Part I – General Facility Information
The following clarifications relate to information provided for Question 16: 

Unit ID 1V:  Unit 1 is equipped with crude atmospheric distillation and a dedicated vacuum distillation unit.  To indicate these capabilities, the #1 Crude Unit vacuum section is identified as Unit 1V.

Unit 11a and 11b:  The fuel gas (unit 11a) and natural gas (unit 11b) systems are reported as separate units to facilitate reporting in Part II, Section 3: Equipment Leaks.

Unit IDs 15 and 16:  The cooling water system (unit 15) and steam system (unit 16) are reported as separate process units to facilitate reporting in Part II, Sections 14 and 15, respectively.  These systems do not contain components that are subject to the equipment leak regulations.

In addition, Units Cat, Alky, #1 Ref, #2 Ref, Crude, and #3 SRU indicate cooling water systems reported in Section 14.    

Unit Throughput Capacity: Units that have a designated -99 throughput capacity do not have a maximum capacity that is easily identified and readily available. The amount of throughput to these units has a number of variables that affect the throughputs, namely throughput in actual process units and other operating conditions.

Unit IDs – LDAR Units: The following units have been added to question 16 to make it possible to provide information in following sections of the ICR:

Unit ID 2b (#2 Crude New Tail Gas Compressor) – Included only to provide information pertaining to SPPRCs LDAR program can be provided in the equipment leaks section. This unit is part of the #2 Crude Unit ID 2, however Unit ID 2b is split out as it is a separate facility under equipment leak regulations.

Unit IDs 7A, 7B, 7C, 7E, 7F, 7G, 7H, 7J – Included only to provide information pertaining to Part II Section III, Equipment Leaks. These are all part of overall refinery Unit ID 7 Blending and Transfer; however Unit ID 7 is split out into different areas for compliance with equipment leak regulations (LDAR Programs).  

Unit IDs – Catalytic Reformers:  The feed desulfurization for SPPRC’s two catalytic hydrotreaters (Units 3 and 36) are integral to those units.  For the purpose of the ICR, the desulfurization sections of those units have been designated as 3a and 36a, respectively, to indicate that the reformer units do include desulfurization capability.

Question 16 Unit IDs – Isomerization:  SPPRC’s isomerization unit includes a C5/C6 isomerization and a post-processing unit for separation of n-butane from isobutane.  These units are designated as 35a and 35b, respectively.  

Question 16 Unit IDs – Heavy oil storage tanks:  For the purposes of Section 2, Process heaters, heavy oil storage tanks with internal heaters have been designated as Unit 999.  

Question 16 Unit IDs – Wastewater Treatment Systems: The following units have been added to question 16 to make it possible to provide information requested in Section 15: OWS, DGF, SBC, Lagoon 3, Lagoon 4, 158, and 159.  These are the individual components in the wastewater treatment process and are included only to provide the information related to SPPRC’s Wastewater Treatment System (Unit 14b).

Question 16 Unit IDs – Product Loading:  The following units have been added to Question 16 to make it possible to provide information requested in Section 16:  Light Oil, Heavy Oil 1, Sulfur 1, LPG 1, Heavy Oil 2, Sulfur 2, LPG 2, and Barge. 

Part II Section I – Energy Management
Question 4: This site has a full time energy coordinator that monitors energy usage and drives energy reduction/optimization projects and policies.  Key energy reductions that have resulted from the implementation of the plan are improved heater thermal efficiency, reduced fuel oil consumption, and improved heat recovery in multiple process units. SPPRC is constantly evaluating a wide range of projects and programs to maintain and improve energy performance. Economically attractive projects are incorporated into the strategic and business planning process.

Question 6:  For the purposes of steam consumption, Unit 7 encompasses the steam consumption in Units 7A, 7B, 7C, 7E, 7F, 7G, 7H, and 7J.  Steam consumption of the individual components in Unit 7 is not measured and the reported value is an estimate.

Part II Section II – Process Heaters
Unit 999, Heavy Oil Storage Tanks:  Natural gas flows to these heaters are not measured individually, rather through a central flow meter.  Fuel flow to individual heaters is controlled by localized flow control valves (“fireman valves”) based on the tank temperature set point. Therefore, it is not possible to determine the 2010 average heat input and respective number of hours that these heaters were operated at the various percentages of rated capacity.

Part II Section III – Equipment Leaks
Table 3-1
Federal and State Regulations: Unit IDs 7H, 11, 16, and 30 are all subject to state LDAR requirements as listed in SPPRCs Title V Permit. Also, these Unit IDs are subject to the recordkeeping and reporting requirements of 40 CFR 60 Subpart GGG. SPPRC has listed 40 CFR 60 Subpart GGG under the federal regulations section, however as stated previously, the units are only subject to the recordkeeping and reporting requirements of the regulation.

Flanges and Connectors:  SPPRC’s; LDAR program does not include flanges and connectors and an exact count is not available.  The counts were calculated assuming two flanges per pump and two flanges per valve in each of the respective services.

Open-ended lines:  The numbers reported in this section indicate the caps or plugs associated with regulated components and do not indicate open-ended lines.  Caps and plugs are included in SPPRC’s LDAR monitoring program and the number of missing caps or plugs identified during LDAR monitoring events are reported in each regulatory report. 

Compressor Seals, Gas and Liquid Sampling Connections:  The numbers reported in this section indicate the number of compressors and gas/liquid sampling stations, all of which are included in the LDAR monitoring program.

Other:  This section includes relief valves that discharge elsewhere in the process unit instead of relieving to the flare or fuel gas system.  These components are also included in the LDAR program.  

Table 3-2, Fuel Gas and Natural Gas Systems:  Natural gas components are not included in the LDAR monitoring program.  Component counts are estimated from a review of Process and Instrumentation Diagrams.

Table 3-3, Pressure Relief Devices:  The PRDs reported in this section are those which vent to the flare or to other equipment which vents directly to the flare.  
Part II Section IV – Storage Tanks
Table 4-1:
SPPRC has chosen to include propane, butane, and propylene bullets and spheres into the storage tanks section Table 4-1. It is widely known that these are pressurized vessels that do not release emissions into the surrounding ambient air. It is the piping, valves and connectors that create the emissions from the process of moving material into and out of these storage vessels. Throughputs for the propane, butane, and propylene vessels are not directly measured, only vessel levels are known.

Part II Section V – Catalytic Cracking Units

Table 5-2, E-cat and CCU Funes Metal Concentration:  SPPRC only measured metals concentrations for nickel and vanadium for e-cat during 2010. Other metals concentration data are not available.

Part II Section VI – Fluid Coking Units
SPPRC does not own or operate a fluid coking unit.

Part II Section VII – Delayed Coking Units
SPPRC does not own or operate a delayed coking unit.

Part II Section VIII – Catalytic Reforming Units
The reported hydrogen production rates are estimated.  The units operate at varying conditions that affect hydrogen production rates and hydrogen production is not specifically measured. 

Part II Section IX – Sulfur Recovery Units
There is no supplemental information for this section.

Part II Section X – Hydrogen Plant Vent
There is no supplemental information for this section.

Part II Section XI – Other Atmospheric Vents
There is no supplemental information for this section.

Part II Section XII – Flares
There is no supplemental information for this section.

Part II Section XIII – Fuel Gas Treatment Systems
There is no supplemental information for this section.

Part II Section XIV – Heat Exchange Systems
There is no supplemental information for this section.

Part II Section XV – Wastewater Collection and Treatment
There is no supplemental information for this section.

