oklahoma department of environmental … · web viewheat generated by the thermal oxidizer is...

DRAFT

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITYAIR QUALITY DIVISION

MEMORANDUM January 16, 2008

TO: Phillip Fielder, P.E., Permits and Engineering Group Manager

THROUGH: Matt Paque, Supervising Attorney

THROUGH: Kendal Stegmann, Senior Environmental Manager

THROUGH: Richard Kienlen, P.E., Engr. Mgr. II, New Source Permits Section

THROUGH: Peer Review, David Schutz, P.E., New Source Permits Section

FROM: Herb Neumann, Regional Office at Tulsa (ROAT)

SUBJECT: Evaluation of Permit Application No. 2007-005-C (M-1)Sinclair Tulsa Refining Company (STRC)Tulsa Refinery (SIC 2911)902 W. 25th Street, Tulsa, Tulsa County (36.126N, 96.002W)Sections 13, 14 and 23, T19N, R12E

I. INTRODUCTION

Sinclair Tulsa Refining Company (STRC) currently operates their Tulsa Refinery under Permit No. 98-021-TV and its many modifications. STRC has submitted a renewal application that is currently in process as Permit No. 2007-005-TVR, referenced hereafter as the TVR. The applicant now requests authority to install several new process units and to modify several existing process units. This project is known as the Heavy Crude Processing Expansion (HCPE) project.

II. FACILITY DESCRIPTION

The Tulsa Refinery is a fuels refinery with several major process units. Other activities include various minor processes outside the major units, including storage and transfer of products. Much of the equipment is “grandfathered,” having been placed in service before permitting requirements. The oldest construction dates from approximately 1907, when the Texas Company commenced building in the area. STRC purchased the facility from Texaco in 1983. Refinery property covers approximately 470 acres.

New equipment to be constructed includes a delayed coker unit (DCU), a crude distillation unit (CDU #2), a hydrocracking unit (HCU), a hydrogen plant (H2 Plant), three sulfur recovery units (SRU #3, SRU #4, SRU #5) and their associated tail gas treating units (TGTU), a diolefin reactor/splitter, and a distillate fuel off-loading rack. Construction of the new sulfur complex

PERMIT MEMORANDUM NO. 2007-005-C (M-1) DRAFT

includes two new sour water stripper units (SWS #3, SWS #4). Additions and extensions to existing systems include two amine regeneration units (ARU #3, ARU #4), a flare gas recovery system and emergency flare #3, several storage tanks or vessels, the instrument air system, and emergency system.

Several units will be modified, including the distillate hydrotreater unit (DHTU), the fluid catalytic cracking unit (FCCU), the continuous catalytic reforming (CCR) unit, the wastewater treatment plant (WWTP), the polymer/alkylation (POLY/ALKY) unit, and the Unifiner/Penex (Penex) unit.

Additionally, some equipment will be removed from service. Items to be retired include the existing CDU (CDU #1), SRU/TGTU #1, API separators at the WWTP, and a number of storage tanks. The significance of these removals or retirements is principally with respect to PSD netting considerations.

Descriptions of each existing and proposed new unit follow these introductory paragraphs. Greater detail is provided in the descriptions of new or modified units. Refining is a sophisticated process to make crude oil into a variety of products, including gasoline, heating oil, lubricants, and feedstocks for other industries. Refining equipment and processes involve a certain amount of iterative treatment, in which materials may be processed more than once at a particular location or may be returned to an earlier step in the system for further handling. Only those processes necessary to understand the basic principles are presented. A very general description of the entire process at this particular refinery starts with crude oil being processed in the Crude Unit. Process streams currently flow from CDU #1 to the FCCU, the DHTU, Naphtha Hydrodesulfurization Unit (NHDS), and the Penex. A residual stream becomes asphalt or residual fuel oil. Tulsa Refinery final products are currently classified as gasoline, distillate, residual fuel oil, and asphalt, but there are also intermediate products, such as propane, butane, propylene, and sulfur. After construction is completed, process streams from CDU #2 will flow to Penex, to the NHDS, to the DHTU, to the HCU, and to the DCU. The NHDS stream will then flow to the CCR. Gas oil flows from the CDU#2 and/or the HCU to the FCCU while distillate flows from HCU to product. The FCCU stream will flow to the DHTU, POLY/ALKY, or Scanfiner (SCAN), or to product. The DCU stream will flow to the diolefin splitter, to the POLY/ALKY, to the DHTU, to the HCU, or to coke product. The H2 plant will provide hydrogen to various users at the refinery, including the HCU, whose stream will then flow to the NHDS, the FCCU, to product, and the DHTU. The diolefin splitter stream will flow to the NHDS or to product. The ARU/SWS combinations will flow sour gas to the SRUs. End products of each final unit in the preceding flow strings will be discussed in the lettered sections below. These final products will include gasoline, distillate, fuel oil, asphalt, propane, propylene, butane, sulfur, and coke. Process flows described above are only typical and not inclusive of all possible operating scenarios. These descriptions are not intended to limit the possibility of directing some of the process streams as necessary to run the refinery in an efficient and safe manner.

Note that Emission Unit Groups (EUGs) are based on different criteria from those used to describe process units, so descriptions of the EUGs do not match those of the processing units. For example, EUG #9 in the TVR permit consists of heaters found in three different units.

2


Similarly, although the bulk of all tanks is found in the Product Blending Unit, the storage tanks are divided into EUGs based on roof design and permit status. Also, heater firing rates are based on higher heating values (HHV). Generally speaking, all numbers used in this memorandum will consist of three significant digits, although rounding will occur only after a calculation or series of calculations has been completed.

Some of the construction authorized by Permit No. 98-021-C (M-26) for the Low Sulfur Diesel Project had not been completed at the application submittal date for the HCPE project, but all of the proposed construction is discussed here as if it were completed.

A. Crude Distillation Unit (CDU)Distillation is a thermal process that separates product fractions out of a mix of materials based on differences in vaporization temperatures. The CDU separates crude oil into intermediate products, which are either feedstocks for downstream units or residual products. Heavy crude (also referred to as sour crude), defined at STRC as crude oil with sulfur content greater than 0.5 weight percent, currently represents approximately 10% of all volume processed by CDU #1. The remaining 90% sweet crude at the Tulsa refinery has historically averaged approximately 0.4 weight percent sulfur. Heavy crude is usually run through CDU #1 at approximately 55,000 barrels per day (BPD) and sweet crude is generally run at approximately 65,000 BPD. Further discussion of CDU #1 and ancillary equipment may be found in the memorandum associated with the pending TVR.

Crude oil deliveries are metered, sampled, and tested before processing. Sweet and heavy crudes are currently segregated in storage tanks and are processed in separate batches through CDU #1. Upon completion of CDU #2, most of the crude will be heavy and no distinction will be made between sweet and heavy crude. All crude is de-salted before entering the distillation towers to remove chlorides that would be damaging to piping and vessels. CDU#2 will include equipment similar to that included in CDU #1, including, but not limited to an atmospheric distillation unit (ADU) and 283 MMBTUH heater, a vacuum distillation unit (VDU) and 110 MMBTUH heater, desalters, a steam generation system, and a naphtha splitter. CDU #2 is anticipated to have capacity of 115,000 BPD. Crude flows through the atmospheric tower first, where the lighter ends are removed or distilled. “Atmospheric” simply refers to the fact that the constituents distilled in the ADU are capable of vaporizing at atmospheric pressure. Heavier ends that are not distilled in this tower are then run through the VDU for further separation. Some material is refluxed, meaning that it is taken out of the column and reintroduced at an earlier point to achieve better separation into distinct product fractions. Refluxing is also a method for taking heat out of the tower. It is one of the processes that is used at different points and that constitutes one of the previously mentioned techniques to improve performance and more efficiently process materials in the CDU.

STRC defines seven outputs from CDU #2 in order of increasing molecular weight as follows. Streams 1 - 5 come from the atmospheric tower, while 6 and 7 come from the vacuum tower.

1. Light ends/butane/propane. These streams contain lighter hydrocarbons and are routed to the fuel gas system or to storage.

2. Light straight run naphtha. This stream is mostly gasoline range hydrocarbons and is

3


routed to the Penex.3. Heavy straight run naphtha. This stream is mostly gasoline range hydrocarbons and is

routed to the NHDS Unit.4. Kerosene. This stream is routed to the DHTU.5. Diesel. This stream is routed to the DHTU.6. Gas oils. This stream is routed to the HCU.7. Vacuum residuum. This stream is either processed through the DCU or distributed as

residual fuel oil or asphalt.

The CDU has other responsibilities as described in the TVR memorandum.

B. Fluid Catalytic Cracking Unit (FCCU)The FCCU treats gasoils from the CDU (hot) or gasoils from storage (cold) with heat in the presence of a catalyst. Currently, hot gasoil from sweet crudes is mixed with cold gasoil from heavy crudes, and the situation is reversed when heavy crude is being processed. The FCCU has current capacity estimated at 24,000 BPD and usually processes approximately 20,000 BPD. “Gasoils” are heavier than diesel and lighter than the residual products taken from the CDU. Heavy molecules are broken or “cracked” into lighter molecules that allow the facility to increase the production of liquid fuels. A distillation tower then separates these products into gasoline and diesel components, as well as producing feedstock for the Alkylation (ALKY) and Scanfiner (SCAN) Units (see below).