Part II Section XVI – Product Loading Operations
Table 16-1 Capacity loading throughput (gal/yr): Capacity loading throughput is based on double the actual 2010 loading throughput for each loading method displayed in the table. With the exception of the light oil loading rack, SPPRC does not have a specified loading capacity value as the amounts of each product loaded.  SPPRC’s Title V Permit establishes an annual gasoline loading limit of 900,000,000 gallons. Other product loading rates depend upon, and are limited by, the process unit throughput and product demand for each product loaded out. Capacity is not limited by loading equipment; it is limited by production capabilities.
For gasoline and diesel fuel loading, a portion of the trucks loaded are owned by SPPRC, but the majority of the trucks loaded are not owned by SPPRC.  
Part III – Non-Routine Emissions
Opacity exceedences were not included in the non-routine emissions table. SPPRC does not have a method to correlate opacity emissions to a mass basis as requested by the ICR.
Part IV – Cost Data (Optional)
SPPRC is not submitting this optional data due to time constraints and data not being readily available.
Part V – Emissions Monitoring and Source Test Data
SPPRC considers all emissions monitoring and source test data to be Confidential Business Information (CBI).


energy_management_plan_description:
1-track efficiencies 2-analyze systems 3-monitor targets 4-apply to new projects 5-flare minimization; daily monitoring resulted in better furnace optimization and reductions in purchased nitrogen.

notes:
(1)	  Part I:  Process units that did not use bbl/d for unit throughput capacity and unit actual throughput are as follows:  23 [MMscf/d], 27-2 and 27-3 [LTD], 27-A [MMscf/d], 27B [MMgal/d], 32 [MMgal/d], 36 [MMgal/d], 38 [MMscf/d], 42 [MMgal/d], 59 [MMscf/d], 94 [MMgal/day], 95 [MMgal/day].
(2)	  Part I:  Unit throughput capacity for process unit 38 was based on a worst case scenario with specific molecular weights of flaring flows.  Data is not readily available for typical flaring capacity.  Because the facility does not flare continuously, the unit actual throughput is the total annual throughput divided by 365 days.  All of this data is CBI.
(3)  	Part I:  Capacity and throughput of process unit 61 for 2010 is not reflective of typical operating year due to scheduled turnaround performed in 2010.  
(4)  	Part II, Section 5:  Process units 12 and 62 are catalytic hydrocrackers and the questions in this section do not apply.  The only catalytic cracker is process unit 16.
(5)	  Part II, Section 7:  Average quench water make-up rate is on a per drum basis.
(6)	  Part II, Section 8:  Coke burn off cycle duration per cycle is listed in hours.  This field does not apply to continuous catalytic reforming process units (79).  
(7)	  Part II, Section 9:  Additional back-up control/reduction measures include divert to other SRU, other (caustic scrubber), other (flare gas recovery), and dedicated SRU flare.
(8)  	Part II, Section 12:  The facility has some available data on typical Higher Heat Value of waste gas; however data for typical Lower Heat Value of waste gas cannot be reported because analytical constituents of waste gas were not readily available.
(9)	  Part II, Section 14:  MVR Cooling Tower 4512A/B, MVR Cooling Tower 4532 and Admin Cooling Tower do not service process streams and therefore questions concerning cooling water system operation-fluid pressure and cooling water system VOC/HAP concentrations do not apply.


notes:
The capacity loading throughput is based on loading and unloading.


mailing_address:
P. O. Box Drawer A, Sandersville, MS 39477

notes:
Section 2-1: The value reported as 'Still Gas' is recorded as "FUEL GAS" in the facility emissions inventory internal documents
Section 2-16: The value recorded for 'Typical annual operating hours' represents the hours available for use


energy_management_plan_description:
(1) Refinery Fuel Gas Management to reduce/eliminate flaring of excess RFG. (2) Energy Intensity Index is calculated Daily. (3) Balance steam drivers vs. electric drivers. (4) Clean fin fans annually to maintain cooling in summer.


notes:
ConocoPhillips Billings ICR Component 1 Notes Section
Part 1 Facility Information:  Question 11 - Annual Revenue is from the US Refining and Marketing Revenue.
Part 1 Facility Information: Question 16 – Note the following units for the following process types listed in Question 16
•	For crude distillation through desulfurization units (process type codes 1 through 21), “throughput” is determined in terms of charged liquid material (excluding hydrogen gas inputs).
•	For catalytic cracking units, include both fresh and recycle feed.					
•	For alkylation through oxygenate plants, coke calcining, and chemical production (process type codes 22 through 36 and codes 39 through 45), “throughput” is determined in terms of primary product produced (e.g., quantity of alkylate produced in alkylation unit).				
•	For aromatics production, report the total quantity of all aromatics produced from various separation processes after catalytic reforming.					
•	For hydrogen plants, throughput units are million standard cubic feet per calendar day (MMcf/cd); use 32°F (0°C) and 1	atmosphere as “standard conditions” for H2 plants.		
•	For sulfur recovery, throughput units are long tons per calendar day (LT/cd). 1 LT = 1.12 short tons. Enter individual SRU trains in this table; you will be asked to identify the sulfur recovery plant for each train in Part II, Section 9.					
•	For fuel gas treatment, “throughput” is the quantity of fuel gas input to the unit. Throughput units are million standard cubic feet per calendar day (MMcf/cd); use 60°F (15.56°C) and 1 atmosphere as “standard conditions” for fuel gas treatment.					
•	For fuel blending, “throughput” is the quantity of blended product produced.			
•	For loading operations, “throughput” is the quantity of material loaded.				
•	For wastewater collection and treatment systems (WWTS), throughput units are million gallons per day (MMgal/day). If	desired, you may report wastewater treatment units used to comply with Benzene Waste Operations NESHAP (40 CFR part 61, subpart FF) “BWON” or sour water treatment units as separate WWTS, but you are not required to do so.		
Part 2 Section 1 Energy Management: Energy Management Plan - The Refinery has a robust plan that includes on-going monthly tracking of site-wide energy efficiency, an energy performance checklist used for projects, fired heater oxygen management, steam trap repair program, steam leak repair program, heat exchanger cleaning, waste heat steam generation, systems to recover excess gases (flare gas recovery), and compressed air leak repair.  The Refinery also has a long term program to identify energy efficiency opportunities and implement those projects in the coming years.                                                                                                                      Part 2 Section 3 Equipment Leaks: "Other" Components refers to Pressure Relief Devices
Part 2 Section 4 Storage Tanks: Tanks S56, S76, S84, and S85 are spherical tanks and their heights are N/A.
Part 2 Section 14 Heat Exchange Systems: All Heat Exchange Systems have variable Gas or Chemical Addition Rate Values
Part 2 Section 15 Wastewater Systems: If there are any issues viewing Wastewater Vent Federal Regulations see Excel Spreadsheet Hard Copy 
Part 3 Section 1 Non-Routine Emissions: Opacity was measured on the 3/29/2010 release that lasted 2.7 hours                                                                                                         
Part 5 Source Test Data: BoilerRATARpt2010 and BoilerPMTestRpt2008 Test ID Note – Unit ID: 37 (Combined Boiler Stack)
Part 5 Source Test Data: RATARpt2010-3 – Unit ID: 37 (Boiler 5)
Part 5 Source Test Data: RATARpt2010-4 – Unit ID: 37 (Boiler 6)
Part 5 Source Test Data: 114ICRB5_2010 – Unit ID: 37 (Boiler 5)
Part 5 Source Test Data: 114ICRB6_2010– Unit ID: 37 (Boiler 6)
Part 5 Source Test Data: 114ICRBHSO2_2010- Unit ID: 37(Combined Boiler Stack)


notes:
Part 1, Question 16: BIRF Terminal Unit includes Diesel and Mogas
Part 1, Question 16: BIRF RFG Unit, Fuel Gas Treatment at offsite Sulfur Recovery Facility.  This unit is only for backup.
Part 1, Question 16: BIRF OMS Truck Loading, Includes Diesel, Asphalt and LPG from Refinery Truck Rack and Mogas Kerosene and Diesel from the Terminal Rack
Part 1, Question 16: BIRF OMS Rail Loading: Includes Asphalt, LPG, C4, MCO/CBO and Diesel
Part 1, Question 16: BIRF WWTS: From NPDES Reports

Part 2, Section 1 Energy Management Plan:

ExxonMobil’s energy management system for Downstream and Chemical operations, entitled Global Energy Management System, or GEMS, utilizes international best practices and benchmarking to identify energy efficiencies at our refineries and chemical plants.  The system utilizes a common methodology to identify and close performance gaps, sustain progress, and drive plants toward leading-edge energy performance.  Since 2000, we have used GEMS to systematically identify and address operational efficiency opportunities. We have identified ways to improve energy efficiency at our refineries and chemical plants by 15 to 20 percent and have captured over 60 percent of these opportunities to date.
GEMS is based on a three-step approach to performance improvement:
1.  Address base case performance opportunities by operating existing facilities optimally and efficiently through application of best practices.
2.  Identify economic investment opportunities above an optimized base for step-change improvement to address structural differences.
3.  Implement strong management systems to provide the rigor and discipline necessary to sustain progress and drive continuous improvement.
GEMS is a layered approach to energy management.  It starts with the identification of key energy variables and establishes targets for safe, reliable, energy-efficient operations.  Secondly, diagnostic indicators focus on system health and implementation of improvement plans.  A key measure is “lost opportunity”, which is the economic value of the gap between a key energy variable and its target value.  Monetizing gaps helps prioritize work and focus resources.  And finally, Global Measures summarize bottom line performance for corporate and plant management.
As part of the energy management process ExxonMobil conducts GEMS Assessments at sites to deliver best practices and measures.  The Assessment progresses through three stages:
1.  It takes several months to prepare for a GEMS Assessment.  A key step is selection of a team of technical specialists from across the global organization and plant personnel familiar with local operations and practices.
2.  Execution of the Assessment can take anywhere from a couple of weeks to a couple months depending on site size and complexity.  During the assessment the team looks at process units, major equipment, and utilities systems to identify gaps.  The team also looks at plant configuration to identify project opportunities such as advanced controls and optimization, heat integration, and waste heat recovery projects.
3.  The Assessment deliverables include gap-closing options and a cost/benefit analysis for each item identified in the gap assessment.  A multi-year plan is then established that balances the portfolio of operational improvement and facilities enhancements along with other business and investment needs.  All ExxonMobil refineries in the U.S. are in the GEMS program, and the initial energy management Assessments were performed a number of years ago.  Our sites are now in the implementation phase of this process.  

Part 2, Section 3 Table 3-2: See Unit HF 2 for BIRF HF 3 component counts
Part 2, Section 3 Table 3-3: Total number of PRD’s for BIRF HRUB are included in Unit ID HYBL
Part 2, Section 4: Tanks 22, 23, 24 have a max True Vapor Pressure which is based on 2009 API samples and is approximated.  The Temperature to calculate the Max TVP for these tanks was approximately NWS high monthly average temperature for 2010.
Part 2, Section 12: Flare location coordinates are in Kilometers UTM from Google Earth
Part 2, Section 14: Gas/Chemical Addition Rate value for ID CT-T-1 was for chemical A: 11 and B:3.  For ID CT-1201 the values were for A: 9 and B:2.5.
Part 2, Section 15: Wastewater Atmospheric Vent Federal Regulations were imported into the database, if you have any issue accessing the Federal Regulations please refer to the printed hardcopy template of Component 1.
Part 2, Section 16: For the OMS Rail Loading unit the facility owns 10% of the vessels being loaded, leases 40%, and are 60% customer vessels
Part 3, Non-Routine Emissions: Opacity Emissions do not have pollutant code and their emissions are N/A.
Part 5, Test/Monitoring Data ID “2-PM”: the following description is provided for the “Process Testing Description” for this stack test ID: Represents the emissions from the Coker CO Boiler Stack (Coker CO Boiler SO2 Relative Accuracy Test Audit SO2 compliance Demonstration PM Compliance Demonstration Opacity Observations for ExxonMobil Billings Refinery, 10/8/2010, pgs. 1 - 189, and Coker CO Boiler SO2 Relative Accuracy Test Audit SO2 compliance Demonstration PM Compliance Demonstration Opacity Observations for ExxonMobil Billings Refinery, Revised 12/13/2010, BATES LABEL 190-202)
Part 5, Test/Monitoring Data ID “2-SO2”: the following description is provided for the “Process Testing Description” for this stack test ID: Represents the emissions from the Coker CO Boiler Stack (Coker CO Boiler SO2 Relative Accuracy Test Audit SO2 compliance Demonstration PM Compliance Demonstration Opacity Observations for ExxonMobil Billings Refinery, 10/8/2010, pgs. 1 - 189, and Coker CO Boiler SO2 Relative Accuracy Test Audit SO2 compliance Demonstration PM Compliance Demonstration Opacity Observations for ExxonMobil Billings Refinery, Revised 12/13/2010, BATES LABEL 190-202)


notes:
General Comments
The following codes were used in the ICR database:
-88 = Not applicable
-90 = Confidential Business Information (CBI)
-99 = Unknown
1.	Part I, General Facility Information, Annual revenue in 2010.

Tesoro Response:  Tesoro has provided the total combined annual revenue for all of its facilities in operation in the USA. 

2.	Part I, General Facility Information, Table 15, Disposition of Products by Transport Method

Tesoro Response:  The percentages of disposition of products by transport method are the percent of 2010 production shipped.  The percentages do not include the existing inventories/receipts that were also shipped during 2010.

3.	Part I, General Facility Information, Table 16, Unit Capacity

 Tesoro Response:  There is no basis for determining the capacity and throughput for Oil Movements, therefore none are provided.

4.	Part II, Section 2, Process Heaters, Rated heat input capacity (MMBtu/hr)

Tesoro Response:  Pilot gas heat input is not considered in rated heat capacity.  

5.	Part II, Section 2, Process Heaters, Average heat input rate in 2010 (MMBtu/hr)

Tesoro Response:  Pilot gas heat input is not considered in average heat input. 

6.	Part II, Section 3, Equipment Leaks, “Do you own or have ready access to an optical or thermal imaging device for detecting equipment leaks?”

Tesoro Response:  Tesoro does not own or have ready access to optical or thermal imaging devices for detecting leaks. 

7.	Part II, Section 3, Equipment Leaks, “Average methane concentration in process fluid that contacts equipment in gas service throughout the process (ppmv)”.

Tesoro Response:  Where the average methane content will vary significantly across the plant, it is impossible to estimate.  Therefore, Tesoro does not monitor methane content at the facility. 

8.	Part II, Section 3, Equipment Leaks, “Is the average methane concentration based on sampling and analysis results or estimated (e.g., based on process knowledge).

Tesoro Response:  The average methane content will vary significantly across the plant and cannot be estimated. Tesoro has not monitored methane content in the facility.	

9.	Part II, Section 3, Equipment Leaks, Pump Seals – Light liquid.

Tesoro Response:  Tesoro has identified the number of pumps in the table. 

10.	Part II, Section 3, Equipment Leaks, Pump Seals – Heavy liquid.

Tesoro Response:  Tesoro has identified the number of pumps in the table.