The method of operation of the FCCU will not be significantly altered by the HCPE project, however some changes will occur. New trays will be installed in the fractionator tower, a new lean oil absorber will be installed, and the B2 heater firing rate is now set at 73.3 MMBTUH. The 150 MMBTUH B2 heater rate described in the memoranda for Permit No. 98-021-TV and in various modifications to that initial TV permit was only an estimate of actual firing rate, so this new firing rate is not a re-rating of the heater, nor is it an attempt to establish a maximum heat input rate. The facility does accept it as an authorized rate and it will be used in calculations concerning PSD significance. STRC will add a scrubbing system to the regenerator vent to achieve emission limits contained in the consent decree mentioned earlier. This activity does not require permitting, but the addition of water vapor to the exhaust may degrade the performance of the COMS. Because STRC is required to monitor opacity, the facility plans to apply for an alternative monitoring plan (AMP), as has been allowed by EPA in similar circumstances. Information concerning the AMP will be submitted when detail design of the scrubbing system is completed. A description of certain FCCU activities, including catalyst handling and regeneration, thermal distillation, heaters, and the wet gas compressor, may be found in the TVR memorandum.

4


Additionally, the FCCU currently has responsibility for the operation of two flares, all pressur-ized spheres, all pressurized “bullet” tanks except for three tanks located at the ALKY Unit, and propylene loading. Currently, the CDU #1, FCCU, ALKY, POLY, and PENEX Units feed Flare #1 and everything else is directed to Flare #2. STRC will continue to operate Flare #1 and Flare #2 as currently permitted, thus providing emergency relief for refinery process units. A third flare, identified as Flare #3, will be constructed to handle only emergency upsets at the facility. All three flare systems will be cross-connected to provide flexibility in dealing with unexpected releases. STRC will install a flare gas recovery system to route gases that have historically been vented to the refinery flare system to the plant fuel gas system. This system will affect all gas that would otherwise flow directly to one of the three flares mentioned above and will also in-clude recovery systems close to individual large units, such as the DCU. Set points will be es-tablished in the recovery system to protect against overpressure. As currently proposed, the low-est setpoint will be on Flare #3, with #1 or #2 at the next highest level. Thus, any emissions that are flared will exhaust through #3 first, with #1 or #2 being activated only in more extreme situa-tions. After processing through the refinery’s amine system, the recovered flare gas will then be available for use as sweetened fuel gas by the various users at the refinery.

C. Unifiner/Penex Unit (PENEX)The PENEX upgrades the octane of light straight run naphtha from the CDU by isomerizing the normal pentanes to isopentanes. The PENEX also saturates benzene, thus reducing the benzene and aromatic levels in gasoline produced by STRC. The normal charge rate to the PENEX has been approximately 6,000 BPD although it has nominal capacity to charge over 8,500 BPD. An extensive description of the process is available in the TVR memorandum. The method of operation of PENEX will not be significantly altered by the HCPE project; however, the Unifiner heater firing rate will increase to 45.9 MMBTUH. The 35.0 MMBTUH Unifiner heater rate described in the memoranda for Permit No. 98-021-TV and in various modifications to that initial TV permit was only an estimate of actual firing rate, so this new firing rate is not a re-rating of the heater, nor is it an attempt to establish a maximum heat input rate. The facility does accept it as an authorized rate and it will be used in calculations concerning PSD significance.

D. Continuous Catalytic Reforming Unit (CCR)The CCR upgrades the octane of heavy straight run naphtha from the CDU (through the NHDS) by dehydrogenating the hydrocarbons, resulting in the production of high octane materials such as aromatics. These high octane “blend stocks” are blended directly into gasoline. A more complete description of this unit may be found in the TVR memorandum. The CCR will continue to function as described in that memo, but heavy coker naphtha from the HCU will now be added to its input, after it is treated at the NHDS. CCR heater rates will be adjusted from those listed in earlier permits to reflect anticipated firing rates needed upon completion of the HCPE project. These adjustments may be considered “as built” adjustments as suggested in the two preceding sections, but these are now established as authorized heat rates for permitting purposes. Changes for these heaters are identified in the following table.

Heater Heat Input (MMBTUH)Previous New

CCR Charge Heater (10H-101) 120 67.1CCR #1 Interheater (10H-113) 141.8 121.6

5


CCR #2 Interheater-1(10H-102) 101 123.3CCR #2 Interheater-2 (10H-103) 25.0 30.5CCR Stabilizer Reboiler (10H-104) 85.0 64.5

E. Naphtha Hydrodesulfurizer Unit (NHDS)The NHDS removes sulfur from the CCR charge (heavy naphtha), and has a capacity of 22,000 BPD. A more complete description of this unit may be found in the TVR memorandum. Operation of the NHDS will not be altered by the HCPE project, except that its charge will now be supplemented by the heavy fraction of coker naphtha. Coker naphtha will be processed by the diolefin splitter, with the light fraction going to product.

F. Distillate Hydrotreating Unit (DHTU)The DHTU is capable of processing approximately 24,000 barrels per day (BPD). The DHTU currently removes sulfur from diesel blend stocks. When the HCPE project is completed, the DHTU will process distillate from CDU #2, light cycle oil (LCO) from FCCU, and coker gasoil. Although the basic description of this unit presented in the TVR memorandum is unchanged, some modifications must be made to the DHTU so that it may process the light coker gasoil stream. Upgrades and modifications include a new #1 reactor, additional heat exchange capability, a new recycle compressor, and upgrade of the charge heater to low-NOX burners. The recycle compressor is, and will continue to be, in hydrogen service.

G. Alkylation Unit (ALKY)Alkylation is a process that creates large molecules by reacting two shorter molecules in the presence of a catalyst. In this case, the alkylate produced is typically high-octane material necessary for blend stock. Debutanizer net overhead from the FCCU is rich in butenes and serves as current ALKY feedstock. The HCPE project will add olefins from the DCU as a part of the feedstock. Coker olefins will be pre-treated by POLY and then pass through the debutanizer (C3/C4 splitter), as is the case with light ends from the FCCU. The product stream generated at the splitter is propylene, which is a final product. Further information and description of this unit is available in the TVR memorandum. This unit has been operating under a production limit of 5,500 BPD, imposed under Permit No. 98-021-C. That permit involved the replacement of certain vessels at POLY and required consideration of the applicability of PSD. Because the potential increases were related to increased throughput, STRC accepted an alkylate production limit of 5,500 barrels per day as a demonstration that PSD did not apply. The applicant now requests this limit be released and offers justification presented here in the EUG 8 discussion of Section III (Emissions), with further comments in the discussions of OAC 252:100-8 of Section VI (Oklahoma Rules) and 40 CFR Part 52 in Section VII (Federal Regulations).

H. Poly Pretreat Unit (POLY)This area of the refinery was originally a polymerization unit, hence the name POLY. A description of the unit is available in the TVR memorandum. The HCPE project will cause no changes in this unit.

I. Scanfiner (SCAN)

6


The SCAN process takes all or a portion of naphtha (often referred to as ‘cat naphtha’ or ‘cat gasoline’) from the FCCU and removes the sulfur. A description of the unit and its processes is available in the TVR memorandum. The HCPE project will not affect the operation of this unit.

J. Sulfur Recovery UnitsThe existing SRUs recover sulfur from acid gas streams and the sour water stripper overhead using the Claus process, and store it in elemental form for sale. One third of the H 2S is oxidized to form SO2 and the SO2 is reacted with the remaining H2S in the presence of an alumina catalyst to form elemental sulfur and water vapor. The liquid sulfur is stored in a pit for shipping by rail or truck. The reaction does not achieve total removal of sulfur (with an approximate 95% efficiency), so the tail gas is scrubbed by Tail Gas Treating Units (TGTU) to recover any remaining sulfur oxides formed before they are released from the stack. These units incinerate remaining H2S to SO2, which is then removed by a following caustic scrubber. Scrubber products are routed to the wastewater treatment system. Tail gas concentration of SO2 is maintained below 250 ppm. Continuous emission monitors (CEMs) are used on existing SRU/TGTUs 1 and 2 to demonstrate compliance. The design rate of existing SRU #1 is 15 long tons per day (LTPD) and the design rate of existing SRU #2 is 25 LTPD. SRU #1 will be removed from service upon completion of the HCPE project.

Feed for the existing units is supplied by ARU #1 and ARU #2 (see Section S below). An existing Sour Water Stripper (SWS #1) is also associated with this complex of units. SWS #1 takes sour water from various units and removes ammonia and H2S. Offgas from SWS #1 is sent to SRU #2. As currently operated, if SRU #2 is unavailable for some reason, SWS will be placed on fresh water feed or shut down and sour water stored in tanks. Upon return to service of SRU #2, any accumulated sour water will be processed and the offgas sent to SRU #2.

Acid gas from the proposed ARU#3 and ARU#4 will be routed to proposed SRU/TGTUs #3, #4, and #5. Each of the new SRU/TGTUs will have a nominal capacity of 150 LTPD. Each includes the following major equipment, similar to the design of the existing units, but with greater sulfur recovery efficiency, due to the addition of Super Claus systems.

Claus Unit Super Claus system Thermal Oxidizer Steam Generation System Tail Gas Treatment Unit

Each Claus unit includes a thermal reactor and a 2-stage “traditional” catalyst bed system followed by a single-stage high efficiency Super Claus catalyst bed system. Tail gas from each Claus unit will be processed through an 18.0 MMBTUH thermal oxidizer to convert the remaining H2S to SO2. Heat generated by the thermal oxidizer is recovered in a steam generation system. The incinerated tail gas is then processed through its associated TGTU. Each TGTU utilizes water-based scrubbing technology to absorb the remaining SO2 in the incinerated tail gas stream. The SO2 is absorbed into the scrubber caustic/water solution and neutralized to sulfate salts. The scrubber effluent is discharged to the WWTP.

7


The coker project will result in an increase in the generation of sour water. This sour water will be processed through new SWS#2 and/or SWS#3 to strip the sulfides and ammonia species out of process wastewater. The overhead gas produced from SWS#2 and SWS#3 will be processed through SRU#3, SRU#4 and/or SRU#5.

The new sulfur complex and existing sulfur complex network will be designed to allow the processing of rich amine streams generated throughout the refinery at any of the SRU trains. For example, when operational conditions dictate only two SRU trains are needed to operate, STRC will have the option to route the majority of the sour gas generated at the refinery through these units. This will enable the other two SRU trains to be run at reduced load, idled or shut down for maintenance. This operational philosophy and redundancy of acid gas processing capability will enable the refinery to better manage operations and enhance environmental compliance during periods of process unit upsets.The same operational concept is being designed into the SWS system such that sour wastewater may be processed through SWS#1 (existing), SWS#2 and/or SWS#3. This operational redundancy will enable the refinery to better manage operations and maintain environmental controls during periods of changes in operation and unit shutdown.

Sulfur from the SRUs is routed to a sulfur pit for temporary storage. Sulfur from the pit is pumped into tank trucks or rail cars for shipment off site. Vapors from the pit and from the sulfur loading operation are routed to the Claus units for control.

K. Product Blending (PB)Product Blending is responsible for tankage at STRC. The majority of the tanks are fixed roof tanks storing materials of low volatility. The PB department receives crude oil and ships out gasoline and diesel products by pipeline. The PB department is also responsible for the waste-water treatment facility and the asphalt loading racks. There is also a diesel railcar loading rack and a gasoil truck loading rack.

The HCPE project will add six new tanks, including one tank each for heavy straight run, black oil, biosolids, sludge, sour water, and an LPG sphere. These may not all be assigned to PB.

L. Boiler House (BOHO)The BOHO is responsible for steam production for the refinery. The BOHO is also responsible for the other utility systems such as plant air, instrument air, and nitrogen. There are four boilers at the BOHO, each capable of producing over 100,000 pounds per hour of 250 psig steam. These boilers primarily burn sweet plant fuel gas, but each is also capable of burning liquid fuel, which occurs only during gas curtailment or burner testing. Generally, a different boiler is shut down every six months for maintenance.

The HCPE project adds several units that are capable of producing steam. STRC has provided a steam balance showing that these units will provide as much or more steam as the amount required by the HCPE project. Thus, demand on the BOHO will remain flat or decrease.

M. Sales TerminalThe sales terminal is responsible for the shipment of gasoline, diesel, and propane via tank

8


trucks. Crude oil enters the refinery at a metering station located at the terminal. A description of the unit and its processes is available in the TVR memorandum. The HCPE project will not affect the operation of this unit. Although HCPE will increase the production of items shipped by the terminal, these sales are typically local, so increased throughput is possible only if local demand increases. Excess production will leave STRC by pipeline.

9


N. Wastewater Treatment Plant (WWTP)A description found in the TVR memorandum is essentially sound. The only changes contemplated under HCPE are replacing the existing open API separators with a new oil-water separator tank for primary treatment in addition to the existing tanks and addition of a dissolved nitrogen flotation (DNF) system for secondary treatment. VOC emissions from the DNF system will be controlled by a Regenerative Thermal Oxidizer (RTO) system. The existing uncontrolled API separators will be permanently removed from service. A portion of the wastewater generated at the refinery will be sent to the City of Tulsa Public Owned Treatment Works (POTW) for treatment. By using the POTW, the wastewater flow rate to the WWTP will remain at or below current levels. Biosolids generated in the WWTP may be sent to the coker unit for processing.

O. Miscellaneous PointsMiscellaneous equipment leaks or fugitive emissions occur from all piping components throughout the refinery. Components added by the HCPE project will not alter the applicability of any of the rules or regulations affecting such emission points. This topic, as well as the refinery fuel gas (RFG) system, the hydrocarbon recovery system, and various cooling towers, are described in the TVR memorandum and their treatment will not be altered by the HCPE project.

New equipment to be installed under the HCPE project includes a distillate fuel offloading rack, an instrument air system, and emergency systems.

The new offloading station will allow distillate fuel oils produced at facilities other than STRC to be processed at the refinery. Because these materials will be unloaded from tank trucks directly into storage tanks, only fugitive emissions will be associated with this unit.

An instrument air system will be installed to provide instrument air for the various users at the refinery. The instrument air system will use electrical drivers and steam turbine drivers and will not have any associated emission points or fugitive emissions. STRC will install two new instrument / plant air compressors in conjunction with the HCPE Project. One compressor will have an electric motor driver and the other compressor will have a steam turbine driver. The steam turbine will consume steam generated from the new process units associated with the HCPE Project.

New emergency firewater pumps and an electrical generator will be installed for emergency purposes. It is anticipated these systems will operate less than 500 hrs/yr.

P. Delayed Coker Unit (DCU)The DCU will use the “delayed coking” process to thermally crack vacuum residuum into lighter boiling range intermediate streams such as refinery fuel gas, naphtha and gasoils. The nominal capacity of the DCU is approximately 30,000 barrels per day (BPD) and includes the following major equipment.

Coker heater (4 heater cells) Coke drums (2 drums)

10


Coker fractionator Coke cutting/conveying/loading system Steam generation system Biosolids tank Diolefin Reactor / Splitter Sludge tank Coker Cooling Tower

Vacuum residuum from the existing CDU #1 is sold as asphalt or roofing flux. As noted in the CDU #2 discussion in Section A earlier, this material will now be processed by the DCU. Vacuum residuum is first fed to the coker fractionator to remove as many lighter boiling components as possible. Bottoms from the fractionator are heated to approximately 900F by the coker heater. Prior to entering the coker heater, steam or boiler feed water is combined with the fractionator bottoms to maintain a high tube-side velocity that minimizes the deposition of coke in the heater tubes. The residuum stream is then introduced into a coke drum where adequate residence time enables coke to form within the coke drum. The vaporized, non-coke intermediates from the coke drum are routed back to the coker fractionator enabling the distillation of the coker intermediate streams.

The coker fractionator distills the unit feed and coking reaction intermediates into fuel gas, coker naphtha, coker diesel, light and heavy coker gas oils, and bottoms. Coker fuel gas containing olefins is pre-treated by POLY, and then routed through the C3/C4 splitter. Coker naphtha is routed to the diolefin splitter, with light naphtha to product and heavy naphtha to the NDHS Unit for hydrotreating. Coker diesel is routed to the DHTU for hydrotreating. Coker gasoils are sent to the HCU. The bottoms stream is recycled to extinction via the Coker Heater and coke drums.

The proposed DCU employs two coke drums in parallel, each of which is controllably switched between on-line and off-line status. As one coke drum is being filled, the other drum is off-line for hydraulic cutting to remove the solid coke. Prior to removal of the solid coke, steam is introduced into the off-line coke drum to remove hydrocarbons remaining in the drum. The vent from this steam quench is routed to the coker fractionator for processing. A water quench is then used to cool the coke in the drum. This water is then processed through the coker water treatment system and recycled for use as quench/cutting water. Prior to opening the coke drum for hydraulic drilling, the gases remaining in the coke drum are vented to the quench tower and then to the coker gas recovery system, which includes a compressor system that routes the gases to the RFG system for further processing.

When the coke drum is safely evacuated, the drum is opened and a hydraulic cutting system is used to cut coke from the drum. The coke then falls through the bottom of the coke drum and into the coke pit/pad. Cut coke is lifted by bridge crane to a grizzly hopper and coke crusher for size reduction. From the crusher, the coke is transferred via an enclosed conveyer system to a storage silo. From the storage silo the coke is directly loaded into trucks for transportation offsite. The moisture remaining on the coke from the cutting operation reduces particulate emissions from the bridge crane, grizzly hopper and coke crusher operations. Particulate emissions from the enclosed conveyer system, storage silo and truck loadout system are controlled by a dust collection and control system.

11


In the event the coke handling system is offline for maintenance, the coke may be loaded directly into trucks by the bridge crane or front-end loader for transfer off-site. Water from the coke pad is pumped to a clarifier/water storage tank for reuse by the coke cutting/quenching system.

RCRA regulations at 40 CFR 261.4(a)(12)(i) & (ii) allow the processing of “hazardous oil-bearing secondary materials” as coker feed. The coker unit to be installed at the refinery has the capability of processing these types of materials.A new cooling tower will be constructed to provide cooling for process water used by the new equipment.

Q. Hydrocracking Unit (HCU)The HCU is designed to crack virgin gasoil from CDU#2, light cycle oil from the FCCU and coker gas oil, in the presence of a catalyst, into gasoline and distillate fuel oil range blendstocks. A hydrotreating reactor in the unit removes sulfur from the feed streams. The HCU catalyst bed is fixed and requires periodic regeneration that will be performed during unit turnaround. Major equipment items include a 92.0 MMBTUH reactor charge heater, a hydrotreator reactor, an HCU reactor, and an HCU fractionator and 86.0 MMBTUH fractionator feed heater.

A new cooling tower will be constructed to provide cooling for process water used by the new equipment.

R. Hydrogen Plant (H2 Plant)The H2 Plant is designed to produce approximately 82 MMSCFD of hydrogen for use by various process units at the refinery. Purchased natural gas and steam are fed to the radiant coils of the reactor where the reforming reaction produces H2, CO and CO2. Hydrogen is separated from the reactor discharge stream in the pressure swing adsorber (PSA) unit for use by other refinery process units. The PSA purge gas stream from the separation step consists of unreacted methane, CO and CO2. The PSA purge gas, RFG, and purchased natural gas are routed to the furnace to provide heat input for heating the radiant coils. The products of combustion exiting the reactor are used to indirectly produce steam prior to discharge to the atmosphere. Major equipment items at the H2 Plant include the H2 reactor and 604 MMBTUH furnace, the H2

separation system (PSA), and the steam generation system.