11.	Part II, Section 3, Equipment Leaks, Open-ended lines.

Tesoro Response:  For purposes of this response, Tesoro will define “open ended line” as it is defined in the NSPS.  Under NSPS, open-ended line (“OEL”) “means any valve, except safety relief valves, having one side of the valve seat in contact with process fluid and one side open to the atmosphere, either directly or through open piping.” Throughout 2010, Tesoro had no equipment designed or operating as an OEL. For regulated valves that are otherwise open to the atmosphere, Tesoro meets the NSPS by applying a cap, blind flange, plug, or second valve, which effectively changes the design to no longer meet the OEL definition. If the cap, blind flange, plug, or second valve is found to not be properly installed, the refinery takes steps to replace it. Instances where a line was found to be open during an interim period in 2010 when it was designed to be capped does not make it an OEL design throughout 2010.

12.	Part II, Section 3, Equipment Leaks, Heavy Liquid – covering Pump Seals, Valves and Flanges & Connectors

Tesoro Response:  Tesoro interprets this data collection requirement for those facilities that are under fugitive monitoring program under State or Federal requirements to monitor heavy liquids components. In line with this, only Tesoro facilities that are required to conduct monitoring of heavy liquid components are submitting this data.

13.	Part II, Section 3, Equipment Leaks, Compressor Seals.

Tesoro Response:  Tesoro has indicated the number of compressors in the table.

14.	Part II, Section 3, Equipment Leaks, Atmospheric PRD-Gas-Monitoring of Releases-Number of PRD monitored using a system designed to measure the duration of a release and/or the quantity of compounds released.

Tesoro Response:  Tesoro does not have a specified system to monitor measure flow rate specific to PRD monitoring.

15.	Part II, Section 4, Storage Tanks, Storage Tank General Information.

Tesoro Response:  Tesoro has not included information in Table 4-1 for spheres or pressurized tanks used for storage of compressed Propane and Butane.

16.	Part II, Section 4, Storage Tanks, Total throughput for all materials stored in the tank in 2010 (bbl).

Tesoro Response:  Tesoro’s tank throughput is based on change in tank levels as used in Emissions Inventory Calculations. 

17.	Part II, Section 8, Catalytic Reforming Unit, Operating Pressure (psig).

Tesoro Response:  Tesoro is reporting the average reactor pressure [i.e., (Lead + Lag) ÷ 2] due to the pressure measurement location not being defined in the ICR. 

18.	Part II, Section 11, Other Atmospheric Vents. 

Tesoro Response:  Process gas chromatograph sampling system streams are typically vented to the flare. The sample that goes through the analyzer, about 160 ml every 2 to 5 minutes, is vented to atmosphere.

CB-101 is also associated with EUI 1: CRUDE, EUI1: Poly and EUI8: VRU

CB-701 is also associated with EUI 8: RAIL RACK

19.	Part II, Section 13, Fuel Gas Treatment Units. 

Tesoro Response:  The estimated annual average total sulfur concentration is based on one fuel gas grab sample analysis from the year 2000. Routine analysis does not include COS, CS2, or Mercaptans.

20.	Part II, Section 15, Wastewater Collection and Treatment, Average VOC concentration (ppmw).

Tesoro Response:  Tesoro has not analyzed VOC concentration (ppmw) or total HAP concentration, and therefore does not have a good estimate to report.  As a result, Tesoro has left these fields blank. 

21.	Part III, Non-Routine Emissions

Tesoro Response:  Tesoro will meet this requirement by submitting all agency reportable emissions that occurred during periods of startup/shutdown and component malfunction for the year 2010.

22.	 Part IV, Cost Data (Optional) - CONFIDENTIAL BUSINESS INFORMATION REDACTED

Tesoro Response - CONFIDENTIAL BUSINESS INFORMATION REDACTED: IIn addition to the capital costs for the Boiler #1 and Boiler #2 Ultra Low NOx Projects, an additional $CBI*  was spent on temporary boilers that were used to allow the refinery to maintain production during the construction phase of the project.

* Tesoro considers the cost of the rental boilers to be Confidential Business Information.   

23.	Part V, Emissions Monitoring and Source Test Data, Qualified CEMS Data.

Tesoro Response:  Tesoro is submitting data for all CEMS that fall under the purview of Federal regulations. Tesoro is not including in its response continuous monitors required by state or other agencies that do not meet federal CEMS testing and compliance assurance requirements.

Tesoro does not monitor stack moisture. The analyzers on Boiler 1, Boiler 2, and the FCCU measure on a dry basis, and the analyzer on the SRU is corrected to a previously determined percent moisture.


notes:
For process units, emission point IDs (PT#) were used where applicable; however, some emission points include multiple process units.  For these process units, the emission point ID is used, followed by a letter (e.g., PT1-A, PT1-B, etc.).

For emission points including multiple process units (e.g., PT3 includes two 106 MMBtu/hr boilers), capacity figures represent the totals for the units (e.g., PT3 boiler heat input capacity = 212 MMBtu/hr).

The refinery had a turn-around in 2010.  In Part I, Question 16, the actual throughput values provided are estimates of expected "normal" 2010 processing rates had the facility not had a turn-around.


notes:
GENERAL COMMENT:  Data provided in this submittal is limited to the sources that were operating in 2010 and the sources which had relevant source testing data as requested in Component 1 Instructions for Part V.  The atmospheric and vacuum distillation capacity at the 80,000 bbl/cd Perth Amboy Crude Unit has been idle since 2008, therefore there will be no data reported for these units.  Associated support units which include the boilers, NaSH Plant, Flare, and Cooling Tower were also idled in 2008.  The boilers are included in this submittal because there is relevant source testing data to submit.  The sources that were operating in 2010 were limited to tankage, marine product loading of heating oil, and the wastewater collection and treatment systems, as well as associated component fugitives.

SECTION 15 
Question 3 - these items have been marked as N/A because the only tanks that were water drawn in 2010 contained heating oil and are considered negligible sources for BWON purposes.  Based on the influent concentration data measured at the effluent treatment plant less than 1lb of benzene entered the effluent treatment plant in 2010.
Question 5 Wastewater Generation Information - there are no process units operating that routinely generate wastewater.
Table 15-1 Wastewater Treatment Process identified as #3 Dissolved air/gas floation is actually an Induced Air Floatation Unit.

SECTION 16
Thermal oxidizer is available for control during loading of material with a vapor pressure of 0.02 psia or greater at 70 F.  In 2010 no material was loaded that was in this vapor pressure range, so no controls were required during loading.