S. Amine SystemThe refinery currently has an amine system that removes H2S from various gas and liquid hydrocarbon streams. There are six amine treaters (or “contactors”) that contact the different streams with lean amine, where “lean” means that the amine has a low concentration of H2S. The lean amine absorbs the H2S, making it into a “rich,” or high-concentration, stream. The ARU regenerates the amine solution by boiling it, producing lean amine to return to the contactors and hydrogen sulfide to feed the SRU. ARU #1 processes the sour amine solution from the amine absorber. Acid gas from the ARU is vented to the sulfur recovery units (SRU#1 and/or SRU#2).

Under the HCPE project, sour overhead vapor streams from various process units at the refinery will be routed to a new amine system for sweetening. The new amine system will include various amine contactors located throughout the refinery, amine regeneration unit #3 (ARU#3),

12


amine regeneration unit #4 (ARU#4) and rich and lean amine tanks. The sweetened refinery fuel gas from the contactors will be available for use by the refinery’s fired sources. This new system will be independent from the existing system, although clean amine will be on a common system.

T. MiscellanyOther environmental permits include RCRA Part B (EPA No. 3572040) for the Walnut Grove Land Treatment Unit, RCRA Post Closure for the Flare Area Treatment Unit (EPA No. 990750960-PC) and NPDES wastewater discharge (EPA No. OK0001309/DEQ No. I72001630). The HCPE project is expected to affect the NPDES permit.

III. EQUIPMENT

The following tabulation of Emission Unit Groups (EUGs) follows the design of the pending TVR memorandum. EUGs not affected by the HCPE project are listed by name only, with no details as to members of the group or discussions about the criteria determining membership. EUGs that the TVR memorandum shows as empty are not listed.

EUG 1 MACT CC Group 1 Storage Vessels - Internal Floating Roof (IFR)

The “old” Tank #7 will be removed from service, and there is no change in applicability for this EUG. Since Tank 7 was not shown in the TV renewal listing, the listing is not presented here.

EUG 2 MACT CC Group 1 Storage Vessels - External Floating Roof (EFR)

EUG 3 MACT CC Group 2 Storage Vessels - Fixed Roof (FR)

These storage vessels are regulated under 40 CFR 63 Subpart CC (MACT CC) Group 2 Storage Vessels and are limited to the existing equipment as it is. Due to the overlap provisions of MACT CC (§63.640(n)), the list of 45 tanks in the TVR memorandum and permit includes any Group 2 storage vessels that are also regulated under NSPS Subparts K or Ka but that are not required to meet the K/Ka control standards, as they must meet the MACT requirements per §63.640(n)(7). Storage vessels required to meet control requirements under NSPS Subparts K and Ka are required to comply only with those subparts, per §63.640(n)(6), and are not included in this list. The biosolids, sludge, and black oil tanks are added to this EUG. Tanks #106, 121, 127, 400, and 401 will be removed from service as part of the HCPE project.

Tank No. Point ID

Year Built Height Diameter Nominal

Capacity9 6242 2005 48' 150' 151,10010 6180 1910 30' 96' 37,50011 6181 1910 30' 96' 37,50015 6244 1949 48' 140' 130,00016 6245 2003 48' 150' 151,10017 6183 1910 30' 96' 37,50019 6247 1922 30' 52' 11,300

13


Tank No. Point ID


Capacity34 6252 1922 30' 53' 11,70036 6253 1922 30' 53' 11,50039 6254 1922 35' 28' 3,29040 6185 1923 40' 32' 6,10041 6248 1922 35' 29' 3,90063 TBD 1973 18' 20' 1,000102 6189 1907 30' 96' 37,500103 6190 1907 30' 96' 37,500104 6255 1907 30' 96' 37,5001062 6256 1907 30' 96' 37,500107 6257 1949 48' 140' 131,000108 6191 1907 30' 96' 37,500109 6192 1907 30' 96' 37,500110 6193 1907 30' 96' 37,500111 6194 1907 30' 96' 37,500112 6195 1907 30' 96' 37,500115a TBD 2007 48' 150' 150,000115b TBD 2007 48' 150' 150,000116 6199 1907 30' 96' 37,500117 6200 1907 35' 115' 63,500118 6201 1907 30' 96' 37,500119 6202 1907 30' 96' 37,500122 6203 1907 30' 96' 37,500123 6260 1907 30' 96' 37,500124 6261 1907 30' 96' 37,500125 6262 1907 30' 96' 37,500126 6263 1907 30' 96' 37,5001272 6264 1907 30' 96' 37,500129 6204 1949 36' 35' 6,100130 6205 1949 36' 35' 6,100131 6265 1907 30' 96' 37,500132 6206 1907 30' 96' 37,500

4001,2 17035 1922 30' 24' 2,4004011,2 17036 1920 20' 25' 1,700451 6229 1930 30' 53' 11,700452 6230 1930 30' 53' 11,700603 23132 1951 30' 20' 1,617

TBD (Sludge) TBD Proposed 30' 16' 1,000TBD (Biosolids) TBD Proposed 30' 16' 1,000TBD (Black oil) TBD Proposed 47' 175' 197,000

1 Tank is also listed in wastewater EUG 4.2 To be removed from service in HCPE project.

14


Tanks 20, 21, 22, 23, 32, 35, 45, and 46 have been idle and are scheduled for demolition in 2007. Tanks 360, 403, 440, and 443 have been idle for a long time and would require permitting to be restored to active service.

EUG 4 MACT CC Wastewater Tanks

Tanks #400 and 401 will be removed from service as part of the HCPE project, and the HCPE project causes no change in applicability for this EUG. These storage vessels are regulated under 40 CFR 63 Subpart CC (MACT CC) as wastewater management units and are limited to the existing equipment as it is. Due to the overlap provisions of MACT CC, the requirements of 40 CFR 61 Subpart FF (BWON), and 40 CFR 60 Subpart QQQ (NSPS QQQ), these vessels are required to comply with 40 CFR 60 Subpart Kb to meet the applicable standards under MACT CC, BWON, and NSPS QQQ.

Tank No.

Point ID

Year Built Height Diameter

Nominal Capacity (barrels)

13 6243 1976 40' 116' 75,25018* 6246 1910 30' 96' 37,50052 22638 1972 36' 40' 7,50056 36193 1992 16' 25' 1,40057 36193 1992 16' 25' 1,40067 23134 1992 12' 10' 165140 23134 1971 16' 36' 2,900369 23134 1960 23' 12' 480370 23134 1967 23' 12' 480

* Also listed in EUG 1

EUG 5 NSPS Subpart Kb Storage Vessels - Internal Floating Roof (IFR)

These storage vessels are regulated under 40 CFR Part 60, NSPS Subpart Kb and are limited to the existing equipment as it is. Due to the overlap provisions of MACT CC, these vessels are required to comply only with NSPS Kb. The HCPE project will add a new tank for storage of SWS feed and a new tank for storage of heavy straight run naphtha.

Tank No. Point ID


Capacity4 23129 2003 48' 134' 120,600

7 (naphtha) TBD Proposed 47' 175' 200,00031 6250 1998 48' 48' 15,000472 TBD 2007 48' 150' 140,000605 6278 1951* 32' 30' 3,400

TBD (SWS) TBD Proposed 48' 150' 151,000*Built as a fixed roof in 1951, converted to IFR in 1987, subject to Kb 1992.

15


EUG 6 Catalytic Reforming Unit (CCR)

EUG 7 MACT CC Group 2 Storage Vessels External Floating Roof (EFR) Tank

EUG 8 Fired Boilers

Boilers 1 and 2 share the East Stack and Boilers 3 and 4 share the West Stack. Both stacks are 7 in diameter and exhaust at 71 above grade. Exit temperature is estimated at 350 F. Listed heat capacities are based on boilerplate capacity of 170,000 pounds/hour of 350 psi, 500F steam. There are no emission limits applied to this EUG under Title V but it is limited to the existing equipment as it is. These sources were to be regulated under 40 CFR 63 Subpart DDDDD (MACT DDDDD), however, that rule has been vacated. These boilers will no longer burn liquid fuel, except during periods of natural gas curtailment, test runs, or operator training.

ID Point ID Name/Model Heat Capacity Construction Date1 6150 Babcock & Wilcox FH 26 233 MMBTUH 19502 6150 Babcock & Wilcox FH 26 233 MMBTUH 19503 6151 Babcock & Wilcox FH 26 233 MMBTUH 19504 6151 Babcock & Wilcox FH 26 233 MMBTUH 1955

EUG 9 Fuel-Burning Equipment

Various process heaters share stacks. Stack parameters follow. STRC has accepted the NSPS Subpart J SO2 limit of 0.1 gr/dscf for all heaters at the facility. Further, two heaters have accepted heat input limits. Note that CDU #1 will be removed from service upon completion of the HCPE project.

Stack Height (ft)

Diameter (Ft) Temp (F) Flow

(ACFM)CDU #1 175 11.5 500/800 67,000FCCU Air Heater (B-1) 191 5 ** **Unifiner Heater (H-1) 50 3.8 950 4,500

** This heater operates only upon recharging the catalyst, for approximately four or five days out of a four-year period. Its exhaust is handled by existing stacks, so individual data for these parameters are unknown.

The following table shows available information for all heaters in this EUG. Except as noted in the table’s footnotes, the heat capacity shown is based on Tulsa Refinery estimates provided during a June 1998 DEQ facility inspection. These capacities may not accurately represent

16


design capacities or maximum heat rates, nor do they necessarily represent applicant’s designation of heater duty.