notes:
Part I Question 11: Total Revenue for NuStar Energy LP                                                    Part I Question 16: U12 Crude 2W - Throughput Estimated: Approx.  80% of Crude Unit 2E throughput.                                                                                                               Part I Question 16: U5 and U18 Storage Tanks - Unit throughput capacity based on air permit throughput limitations for straight run gasoline and crude oil.                                                Part I Question 16: Steam Demand by Process Unit - U12 Crude Unit 1 and U12              Crude Unit 2W :  Steam Generation for process. Quantity used for heating is unknown.           Part I Question 16: Steam Demand by Process Unit - U12 Crude Unit 2E, IS3  No. 6 FO Railcar loading, IS4 Asphalt truck loading, IS7 Dock ,1 2, 3 (Marine Loading), IS8 Asphalt Railcar Loading, U2 MECS (DOCK 1) - SRG Loading,  U30 PMA, and Unit 3 FGTS : Quantity of steam used for heating is unknown.                                                                                         Part II Section 2: Rated heat input capacity (MMBtu/hr) - [CBI] represents combined heat input capacity for process heaters H-601 and H-602.
Part II Section 3: U12 Crude Unit 1, U12 Crude Unit 2E, U12 Crude Unit 2W, U2 MECS and Unit 3 FGTS - average methane concentration in process fluid that contacts equipment in gas service throughout the process is from a combined total of refinery gas (88% Methane) and Mixed Gas (14% Methane).                                                                                    Part II Section 3 - Values reported are for combined U12 Crude Unit 2E and 2W                    Part II Section 3 - Values reported under IS7 Dock 1, 2 and 3 (Marine Loading) are combined values for Docks 1, 2 and 3.                                                                                     Part II Section 3 - Heavy valves for Unit 1, Unit 2, Unit 3 and PMA were estimated using Table 2-4 in the EPA Emission Protocol for Petroleum Refineries.                                                  Part II Section 3 - Flanges and connectors were estimated using Table 2-4 in the EPA Emission Protocol for Petroleum Refineries.                                                                              Part II Section 3 - Open ended lines were estimated using Table 2-4 in the EPA Emission Protocol for Petroleum Refineries.  Values shown are potential open ended lines and do not meet the EPA definition of open ended lines.                                                                Part II Section 3 - It was assumed that 90% of open ended lines in gas or light liquid service are monitored during quarterly valve monitoring.                                                          Part II Section 3 - Heavy valves for asphalt railcar and asphalt truck rack based on a review of P&IDs.                                                                                                                     Part II Section 3 - Heavy valves for docks and No. 6 fuel oil railcar were based on counts on known systems.                                                                                                        Part II Section 3 - Open ended lines for truck loading, railcar loading and docks were based on the average ratios provided for processes shown in Table 2-4 in the EPA Emission Protocol for Petroleum Refineries.                                                                                             Part II Section 3 - The tank process unit only include tanks that contain liquids with a vapor pressure above 0.1 psi.                                                                                             Part II Section 3 - Natural gas valves in Unit 1, Unit 2, Unit 3 and MECS are based on a review of P&IDs.                                                                                                            Part II Section 3 - Natural gas valves in Boiler A based on a review of P&IDs.                     Part II Section 3 - Natural gas valves in PMA heater estimated based on PAK tank heater valve count.                                                                                                                      Part II Section 3 - Sample connections were included in valve counts.                               Part II Section 12 Question 2: Typical lower heating value of waste gas - BTU value based on off gas sampling conducted by stack testing firm in October 2005.                                        Part II Section 13 Question 2: Estimated annual average total sulfur concentration in treated fuel gas -  Sulfur concentration is based on the hydrogen sulfide concentration. However, other sulfur compounds may be present.


energy_management_plan_description:
The Refinery has a robust plan that includes an energy performance checklist used for projects, fired heater oxygen management, steam trap repair program, steam leak repair program, heat exchanger cleaning, and compressed air leak repair. Please see note.

notes:
Part I - Process Units' Throughput Capacity and Actual Throughput:  

For the following units, the CBI version includes the average actual throughput and number of days of downtime, or other qualifying information affecting throughput:

FCBW;  
CLEU;
USBW;
ABW; 
ISOM-2;
H2BW;
7PS;
7VPS;
SDA;
FGBW;
PPBW;
PFBW;
CRUBW;
CNHBW;
POLYT;
POLYSP;
DSU-1;
DSU-2;
HRU-1 (HPU);
LORU;
PRBW;
BIBFBW;

For Polypropylene Rail Car Rack, the throughput data is included with PPBW;

For Polypropylene Truck Rack, the throughput data is included with PPBW;

For CNHBW-T-602, the throughput data is included with CNHBW;

For DSU-1-T-101, the throughput data is included with DSU-1;

For DSU-2-T-403, the throughput data is included with DSU-2;

For DSU-2-T-402, the throughput data is included with DSU-2;

For Linden Terminal, the units for the average actual throughput entered into the database are bbl/cd;

For Linden Terminal Gasoline Rack, the throughput data is included with Linden Terminal;

For Linden Terminal ULSD Rack (Top Loading), the throughput data is included with Linden Terminal;

For Linden Terminal ULSD Rack (Bottom Loading), the throughput data is included with Linden Terminal;

For Linden Terminal LPG Rack, the throughput data is included with Linden Terminal;

For BW Marine Terminal, the units for the average actual throughput entered into the database are bbl/cd;

For BW Marine Terminal Steamer Docks, the throughput data is included with BW Marine Terminal;

For BW Marine Terminal Barge Piers (Heavy Products), the throughput data is included with BW Marine Terminal;

For BW Marine Terminal Barge Piers (Light Products), the throughput data is included with BW Marine Terminal; and

For MLR, the units for the average actual throughput entered into the database are bbl/cd.

Part I Additional CBI Items - In addition to the options on the database, Bayway Refinery considers the following entries to be CBI: Disposition of Products by Transport Methods (% used onsite, % shipped by barge, % shipped by tank ship, % shipped by barge, % shipped by tank truck, % shipped by rail car and % shipped by pipeline), and Steam consumption for the processing unit in 2010 (tons/yr) (information required in Part II, Section 2, Question 6 - Table 1-3 Steam Demand by Process Unit).

These items are reflected on the non-CBI data disk
___________________________________________________________________________

Part II Section 1 Energy - Key elements of the energy management plan and key energy reductions that have resulted from the plan's implementation Full Description is as follows: 

“The Refinery has a robust plan that includes an energy performance checklist used for projects, fired heater oxygen management, steam trap repair program, steam leak repair program, heat exchanger cleaning, and compressed air leak repair.  The Refinery also has a long term program to identify energy efficiency opportunities and implement those projects in upcoming years.” 

Part II Section 1 Energy Additional CBI- In addition to the options on the database, Bayway Refinery considers the following entries to be CBI: 

Air preheat (pick from list or "Other (specify)"), Air preheat temperature (°F), Disposition of electricity (pick from list), Pressure of steam (psia), and Disposition of steam (pick from list).

These items are reflected on the non-CBI data disk
___________________________________________________________________________

Part II Section 2 Heaters - Heater F-751 at 7VPS (Pre Turnaround) was decommissioned in September 2010, Heater F-752 (Post Turnaround) - was commissioned in November 2010; 

Due to the current stay of 40 CFR 63 Subpart DDDDD, that rule was not considered for possible applicability to the facility process heaters and boilers; For F-500, 40 CFR 60 Subpart Ja does not go into effect until 2012;

For Heater F-502, the average heat input rate for 2010 was less than 1 MMBtu/hr so it was rounded to 0 MMBtu/hr in the database.  

Part II Section 2 Heaters Additional CBI - In addition to the options on the database, Bayway Refinery considers the following entries to be CBI: 

Energy efficiency measures, % of total operating hours fired with primary fuel in 2010, and % of total operating hours fired with secondary fuel in 2010.

These items are reflected on the non-CBI data disk

___________________________________________________________________________

Part II Section 3 Equipment Leaks - Process Units - Leak Definitions for Valves are governed by EPA Consent Decree H-05-258; Linden Terminal is not subject to Consent Decree H-05-258.  Therefore, the Linden Terminal adheres to different monitoring frequencies and leak definitions; 

Numbers of equipment for Valves in Heavy Liquid Service were estimated from number of HL pumps times the ratio of LL valves to LL pumps in the same unit. 

For Flanges and Connectors in Gas and Light Liquid Service: Numbers of equipment were estimated by Estimated by (3 x (valves + PRDs)) + (24 x (pumps + agitators + compressors)) and leak definitions are 1,000 ppmv for gas/vapor and 10,000 ppmv for light liquid.  

For Flanges and Connectors in Heavy Liquid the numbers of equipment were estimated from (3 x HL valves) + (24 x HL pumps). 

The number of potential open ended lines is an estimate developed for the Bayway site. 

For PRD routed to atmosphere in Gas Service monitored with Method 21, the leak definitions are 1,000 ppmv for equipment subject to state regulations only, 500 ppm for equipment subject to EPA Consent Decree H-05-258 as well.  

Part II Section 3 Equipment Leaks - Process Units CBI:  Bayway Refinery is considering the following entries to be CBI:  

Total number of pressure relief devices (in all service types), Number of PRD in Gas Service routed to a fuel gas system or control device, Number of PRD in Liquid Service routed to a fuel gas system or control device, Number of PRD in Gas Service routed to the atmosphere, Number of PRD in Gas with rupture disk or other non-reclosing device routed to the atmosphere, Number of PRD in Liquid Service routed to the atmosphere, and Number of PRD in Liquid Service with rupture disk or other non-reclosing device routed to the atmosphere.

Part II Section 3 Equipment Leaks - Gas Systems - Leak Definitions for Valves are governed by EPA Consent Decree H-05-258; FGS or NGS were added to the end of each process unit to denote that there is a fuel gas system or natural gas system for that process unit.
___________________________________________________________________________

Part II Section 4 - Storage Tanks CBI - Bayway Refinery considers the following entries to be CBI: Total throughput for all materials stored in the tank in 2010 (bbl), the last year the tank was degassed and the year anticipated for next degassing event (pick from list).

These items are reflected on the non-CBI data disk
___________________________________________________________________________

Part II Section 5 - Catalytic Cracking Unit - Recycle/resid capacity is based on 42% Atm Resid and 7% DAO. 

Part II Section 5 - Catalytic Cracking Unit - Additional CBI - In addition to the options on the database, Bayway Refinery considers the following entries to be CBI:  

Fresh feed capacity (bbl/cd), Recycle/resid capacity (bbl/cd), Percent of CCU Feed that is hydrotreated (%), Typical coke burn rate at capacity (tons/cd), and Type of CCU Regenerator (pick from list).

These items are reflected on the non-CBI data disk

___________________________________________________________________________

Part II Section 8 - Catalytic Reforming Unit Additional CBI - In addition to the options on the database, Bayway Refinery considers the following entries to be CBI:  

Operating Pressure, Average annual regeneration frequency (cyclic and semi-regen units,: regeneration cycle/year), Average annual regeneration time (hours/year), Depressurization/Purge Cycle Vent Disposition/control (pick from list or "Other (specify)"), Purge Process Type (pick from list or "Other (specify)"), Coke burn-off cycle vent disposition/control (pick from list or "Other (specify)"), Coke burn-off cycle duration per cycle, Rejuvenation cycle vent disposition/control (pick from list or "Other (specify)"),  and Reduction or Activation cycle vent disposition/control (pick from list or "Other (specify)".

These items are reflected on the non-CBI data disk

___________________________________________________________________________

Part II Section 12 - Flares - Poly Flare and ABW Flare will become subject to NSPS Subpart J by December 31, 2011.
___________________________________________________________________________

Part II Section 15 - Wastewater Collection and Treatment - Processes: The Bayway Refinery Benzene Waste Stripper (PWWS) uses fuel gas as the stripping media instead of steam.  That option was not available on the pick list.

Part II Section 15 – Wastewater Collection and Treatment - Facility-Level Questions - The refinery WWTS processes an average of 832,632 gallons/day of wastewater from third parties that contains no benzene.

There are six oil-water separators at the refinery and they are: Linden Terminal Separator (affected by N.J.A.C. 7:27-22), API Oil Water Separator (affected by BWON, Refinery Wastewater NSPS and N.J.A.C. 7:27-22), Tremley Separator (affected by N.J.A.C. 7:27-22), 40 Acre Tankfield Separator, East Rahway River Tank Separator (affected by N.J.A.C. 7:27-22) and West Rahway River Tanks Separator (affected by N.J.A.C. 7:27-22).

There are two sour water strippers at the refinery (PWTU2 and PWTU3).

There are four Equalization basins/tanks at the refinery and they are: ESEN Basin, East Retention Basin (affected by N.J.A.C. 7:27-22), Tank 136 (affected by Refinery MACT 1, 40 CFR 60 Subpart Kb, N.J.A.C. 7:27-16 and N.J.A.C. 7:27-22) and Tank 530 (affected by Refinery MACT 1, N.J.A.C. 7:27-16 and N.J.A.C. 7:27-22).
___________________________________________________________________________

Part II Section 16 – Product Loading Operations: For Linden Terminal Gasoline Rack and Linden Terminal ULSD Rack (Bottom Loading), the control device is carbon adsorber or thermal or catalytic incinerator / oxidizer (Thermal or Catalytic Incinerator/oxidizer is back-up to the carbon adsorber). 
___________________________________________________________________________


Part III Non-Routine Emissions - 10/25/2010 - FCBW Full Event Description: A total power failure (originating outside the refinery) in excess of 24 hours led to the following incidents which occurred during the shut down and subsequent start ups which commenced on 10/25 and lasted through 11/4.  Two atmospheric safety valves lifted at the FCC during the power failure.

Part III Non-Routine Emissions - 10/27/2010 - H2BW Full Event Description: The H2 Plant NOX ppm limit was exceeded for six block hours during the warm up of the F-500 furnace when an EIV (Emergency Isolation Valve) malfunctioned in the ammonia delivery system to the SCR.  The unit was being prepared to restart after the total power failure.

Part III Non-Routine Emissions - 10/30/2010 - H2BW Full Event Description: The H2 Plant NOX ppm limit was exceeded for eleven block hours on 10/30 and seven block hours on 11/4 to make repairs to the SCR B vaporizer (an inability to isolate the vaporizer necessitated brief outages of the SCR system to provide and then remove positive isolation).

Part III Non-Routine Emissions - 11/2/2010 - FGBW, POLYT, CNHBW-T-602, DSU-1-T-101, DSU-2-T-403 and DSU-2-T-402 Full Event Description: During the restart of a transformer within the refinery electrical system (following the power failure); transient harmonics caused a VFD compressor (Variable Frequency Drive) at the third party sulfuric acid regeneration plant to trip; which resulted in the flaring of refinery acid gas for 27 minutes before the compressor was restarted.  It was later found that an acid gas dump valve to the flare was leaking through for another ten and one half hours..  
___________________________________________________________________________

Part IV  Cost Data for APCD (Optional) CBI - Bayway Refinery considers the following entries to be CBI:  

Primary equipment ($), Auxiliary equipment ($), Instrumentation and monitors ($), Sales tax and freight ($),Total purchased equipment costs ($), Installation costs ($), and Total Installed Cost of APCD ($).

These items are reflected on the non-CBI data disk.

Part IV  Cost Data For Process and Equipment Changes (Optional) CBI - Bayway Refinery considers the following entries to be CBI: 

Number of days process shut down in order to make the change (days of lost production), Total capital cost $, and Change in total annual operating cost $/yr.

These items are reflected on the non-CBI data disk.
____________________________________________________________________________

Part V Source Tests and Monitoring Data Provided – For MVR 301 CO CEMS_Daily and MVR 302 CO CEMS_Daily, there are two vapor combustors serving the piers and each can serve either pier.  Therefore, one must look at the CEMS results from both stacks in conjunction with the loading to get a proper picture of emissions relative to process throughput.