17


Source Point ID Manufacturer MMBTUH (HHV)

Heater Date

CDU #1 Atmospheric Heater4 6155 Foster-Wheeler 200 1949CDU #1 Vacuum Heater4 6155 Foster-Wheeler 90 1949CRU Splitter Reboiler2 6162 SELAS 100 1972

FCCU Air Heater (B-1)1 6159 M W Kellogg 38.4 1949Unifiner Heater (H-1) 6167 Refinery Engr 45.93 1955

(1) vents to FCCU regenerator stack.(2) to be removed from service upon CCR start-up.(3) heat rating accepted as a maximum or design rate under HCPE project.(4) will be removed from service as part of the HCPE project

EUG 10 Sulfur Recovery Units

SRU #1 was constructed in 1972 and SRU #2 became operational in June 2006. Each unit has a tail gas treating unit (TGTU) to scrub its exhaust. The TGTU #1 incinerator is rated at 5.6 MMBTUH and the TGTU #2 incinerator is rated at 12.1 MMBTUH. Scrubbed tail gas exhausts TGTU #1 at 3,600 ACFM and 340F through a 2 diameter stack at 200 above grade. Scrubbed tail gas exhausts TGTU #2 at 6,450 ACFM at 780F through a 2.5 diameter stack at 101 above grade. SRU/TGTU #1 is Point ID 6152, and SRU/TGTU #2 is Point ID 36200.

The incinerators for new units 3, 4, and 5 are rated at 18.0 MMBTUH each. Other equipment information, such as stack heights, is not yet available.

EUG 11 FCCU

As discussed in Section II B above, certain changes are to be made at the FCCU. A scrubber to control SO2 and PM emissions and a Selective Catalytic Reduction (SCR) system to reduce NOX

emissions are to be installed. These changes will not alter the process, and details as to stack dimensions are not yet available.

EUG 12 Flares

Each existing flare is steam assisted with three shielded pilots, flame front generators, and electronic ignitors. Pilot flame presence is detected with either infrared cameras or thermocouples in the pilots. Throughputs are highly variable and exhaust temperatures are approximately 1,500F. The current #1 flare tip was designed in 1968 for 65,000 lb/hr of 42 average molecular weight gas. The #2 flare tip was designed for smokeless operation at 120,000 lb/hr of 87 average molecular weight gas and 42,000 lb/hr of steam and has a maximum capacity of 352,600 lb/hr of 67.8 average molecular weight gas. Both flare tips have a diameter of 5. There are no emission limits applied to this EUG under Title V but it is limited to the existing equipment as it is. Sources in other EUGs under various regulations utilize the flares as air pollution control devices. The flares are currently identified as Point ID 6154.

Details of Flare #3 are not available, but it is designed to provide facility-wide control for emergency releases. It has a pilot rated at 0.05 MMBTUH.

18


As discussed in Section II B (FCCU), the flare gas recovery system required by the Consent Decree will affect flow to all three flares.

Flare Make/Model Height (ft) Date#1 Zink/STF-SA-18 230 1949#2 Zink/STF-SA-36-C 250 1972#3 TBD TBD Proposed

EUG 14 Low Vapor Pressure Loading Operations

There are several loading racks that handle materials that are not treated as VOCs under OAC Subchapters 37 and 39. All of these racks were constructed in 1949. These units are “grandfathered” (constructed prior to any applicable rule). There are no emission limits or compliance obligations applied to this EUG under Title V but it is limited to the existing equipment as it is. A new distillate rack is to be constructed under the HCPE project, however it will be an offloading facility, accepting truck deliveries to storage tanks. All potential emissions will be fugitives accounted for in EUG 16.

Rack Point ID Material CapacityBlack Oil Railcar 6169 Asphalt, roofing flux, vacuum tower bottoms 12 carsBlack Oil Truck 6170 Asphalt, roofing flux, vacuum tower bottoms 3 trucksDiesel Railcar 14455 #2 diesel 8 carsGasoil Truck Idle Gasoils 2 trucks

EUG 15 High Vapor Pressure Loading Operations

EUG 16 Fugitive Emissions

Equipment leaks from the entire refinery, including but not limited to the process units, storage tanks, and the terminal, are included in this Group. There are no annual emission limits applied to this EUG under Title V but it is limited to the existing equipment as it is. VOC concentrations in ppm are limited by various rules and regulations, including MACT CC and OAC 252:100-39-15. Aggregated emission points are identified as Point ID 6172. The HCPE project is estimated to bring the facility total close to 30,000 fugitive emissions sources.

EUG 17 Wastewater System

The existing wastewater system consists of several different sewer systems and the wastewater treatment plant, as described in Part N of Section II (Facility Description) above. Applicability of 40 CFR 61 Subpart FF (BWON), 40 CFR 63 Subpart CC (MACT CC), and 40 CFR 60 Subpart QQQ (NSPS QQQ), as well as the overlap provisions of 40 CFR 63.640(o), are discussed in the TVR memorandum. The June 11, 2007, EPA Applicability Determination (AD) issued to BP Products North America and signed by George Czerniak is also addressed in the TVR memo. Additions to the systems under HCPE will be identified in the application for

19


modified operating permit and will be subject to NSPS Subpart QQQ or NESHAP Subpart FF (through MACT CC) as appropriate.

EUG 18 Hydrocarbon Recovery System

EUG 19 Cooling Towers

Cooling towers are considered to be trivial sources for Title V purposes, so the following table is shown only for completeness.

Number Point ID Purpose Date3 25053 Cooling water for the FCCU 19493a 25054 Cooling water for SCAN 2003

4 and 5 25055 Cooling water for the CDU 19497 25056 Cooling water for the ALKY, POLY & ISOM 2007*8 25057 Cooling water for the OIF 1972

TBD TBD Cooling water for the DCU ProposedTBD TBD Cooling water for the HCU Proposed

* Replaced tower built in 1949.

EUG 20 NSPS Kb Tanks (EFR) - MACT CC Group 1 Wastewater

Proposed new tank 478 will be used as an oil-water separator that will be subject to 40 CFR 61 Subpart FF (Benzene Waste Operations). Facilities in compliance with FF are considered to be in compliance with the Alternative Standards for Storage Tanks of 40 CFR 61.351 and 40 CFR Subpart Kb. Thus, tanks in this EUG may be used in MACT CC Group 1 wastewater service.

Tank No.

Point ID


Capacity478 TBD Proposed 48' 106' 73,000

EUG 21 Pressurized Spheres

EUG 22 Pressurized Bullet Tanks

EUG 25 New Fuel-Burning Equipment with Heat Input < 100 MMBTUH

This EUG contains new fuel-burning equipment with heat input less than 100 MMBTUH. These sources are all regulated under NSPS J and would have been subject to MACT DDDDD, which has been vacated. See further discussion in Section VI (Federal Regulations).

20


Source Point ID Manufacturer MMBTUH(HHV)

Heater Date

NOx lb/MMBTU(HHV)

Scanfiner Charge Heater (12H-101) 23133 Tulsa Heaters,

Inc 25.2 2004 0.07

NHDS Charge Heater(02H-001) 36580 Tulsa Heaters,

Inc 39.0 2006 0.05

NHDS Stripper Reboiler (02H-002) 36584 Tulsa Heaters,

Inc 44.2 2006 0.05

HCU Reactor Charge Heater TBD Optimized Process

Furnaces 92.0 Proposed 0.035

HCU Fractionator Feed Heater TBD Optimized Process

Furnaces 86.0 Proposed 0.035

EUG 26 New Fuel-Burning Equipment with Heat Input ≥ 100 MMBTUH

These sources are all regulated under NSPS J and would have been subject to MACT DDDDD, which has been vacated. See further discussion in Section VI (Federal Regulations). The CCR Interheater maximum or design heat input has been changed from that shown in the TVR memorandum.

Source Point ID Manufacturer MMBTUH

(HHV)Heater Date

NOx lb/MMBTU

(HHV)CCR #1 Interheater (10H-113) TBD Tulsa Heaters,

Inc 121.6 2005 0.05

DCU Coker Heater TBD Foster Wheeler 221.0 Proposed 0.075H2 Plant Heater TBD Technip 604.0 Proposed 0.045ADU #2 Heater TBD TBD 283.0 Proposed 0.035VDU #2 Heater TBD TBD 110.0 Proposed 0.035

EUG 27 Existing Fuel-Burning Equipment That Accepted NO X Limits

Stack Height (ft)

Diameter (Ft)

Temp (F)

Flow (ACFM)

DHTU Reactor Charge Heater (1H-101) 140 4.8 550/620 52,000FCCU Charge Heater (B-2) 151 5.8 665 25,000CCR Stabilizer Reboiler (10H-104) 124 4.5 500 22,000CCR Charge Heater (10H-101), #2 Interheater-1 (10H-102), #2 Interheater-2 (10H-103) 124 5.8 550 52,000

The following list shows available information for heaters in this EUG.

21


Source Point ID

Manu-facturer

MMBTUH (HHV)

Heater Date

NOx lb/MMBTU(HHV)

DHTU Reactor Charge Heater (1H-101) 6157 Foster-

Wheeler 55.0 1972 0.035

FCCU Charge Heater (B-2) 6158 M W

Kellog 73.33 1949 0.040

CCR Charge Heater (10H-101)1 6163 SELAS 67.13 19722 0.050

CCR #2 Interheater-1 (10H-102)1 6163 SELAS 123.33 1972 0.035

CCR #2 Interheater-2 (10H-103)1 6163 SELAS 30.53 1972 0.035

CCR Stabilizer Reboiler (10H-104)1 TBD SELAS 64.53 19722 0.050

(1) CCR Heaters part of Permit 98-021-C (M-26) was to be placed in service in 2007.(2) low-NOX burners installed in 2005.(3) heat rating accepted as a maximum or design rate under HCPE project.