In addition, Bayway Refinery considers the daily throughput for MVR 301 CO CEMS_Daily and MVR 302 CO CEMS_Daily to be CBI.  This is reflected on the non-CBI data disk.


notes:
LDAR component count for heavy liquid valves, heavy liquid pumps, all flanges (gas, LL, HL), and open ended lines are estimated.  Used Table 2-5 in ICR Estimated Protocol as a reference. LDAR counts for fuel gas treatment systems are not segregated in current refinery LDAR data base. The ARU is separate and LDAR component counts provided. Total LDAR component count for Crude Unit 6 (atmospheric and vacuum sections) is included under Crude Unit 6 atm. Total LDAR component count for Crude Unit 7 (atmospheric and vacuum towers) is included under Crude Unit 7 atm.


physical_address:
17 miles east of Gallup, NM at Exit 39 of Interstate 40 in Jamestown, NM

plant_name:
Western Refining Southwest, Inc. - Gallup

notes:
Annual 2010 Revenue is for all Western Refining, Inc. facilities combined.

Western Refining Southwest, Inc. and Giant Industries, Inc. are separate companies with separate board of directors.

The ISOM unit is no longer operating and intentions are to convert the unit to another process within the next few years.

Fuel flow meter for process heater P-H2 is not working correctly.


energy_management_plan_description:
Holly has in the last year begun a corporate-wide energy management best practices team to champion effective energy management at all facilities. (continued in Notes - Energy Management Plan)

notes:
Some information was not readily available within the response time allotted by EPA.

Part I. General Facility Information.
Annual Revenue in 2010
In the Holly accounting system, the annual revenue for both the Artesia and Lovington refineries is combined and not reported separately.  Therefore the number reported here is for both facilities combined.
Parent Company
All employees within the Holly Corporation structure are employed by Holly Logistics Services, LLC, a subsidiary of Holly Corporation, and are not directly employed by Holly Corporation.  Total employees of Holly Logistics Services, LLC are 1,638.
Products Produced
Other Miscellaneous Products represents Molten Sulfur

Process Units
Notes describing unusual operation, and “Normal” Processing Rates 
002 – [CBI]
003 – [CBI]
011 – [CBI]
012 – [CBI]
018 – [CBI]
019 – [CBI]
021 – [CBI]
034 – [CBI]
037 – Throughput units are GPM; Plant averages 40% Condensate recovery with deaerators operating at 50% capacity due to pumping limitations – N/A
039 – Throughput units are lb/hr
040 – Throughput units are lb/hr
043 – Out of service as of Feb 2010 – N/A
044 – [CBI]




Part II. Section 1. Energy Management
Energy Management Plan - 
This team is tasked with driving energy optimization at all facilities through aggressive implementation of energy management best practices and leading the organization to achieve sustainable energy cost reductions.  The team has objectives to reduce energy consumption by 15% over the next 3 years, implement systems to enable better monitoring and management of critical process and utility energy systems, and to target efficiency gains through improved operations, maintenance, and plant modification/capital expenditure.  
 
• All of the refineries have enhanced their furnace efficiency management, reducing excess O2 levels by over 2% from 2009-2010
• A Corporate Energy Director was appointed in 2010
• An extensive internal energy assessment benchmarking was completed in late 2010 to quantify energy improvement opportunities at all refineries
• Bids were solicited for a long term partnership with an energy management consulting firm, and preliminary selection has been made to begin work in 2011 with KBC Engineering
• An corporate wide Alliance agreement has been negotiated with a major steam system equipment manufacturer to provide steam trap and steam system mechanical integrity improvement.  This includes annual trap testing and maintenance which began in April 2011
• Positions were approved for added headcount in each refinery to support energy management activity, and hiring is currently underway to fill those positions.
• Energy improvement alternatives are considered in all projects and refinery expansions undertaken by Holly.  An example is the Crude and Vacuum Unit upgrades completed at Navajo in 2009, where preflash columns and enhanced crude feed preheat trains were installed to reduce energy requirements.

Part II. Section 9. Sulfur Recovery Unit (SRU)
SRU back-up measures (for all SRUs) – 
Dedicated SRU flare
General plant flare
Divert to other SRU

Part II. Section 5. Catalytic Cracking Unit. 
E-Cat and CCU Fines Metal Concentration – 
[CBI]
Part II. Section 5. Catalytic Cracking Unit.                                                                      E-Cat and CCU Fines Metal Concentration – 
[CBI]

Part II. Section 12. Flares
Flares really only receive waste gas during SSM, so typical LHV reported was for header sweep gas.


notes:
Some information was not readily available within the response time allotted by EPA.

Part I. General Facility Information.
Parent Company
All employees within the Holly Corporation structure are employed by Holly Logistics Services, LLC, a subsidiary of Holly Corporation, and are not directly employed by Holly Corporation.  Total employees of Holly Logistics Services, LLC are 1,638.

Annual Revenue in 2010
In the Holly accounting system, the annual revenue for both the Artesia and Lovington refineries is combined and not reported separately.  Therefore the number reported here is for both facilities combined.

Process Units
Other miscellaneous products is Depropanized Gas to 3rd Party.

Notes describing unusual operation
85 – Off-gas typically is sent out of the refinery to a gas plant. When the gas plant are unable to take the Off-Gas, the Off-Gas is sent through the Scrubber and mixed with the incoming Natural Gas,  The combination of natural gas and scrubbed process off-gas is used as refinery fuel. 

Part II. Energy Management Plan
Energy Management Plan - 
This team is tasked with driving energy optimization at all facilities through aggressive implementation of energy management best practices and leading the organization to achieve sustainable energy cost reductions.  The team has objectives to reduce energy consumption by 15% over the next 3 years, implement systems to enable better monitoring and management of critical process and utility energy systems, and to target efficiency gains through improved operations, maintenance, and plant modification/capital expenditure.  
 
• All of the refineries have enhanced their furnace efficiency management, reducing excess O2 levels by over 2% from 2009-2010
• A Corporate Energy Director was appointed in 2010
• An extensive internal energy assessment benchmarking was completed in late 2010 to quantify energy improvement opportunities at all refineries
• Bids were solicited for a long term partnership with an energy management consulting firm, and preliminary selection has been made to begin work in 2011 with KBC Engineering
• An corporate wide Alliance agreement has been negotiated with a major steam system equipment manufacturer to provide steam trap and steam system mechanical integrity improvement.  This includes annual trap testing and maintenance which began in April 2011
• Positions were approved for added headcount in each refinery to support energy management activity, and hiring is currently underway to fill those positions.
• Energy improvement alternatives are considered in all projects and refinery expansions undertaken by Holly.  An example is the Crude and Vacuum Unit upgrades completed at Navajo in 2009, where preflash columns and enhanced crude feed preheat trains were installed to reduce energy requirements.

Part II. Section 12. Flares
Flares really only receive waste gas during SSM, so typical LHV reported was for header sweep gas.

Section 16. Product Loading Operations
Typical annual operating hours (hr/yr): 4368, assumption: 12 hr/day, 7 days/week.


notes:
No non-routine emissions in 2010.
"NAC" is Nevada Administrative Code in "Other Air Reg(s)" tab. NAC's are referenced in Foreland's Class II Air Quality Operating Permit issued by Nevada Division of Environmental Protection (NDEP).
Loading rack capacity is based on the pump capacity running 12 hours a day all year.
In Section 2, propane is used only to start the furnaces.
Tanks with -88, unknown, for vapor pressure are out of service


notes:
Part II - Section 3. LDAR and PRD Process Unit ID Notes:
Cokers 2 and 3 include LDAR and PRD equipment from Coke Rail Loading and Coker Amine Treater,
TRP Amine includes LDAR and PRD equipment from the East Old Feed Amine Treater,
Tail Gas Treater #1 includes LDAR and PRD equipment from the EPA Amine Treater,
Hydrogen Plant includes LDAR and PRD equipment from the East New Feed Amine Treater,
Vac 1 includes the LDAR equipment from the Vac 1 Amine Treater,
Crude 1 includes the PRD equipment from Vac 1 and Vac 1 Amine Treater,
Crude 2 includes the PRD equipment from Vac 2,
Other Tank Farms, Blending, and Loading includes the LDAR and PRD equipment from Loading Marine Dock, Loading Rail Rack, Loading Decanted Oil, and Loading LPG/Propylene,
Asphalt Plant includes the LDAR and PRD equipment from Loading Asphalt Trucks,
SRU #2 includes the LDAR and PRD equipment from Loading Sulfur Rail and Loading Sulfur Trucks,
SRU #2 includes the PRD equipment from SRU #3,
Fluid Catalytic Cracker includes FCC1, FCC2, and Cat Poly From LDAR,
Tail Gas Treater 2 includes Reported Benzene Strippers from LDAR,
ADHT includes ADHT + Merox Jet Fuel Treater from LDAR,
Naphtha Hydrotreater includes Includes DIB and Sat Gas Plant from LDAR,
Asphalt Plant - Includes Asphalt Plant and Asphalt Loading racks from LDAR,
Other LDAR - Boilers, includes West and East Alstom Boiler LDAR and PRD equipment,
Other LDAR - Tanks, Blending, Loading - Includes North, West, East tank farms, and
Other LDAR - Flares - Includes East and West Flare from LDAR.

Part II, Section 13 - estimated total average sulfur concentration: BPH Toledo has one data point on the total sulfur content of one of the EPA amine contactor.  BPH is continuing to investigate this issue, but consider a single data point to be inadequate to provide a basis for estimating the annual total sulfur concentration in the treated fuel gas exiting that contactor.


plant_name:
Marathon Petroleum Company LP - Ohio Refining Division

notes:
1.Part I, Q 11 - Annual Revenue: The 2010 Marathon Oil Corporation revenue was $72,321 million.  The 2010 Refining, Marketing & Transportation segment revenue was $62,487 million.
2.Part I, Q 16 – 4-34 SRU & 4-38 SRU production: Individual SRU production is not measured, only a total.  Therefore, an average rate is taken for each unit.
3.Part I, Q 16 – 4-9A Asphalt Rail Loading & 4-20A Propane Rail Loading Capacities: Both asphalt and propane rail loading operations share the loading rack. The throughput capacity is reported under 4-9A Asphalt Loading.
4.Part I, Q 16 – Miscellaneous Units Capacities and Throughputs: -99 denotes either capacities and throughputs are accounted for in another unit or the information is not readily available or required.
5.Part II, Section 1, Q 4 – Energy Plan: Marathon is constantly evaluating a wide range of projects and programs to maintain and improve energy performance. Economically attractive projects are incorporated into the strategic and business planning process. We have a corporate Energy Technologist and an Energy Engineer at our refinery dedicated to these activities. Marathon instituted a new energy initiative in 2010. The Focus on Energy program is designed to identify specific and actionable metrics in daily operations and to make energy incentives more visible to the refinery operations personnel. The initiative is also expected to identify additional medium and long-term improvements available for implementation. During the balance of 2011, these will be condensed to the most critical items and tracked by daily reports to operations and management.
6.Part II, Section 1, Table 1-3 – 4-31 MEA & 4-35 SCOT Steam Consumption: The steam consumption for these units are combined and reported under Unit 4-31 MEA.
7.Part II, Section 3 – 4-9 Asphalt Equipment Leaks: All units numbered 4-9 or 4-9A are reported together under one unit, 4-9 Asphalt.
8.Part II, Section 3 – Liquid Sampling Connections: Differences between number of pieces and number of pieces monitored is due to some of the samplers and their connectors being in a HL service that are not normally monitored.
9.Part II, Section 3 – 4-0 Crude Liquid Sampling Connections: 100 connections are monitored quarterly. The other 60 connectors are in HL service and are not monitored on a set interval. (Only during sensory monitoring.)
10.Part II, Section 3 – 4-4 Vacuum Compressor Seals: The Vacuum unit has one compressor. However all of the potential leak areas including the seals are monitored as compressor test points (CTPs). Therefore, while there is one compressor, 26 test points are monitored. 
11.Part II, Section 3 – 4-27 HF Alky Compressor Seals: The HF Alky unit has one compressor. However all of the potential leak areas including the seals are monitored as compressor test points (CTPs). Therefore, while there is one compressor, 35 test points are monitored. 
12.Part II, Section 3 – 4-39 DHT Liquid Sampling Connections: 20 connections are monitored quarterly. The other 80 connectors are in HL service and are not monitored on a set interval. (Only during sensory monitoring.)
13.Part II, Section 3 – 4-2 KHT Compressor Seals: The KHT unit has two compressors. However all of the potential leak areas including the seals are monitored as compressor test points (CTPs). Therefore, while there are two compressors, 140 test points are monitored.
14.Part II, Section 3 – 4-32 GHT Compressor Seals: The GHT unit has two compressors. However all of the potential leak areas including the seals are monitored as compressor test points (CTPs). Therefore, while there are two compressors, 224 test points are monitored.
15.Part II, Section 3 – 4-33 CCR Compressor Seals: The CCR unit has three compressors. However all of the potential leak areas including the seals are monitored as compressor test points (CTPs). Therefore, while there are three compressors, 148 test points are monitored.
16.Part II, Section 3 – 4-39 DHT Compressor Seals: The DHT unit has two compressors. However all of the potential leak areas including the seals are monitored as compressor test points (CTPs). Therefore, while there are two compressors, 152 test points are monitored.
17.Part II, Section 3 – 4-14 FWS PRD: The 1 PRD is DTM and gets monitored annually. 
18.Part II, Section 4 – Tank 248 Throughput: Throughput was measured by amount of Biosludge shipped offsite which equals 397 tons.
19.Part II, Section 4 – Tanks 238 and 248 Year of Previous Degassing: No records exist of a previous degassing or cleaning for these tanks.
20.Part II, Section 4 – Tank 246 Type of Tank/Controls: Tank 246 is equipped with a conservation lid.
21.Part II, Section 4 – Tank 270 Type of Tank/Controls: Tank 270 is equipped with a Pressure Vacuum Vent (PVV) which only vents when needed.
22.Part II, Section 8 – 4-33 CCR: Coke burn-off cycle duration units are hours.
23.Part II, Section 9 – 4-38 SRU: There is only one sulfur pit, therefore, no controls or sulfur pit maintenance data is given for 4-38 SRU. Also see Note 2 regarding production.
24.Part II, Section 14 – 15-CT-001-004 Gas or Chemical Additive/Disinfection Method: Primary disinfectant is sodium hypochlorite; however, chlorine dioxide is also used. 
25.Part II, Section 14 – 15-CT-001-004 Gas or Chemical Addition Rate Value and Unit: A target of 0.3-0.7 ppm of residual chlorine is used to determine that amount of chemical added. Therefore, the chemical is not added at a given rate but rather in the amount needed to maintain the target.
26.Part II, Section 15, Table 15-2 – Wastewater Generation Information: Unit 4-14 Flare System includes the north and south flare.
27.Part II, Section 15, Table 15-2 – Wastewater Generation Information: Concentration of organic HAP is unknown.
28.Part II, Section 16 – Capacity Loading Throughput: See note 3.
29.Part II, Section 16 – Vessel Ownership: Marathon Petroleum Company LP owns some of the tank trucks loaded.
30.Part V – 14(FD)-R(10): The RATA was performed on the North Area and South Area Fuel Drums, but entered into the ICR as part of the North Flare since all units are associated with the fuel system.