EUG 28 Regenerative Thermal Oxidizer

The Dissolved Nitrogen Flotation (DNF) system will be controlled by a Regenerative Thermal Oxidizer (RTO) designed to achieve a 97.7% VOC destruction efficiency.

EUG Plantwide

This EUG is established to cover all rules or regulations that apply to the facility as a whole.

IV. EMISSIONS

Emissions are not shown for those EUGs that are unchanged under the HCPE project. Emissions for equipment to be removed from service and for the EUG in which any specific item resides will not generally be shown in Section IV, but will be addressed in the discussion of PSD significance. Emissions and calculations as necessary will be shown for new equipment items and for items accepting new limits under HCPE.


Tanks 4.0.9d was used to calculate emissions for the new sludge tank and for the new biosolids tank. Both models assumed kerosene, with average vapor pressure 0.011 psia and 24 turnovers per year. Results showed slightly more than 47 lbs/year of VOC emissions for each tank. Tanks 4.0.9d was also used to calculate emissions from the black oil tank, assuming an average vapor pressure of 0.0383 psia and a single turnover per year. This calculation yielded 3.80 TPY of VOC emissions.

22


Tank VOC emissionsSludge 47.4 lbs/yearBiosolids 47.4 lbs/yearBlack oil 7,607.3 lbs/yearTotal 3.85 TPY

EUG 5 NSPS Subpart Kb Storage Vessels – Internal Floating Roof (IFR)

VOC emissions for the new naphtha tank and for Tank 472 are calculated using version 4.0.9d of EPA’s TANKS program. VOC emissions for the new SWS feed tank are calculated using the equations and methodology of Section 7-1.3.2 of AP-42 (11/06). Emissions for the other three tanks are taken from the emission inventory data provided with the TVR application. The two new tanks account for an additional 16.0 TPY of VOC emissions.

Tank # Contents Turnovers TPY4 SCAN feed 8.9 2.387 Heavy naphtha 1.0 12.0

TBD Sour water feed 33 4.0131 Slop oil 6.0 1.01472 Gasoline 136 5.97605 Gasoline 31.8 1.73

Total 27.1

EUG 8 Fired Boilers

No physical changes are planned for the BOHO, but the facility has agreed to use only gaseous fuel, except during periods of natural gas curtailment, test runs, or operator training. Because this action is taken under the Civil Action, contemporaneous decreases in SO2 emissions cannot be considered for purposes of PSD. However, emissions of particulate matter are expected to decrease due to this action and STRC is not proscribed from using any decrease in this pollutant for netting analysis (see Section V). The following table is presented only for completeness, and does not alter previous calculations performed for fuel gas combustion at the BOHO. Calculations assume all four units are operated continuously at rated capacity of 233 MMBTUH each. Natural gas emission factors are taken from AP-42 (3/98) Tables 1.4-1 and 2, assuming 1,020 BTU/CF, except that SO2 factors are taken from analysis of the sulfur content of RFG at the boilers.

Pollutant Lb/MMCF Each Boiler All FourLb/hr TPY TPY

NOX 280 64.0 280 1120CO 84 19.2 84.0 336PM 7.6 1.74 7.60 30.4SO2 12.5 2.85 12.5 50NMHC 5.5 1.26 5.50 22

23


The BOHO has been the primary source of steam for refinery operations, but significant amounts of steam are generated by process units and through heat exchange. STRC has prepared a steam balance to show increased demands due to the HCPE project, increased steam production by new units or exchangers, and decreased demand due to removal from service. Some equipment will increase demand for one type of steam and simultaneously generate a different type. For example, the HCU is anticipated to consume 11,000 lb/hr of 50 psi steam while generating 53,650 lb/hr of 600 psi steam and 14,000 lb/hr of 250 psi steam. The table prepared by STRC contains more detail than the summary table presented here, which is intended to show only totals and net values.

Unit or Process Steam Balance in Lbs/hrGeneration Consumption Net

DCU 23,585 53,862 -30,277HCU 67,650 11,000 56,650CDU #2 0 58,400 -58,400H2 Plant 91,293 0 91,293SRU #3 55,269 0 55,269SRU #4 55,269 0 55,269SRU #5 55,269 0 55,269ARU #3 0 19,633 -19,633ARU #4 0 19,633 -19,633SWS #2 0 27,500 -27,500SWS #3 0 27,500 -27,500Diolefin reactor 0 15,000 -15,000Naphtha splitter 7,121 0 7,121C3/C4 splitter 0 15,000 -15,000Overhead lines steam tracing 0 5,000 -5,000Tank heating 0 5,000 -5,000CDU #1 remove from service 23,395 0 23,395Alky throughput increase 0 63,375 -63,375Totals 378,851 320,903 57,948

Of particular interest in this table is the data entry for the Alky unit, which will need to handle increased throughput due to DCU olefins. There will be an excess of 121,323 lb/hr of steam before considering the amount of steam needed to cover potential Alky increased throughput. The amount of steam indicated as net increase reflects the difference between current actual use and future potential, which is a larger interval than the difference between future potential and current allowable. This situation will be addressed in discussions of PSD in both Section VI (Oklahoma Rules) and Section VII (Federal Regulations).

24



Various process heaters share stacks. Stack parameters follow the equipment list. Except for SO2, natural gas emission factors are taken from AP-42 (3/98) Tables 1.4-1 and 2, assuming 1,020 BTU/CF. Note that actual heating values at certain units may vary widely from the standard mentioned. Because STRC is unable to provide exact heat ratings for this equipment, the following emission estimates would not become more accurate through knowledge of the precise heating value of the fuel used by each heater. All heaters burn fuel gas that complies with NSPS Subpart J, although none has been required to do so. STRC has elected to accept the Subpart J standard for all heaters for the HCPE project, but will be required to accept the standards under the Consent Decree. Thus, SO2 factors are based on H2S concentrations of 0.1 gr/dscf (approximately 26.9 lb/MMCF in this instance).

Source Pollutant Emission factorLb/MMCF

EmissionsLb/hr TPY

CDU#1 Atmospheric Heater* 200 MMBTUH

NOX 280 55 240CO 84 16 72PM 7.6 1.5 6.5SO2 59 12 51

NMHC 5.5 1.1 4.7

CDU#1 –Vacuum Heater* 90 MMBTUH

NOX 100 9 39CO 84 7 32PM 7.6 0.7 2.9SO2 59 5 23

NMHC 5.5 0.5 2.1

FCCU Air Heater (B-1) 38.4 MMBTUH

NOX 100 3.77 16.5CO 84 3.16 13.9PM 7.6 0.29 1.25SO2 26.9 1.01 4.44

NMHC 5.5 0.21 0.91

CRU Splitter Reboiler **100 MMBTUH

NOX 280 27.5 120CO 84 8.24 36.1PM 7.6 0.75 3.26SO2 26.9 2.64 11.5

NMHC 5.5 0.54 2.36

Unifiner Heater (H-1)45.9 MMBTUH

NOX 100 4.50 19.7CO 84 3.78 16.6PM 7.6 0.34 1.50SO2 26.9 1.21 5.30

NMHC 5.5 0.25 1.08* SO2 factors not adjusted from previous analyses because these

heaters will be retired upon completion of the HCPE project.** This heater to be removed from service upon startup of the CCR.

25


The following table is a total of all preceding values.

Pollutant Lb/hr TPYNOX 141 615CO 51.2 224PM 4.64 20.3SO2 25.6 112NMHC 3.34 14.6

Emission factors for Hazardous Air Pollutants (HAP) were also reviewed, using AP-42 (3/98) Table 1.4-3. Only those factors resulting in 0.01 TPY or more of any constituent are reported here.

Constituent CAS # TPYFormaldehyde 50-00-0 0.20Hexane 110-54-3 4.94Benzene 71-43-2 0.01Toluene 108-88-3 0.01

EUG 10 Sulfur Recovery Units / Tail Gas Treating Units

Emission reporting factors for the SRU #1 set are based on a Reference Method stack test for carbon monoxide, continuous emission monitoring (CEM) for SOX, and natural gas combustion factors from Tables 1.4-1 and 2 of AP-42 (7/98) for NOX, PM10, and VOC. Emission reporting factors for the SRU #2 set are all taken from the same AP-42 tables, except for SOX, which is also taken from CEM. Emissions of all pollutants were authorized in two construction permits; No. 98-021-C (M-15), which covered construction of the SCAN Unit, and No. 98-021-C (M-26), which covered the Low Sulfur Diesel Project, and on which all work is not yet complete. Emissions authorized by those permits were established based on the following considerations.

A voluntary limit was taken on SRU #1 for SOX to avoid PSD consequences in the SCAN project.

A limit based on the NSPS Subpart J standard of 250 ppm of SOX was applied to the maximum possible exhaust from SRU #2. Details are available in the Memorandum associated with the M-26 permit.

The NOX limit for SRU #1 was the maximum 0.20 lb/MMBTU limit of OAC 252:100-33-2(a) for new gas-fired fuel-burning equipment. The SRU #2 limit was based on the 0.18 lb/MMBTU expectation stated in the SCANfiner permit application.

SRU #1 and #2 factors for CO, PM10, and VOC were all based on the AP-42 tables mentioned earlier, although the PM10 factor for SRU #2 is now rounded up to 0.01 lb/MMBTU, and the SRU #2 CO factor has been adjusted to 0.3 lb/MMBTU, based on an equipment review. Subsequent Reference Method testing of CO emissions from SRU #1 required that a new limit be authorized by Permit No. 98-021-TV (M-52).

Process vents for Units 3, 4, and 5 are limited to the 250 ppmvd SOX standard of Subpart J. Units 3, 4, and 5 will meet NOX and CO standards of 0.07 lb/MMBTU (HHV).

26


The VOC and PM10 emission factors from AP-42 referenced earlier are used for Units 3, 4, and 5, although the PM10 standard is rounded up slightly to 0.01 lb/MMBTU to compensate for the combustion of RFG.

The following table summarizes these factors.

Pollutant SRU/TGTU #1 SRU/TGTU #2 SRU/TGTU #3 SRU/TGTU #4 SRU/TGTU #5NOX 0.20 lb/MMBTU 0.18 lb/MMBTU 0.07 lb/MMBTU 0.07 lb/MMBTU 0.07 lb/MMBTUCO RM test 0.30 lb/MMBTU 0.07 lb/MMBTU 0.07 lb/MMBTU 0.07 lb/MMBTUSO2 PSD limit 250 ppmvd 250 ppmvd 250 ppmvd 250 ppmvdPM10 7.6 lb/MMCF 7.6 lb/MMCF 0.01 lb/MMBTU 0.01 lb/MMBTU 0.01 lb/MMBTUVOC 5.5 lb/MMCF 5.5 lb/MMCF 5.5 lb/MMCF 5.5 lb/MMCF 5.5 lb/MMCF

Emission estimates follow, using these factors and known or expected heat rates for the incinerators at each unit. STRC has requested a total SO2 limit for units 3, 4, and 5, for two reasons. First, it is expected that the Subpart J standard of 250 ppmvd will be met easily and that actual concentrations will average less than half of the standard. Second, the new system is designed to be highly redundant, so it is unlikely that all three units will operate contemporaneously or at full capacity. Strict application of the 250 ppmvd standard to full capacity of each unit yields approximately 140 TPY of SO2, which implies 420 TPY assuming continuous full-capacity operation of all three units. STRC requests a federally-enforceable combined limit of 204.5 TPY of SO2 as a total for all three units.

SRU INCINERATOR EMISSIONS (TPY)Pollutant SRU/TGTU

#1SRU/TGTU

#2SRU/TGTU

#3SRU/TGTU

#4SRU/TGTU

#5Totals

NOX 4.91 9.54 5.52 5.52 5.52 31.0CO 99 15.9 5.52 5.52 5.52 131SO2 34.9 24.6 204.5 (SO2 Bubble) 264PM10 0.18 0.52 0.79 0.79 0.79 3.06VOC 0.13 0.29 0.43 0.43 0.43 1.69

EUG 11 FCCU

The various controls to be installed on the regenerator vent will allow STRC to meet various standards that the facility accepts as limits. The following standards are on a ppmv-dry basis, corrected to 0% oxygen.

Pollutant Standard Averaging period Standard Averaging periodNOX 40 ppm 7-day rolling average 20 ppm 365-day rolling averageCO 500 ppm 1-hour average 100 ppm 365-day rolling averageSO2 50 ppm 7-day rolling average 25 ppm 365-day rolling average

For purposes of clarity, the first 365-day compliance date for CO shall be 365 days after start-up of the FCCU scrubbing system. The Civil Action states that the first compliance demonstration date for the NOX and SO2 365-day limits is December 31, 2010. Proper operation of the scrubber

27


will maintain PM emissions at the required standard of 0.5 lb of PM per 1,000 lb of coke burnoff. STRC estimates that VOC emissions will continue at the level shown in the 2004 and 2005 emission inventories. Using these factors results in the following expected emissions.

Pollutant Lb/hr TPYNOX 14.5 31.8CO 110.6 96.9SO2 25.3 55.4PM10 9.0 39.4VOC 0.47 2.1

EUG 12 Flares

The addition of emergency flare #3 and the flare gas recovery system, discussed in Section II B (FCCU), is expected to decrease emissions from flaring. STRC has provided an engineering estimate of 80% reduction. The TVR memorandum includes an estimate of emissions based on emission factors found in Table 5.1-1 of AP-42 (1/95). Using 2006 refinery feed of 23,920,000 barrels yields the following results, listed here only for completeness, and in support of the comments made in the Federal Regulations section with respect to PSD. Note that the sulfur dioxide emissions were augmented to account for offgas from the Sour Water Stripper (SWS). Until construction of SRU #2, this offgas was routed to the flare system because SRU #1 was incapable of processing the stream.

Pollutant Emission factor(Lb/1000 barrels)

Emissions(TPY)

PM10 Negligible -0-NOX 18.9 228CO 4.3 51.4SO2 26.9 680*VOC 0.8 9.57H2S Eng. estimate 10.1

*See preceding discussion


Fugitive emission estimates for new equipment associated with the HCPE Project is based on an estimated number of piping components to be added with this project and component emission rates per the following.

Pumps and valves in light liquid / gaseous service are based on the Screening Value Correlations of Table 2-10 in the Protocol for Equipment Leak Emission Estimates (EPA-453/R-95-017), using screening values of 2,000 ppmv for pumps and 500 ppmv for valves/others.

Flanges / connectors in all services are based on the Refinery Average Emission Factors in Table 2-2 of the referenced Protocol.

Drain emissions are based on AP-42 Emission Estimates found in Table 9.1-2 of the 4 th

28


Edition of AP-42, including a 75% control efficiency found on page 9 of the TNRCC “Technical Guidance for Equipment Leak Fugitives” (10/2000).

Pumps and valves in heavy liquid service are based on the Refinery Average Emission Factors in Table 2-2 of the referenced Protocol.

Component Service Factor (Lb/hr/item) No. of Items Lb/hr Total TPY

Pump seals Light liquid/gas 1.14 10-2 40 0.46 2.00Heavy liquid 4.63 10-2 40 1.85 8.11

Valves Light liquid/gas 5.2 10-4 4,000 2.08 9.11Heavy liquid 5.07 10-4 4,000 2.03 8.88

Flanges/connectors

Light liquid/gas 5.5 10-4 10,000 5.50 24.1Heavy liquid 5.5 10-4 10,000 5.50 24.1

Drains Light liquid/gas 1.75 10-2 50 0.88 3.83Heavy liquid 1.75 10-2 50 0.88 3.83

Others Light liquid/gas 1.17 10-4 200 0.02 0.10Heavy liquid 1.17 10-4 0 0 0

Totals 28,380 19.2 84.0

Because CDU#1 and SRU#1 will be removed from service, the fugitive emissions decreases resulting from taking their components out of service are used as contemporaneous emissions decreases in the netting analysis (see Section V).


Emissions were calculated for the TVR analysis using EPA’s WATER9 program for estimating air emissions from wastewater systems, “Air Emission Models Wastewater Treatment.” The model was run using an outflow of 457,874,200 gallons (871 gpm) and measured concentrations of various constituents. Results were included in the EUG 16 totals. Although certain changes are to be made in the wastewater system, sending flow to the POTW, as mentioned in Section II N, will maintain flow to WWTP at the current or lower rate.

VOC emissions from the DNF system will be controlled by a Regenerative Thermal Oxidizer (RTO) system. RTO emissions are estimated based on a 97.7% destruction efficiency that is typical for this type of application. Pre-control VOC rates to the RTO are based on Version 2 of EPA’s Water 9 program. The DNF feature of the Water 9 program predicts almost all dissolved hydrocarbon in the wastewater will be stripped out by the DNF unit. Because of this model prediction, there is a substantial decrease of dissolved hydrocarbons in the treated water stream exiting the DNF that is routed to the aeration basin. The emissions decrease from the aeration basin is used as contemporaneous emissions decreases in the netting analysis (see Section V). The RTO has potential to emit no more than 5 TPY emissions of SO2, NOX, PM, or CO and is considered insignificant for these pollutants. This conclusion is based on applying emission factors from AP-42 (7/98) Tables 1.4-1 and 2 for all pollutants except SO2, for which an assumption of 0.0025 gr/dscf is made for consumption of pipeline natural gas. VOC emissions, calculated as described above, are

29


(762 TPY inlet to DNF - RTO) ( 100 – 97.7)% = 17.5 TPY.

Assuming continuous operation yields 4.00 lb/hr.


Cooling towers are considered to be trivial sources for Title V purposes, because particulate emissions are generally considered to be larger than 30 microns. Assuming drift to be 1.7 lb/1,000 gal (0.02%) for the induced draft systems in the TVR memorandum yields PM emissions of 62.2 TPY. Entrained non-HAP VOC emissions of 20.8 TPY were included in the totals for EUG 16. Calculation of VOC was based on factors found in Table 5.1-2 of AP-42 (1/95), using an aggregate circulation rate of 113,000 gpm.

Two new cooling towers are proposed for the HCPE project. These were evaluated by the same technique as the older towers; namely,

PM emissions (lb/hr) = gpm 60 min/hr 8.34 lb/gal drift % total dissolved solids (TDS).

TDS for the Tulsa Refinery is typically 4,000 ppm. These are modern units with drift eliminators estimated to perform at 0.0006%, but STRC assumes a value of 0.001%, assuring conservatively high results. The nominal circulation rate for the DCU tower is 8,000 gpm, yielding 0.16 lb/hr or 0.70 TPY of PM emissions. A nominal rate of 17,000 gpm for the HCU tower yields 0.34 lb/hr or 1.19 TPY of PM emissions. The application cites a paper titled Calculating Realistic PM10 Emissions from Cooling Towers, prepared by Reisman and Frisbie of Greystone Environmental Consultants, which was included in siting documents for a Palomar environmental application in California. As applied to this situation, the paper indicates that approximately 1/8 of all PM at the DCU tower is PM10 and less than 5% of the HCU tower PM is PM10. In any event, these towers are considered to be Trivial, as stated above. Using the same controlled VOC emission factor of 0.7 lb/million gallons of cooling water as was used in the TV and TVR calculations referenced above yields a fugitive VOC emission figure of 4.6 TPY for the combined flow of 25,000 gpm.

EUG 20 NSPS Kb Tanks (EFR) – MACT CC Group 1 Wastewater

Oil-Water Separator Tank 478 emissions were calculated using Tanks 4.0.9d, using slop oil with average vapor pressure 0.9344 psia as the contents and one turnover per year. Analysis yields 1.69 TPY of total VOC emissions, of which 0.56 TPY are HAP.

EUGs 25, 26, and 27 Fuel-Burning Equipment

Emissions of particulate (PM10), carbon monoxide (CO), and VOC from all new and existing equipment are calculated based on factors found in Tables 1.4-1 and 2 of AP-42 (7/98). Oxides of nitrogen (NOX) for new units and for those units modified with low-NOX burners is estimated based on vendor performance data. The NOX factor for existing units not modified for such burners is taken to be the OAC 252:100-33-2(a) limit of 0.20 lbs/MMBTU for new equipment. This factor differs from the AP-42 factor used in annual emission inventories. The emission limits

30


established by using this factor showed that the low sulfur diesel project was not significant for PSD. Further, all units are subject to performance testing to demonstrate that the limits are met. The SO2 factor assumes a maximum concentration of 0.1 grain of H2S per dscf, which is the NSPS Subpart J standard, and stoichiometric conversion to SO2. All refinery fuel gas (RFG) is assumed to have a heating value of 1,023 BTU/CF.

EUG 25Unit andHeat Rate Pollutant Emission

FactorEmissions

Lbs/hr TPY

NHDS Charge Heater (02H-001)39 MMBTUH

SO2 0.1 gr/dscf 1.03 4.49NOX 0.05 lb/MMBTU 1.95 8.54PM10 7.6 lb/MMSCF 0.29 1.27VOC 5.5 lb/MMSCF 0.21 0.92CO 0.04 lb/MMBTU 1.56 6.83

NHDS Stripper Reboiler (02H-002)44.2 MMBTUH


Scanfiner Charge Heater (12H-101)25.2 MMBTUH

SO2 0.1 gr/dscf 0.68 2.97NOX 0.07 lb/MMBTU 1.76 7.73PM10 7.6 lb/MMSCF 0.19 0.82VOC 5.5 lb/MMSCF 0.14 0.60CO 84 lb/MMSCF 2.07 9.06

HCU Reactor Charge Heater92 MMBTUH


HCU Fractionator Feed Heater86 MMBTUH


* Lb/hr figures reflect each heater, but TPY figures show three heaters combined.

EUG 26Unit andHeat Rate Pollutant Emission

FactorEmissions

Lbs/hr TPY

CCR #1 Interheater (10H-113)121.6 MMBTUH


31


EUG 26 cont’d.Unit andHeat Rate Pollutant Emission

FactorEmissions

Lbs/hr Lbs/hr

DCU Coker Heater221 MMBTUH


ADU #2 Heater283 MMBTUH


VDU #2 Heater 110 MMBTUH


H2 Plant Heater604 MMBTUH

SO2 0.1 gr/dscf * 3.68 16.1SO2 0.0025 gr/dscf * 0.31 1.34NOX 0.045 lb/MMBTU 27.2 119PM10 7.6 lb/MMSCF 4.49 19.7VOC 5.5 lb/MMSCF 3.25 14.3CO 0.04 lb/MMBTU 24.2 106

* This unit will use significantly more NG than RFG. SO2 emission calculations assume a mix of 140 MMBTUH of RFG and 464 MMBTUH of NG.

EUG 27Unit and

Heat Rate Pollutant EmissionFactor

EmissionsLbs/hr TPY

CCR Charge Heater (10H-101)

67.1 MMBTUH


CCR #2Interheater-1(10H-102)

123.3 MMBTUH


CCR #2 Interheater-2 (10H-103)

30.5 MMBTUH


32


Unit andHeat Rate Pollutant Emission

FactorEmissions

Lbs/hr TPY

CCR Stabilizer Reboiler

(10H-104)64.5 MMBTUH


DHTU Reactor Charge Heater

(1H-101)55 MMBTUH


FCCU Charge Heater(B-2)

73.3 MMBTUH


The following table summarizes the results of the three EUGs considered.

EUG SO2 NOX PM10 VOC COLb/hr TPY Lb/hr TPY Lb/hr TPY Lb/hr TPY Lb/hr TPY

25 7.53 33.0 12.2 53.2 2.13 9.32 1.54 6.74 12.5 54.826 23.3 102 63.6 279 9.95 43.6 7.20 31.5 53.6 23527 10.9 47.6 16.8 73.7 3.07 13.5 2.22 9.74 16.5 72.5Totals 41.7 183 92.6 406 15.2 66.4 11.0 48.0 82.6 362

Emissions From New Insignificant Activities

Coke handling includes drops, conveyor transfers, enclosed transport, crushing, and storage piles, each of which has associated PM/PM10 emissions. Emission factors and equations for these calculations are taken from tables and discussions in Sections 13.2.4 and 13.2.5 of AP-42 (11/06) and Section 11.19.2 of AP-42 (8/04). The following calculations describe only inputs and results, rather than presenting all of the intermediate results. As an example to support this abbreviated approach, the wind erosion calculation is long and tedious, and results in minuscule emissions. All calculations assume 588,015 short tons of coke production per year, assuming continuous operations at 1,611 tons per day. Wind speed is assumed to be 10 mph, and moisture content is taken to be 4.8%. Coke is assumed to be wet or is wetted throughout, for which the control factor is 70%. Since factors for coke are unavailable, factors for handling sand are used as a surrogate.

33


DropsThere are three drops. The particle size multiplier, k, is 0.74 for PM and is 0.35 for PM10. With 70% control, PM emissions are 0.45 TPY and PM10 emissions are 0.21 TPY.

Conveyor TransfersThere are four such transfers. In addition to the wetting factor, these transfers are enclosed, adding an additional 90% control. In this instance, PM and PM10 emissions are assumed to be equal, at 0.41 TPY.

Wind ErosionThree piles per day are assumed for the pad, with five disturbances daily. The threshold friction velocity is taken to be 1.12 m/s, the angle of repose to be 35 , and coke density to be 45 lb/ft3. The particle size multiplier is 1.0 for PM and is 0.5 for PM10. With 70% wetting control, emissions are 0.18 TPY of PM and 0.09 TPY of PM10.

CrusherNo particle size multiplier is necessary, because the factor is stated as 0.0054 lb/ton for PM and 0.0024 lb/ton for PM10. With 70% wetting control, emissions are 0.48 TPY of PM and 0.21 TPY of PM10.

Storage Silo DustThe emission factor storage loss (with fabric filter) is stated as 0.0099 lb/ton for PM and 0.0016 lb/ton for PM10, thus emissions are 2.91 TPY of PM and 0.47 TPY of PM10.

Total coke handling emissions are 4.43 TPY of PM and 1.41 TPY of PM10.

V. INSIGNIFICANT ACTIVITIES

The insignificant activities identified in the TVR memorandum and listed in the TVR permit are not modified by the HCPE project and may be reviewed in the referenced memorandum and permit. New items may be added to each of the categories listed in the TVR memorandum, but addition alone will not change applicability. However, the HCPE adds another activity, that of coke handling, with PM/PM10 emissions less than 5 TPY. Appropriate recordkeeping, including, but not necessarily limited to, throughput and control methods, is required to demonstrate that this activity continues to be insignificant.

VI. PSD ANALYSIS

This section of the permit application addresses Prevention of Significant Deterioration (PSD) permitting requirements. As noted in the 40 CFR Part 52 discussion in Section VII (Federal Regulation), the facility is a listed stationary source with emissions greater than 100 TPY, so PSD does apply. If a proposed increase in emissions from construction of a new source or modification of an existing source exceeds a PSD significance threshold, further analysis is required. Pollutants emitted by the refinery with potential to exceed one of the thresholds include oxides of sulfur (SO2), oxides of nitrogen (NOx), particulate matter (PM), carbon monoxide (CO), ozone (stated in terms of VOC), and hydrogen sulfide H2S (or total reduced

34


sulfur or reduced sulfur compounds). The applicant has reviewed emissions from new equipment, from modified equipment, and from non-modified equipment that will experience a change in method of operation associated with the HCPE project. Because the first five named all exceed their PSD significance thresholds, applicant proposes various controls and operating practices that it believes will decrease the project’s net emissions increases to levels less than the PSD significance thresholds. Therefore, full PSD review of these pollutant impacts would not be required. This process is referred to as “netting out.”

Applicant uses the “New Source Review Workshop Manual” (Workshop Manual, October 1990 version, Section III.B Emissions Netting) as a guideline for the netting analysis. This manual outlines a six-step procedure to determine a net emissions change at a source. These steps are summarized as follow.

1) Determine emission increase(s) from the proposed project. If the increase(s) are significant, proceed to step 2.

2) Determine beginning and ending dates for the contemporaneous period as it relates to the proposed construction or modification.

3) Determine which emission units at the source experienced (or will experience) an increase or decrease in emissions during the contemporaneous period.

4) Determine which emission changes are creditable.

5) Determine on a pollutant-by-pollutant basis, the amount of each contemporaneous and creditable emission increase and decrease.

6) Sum all contemporaneous and creditable increases and decreases with the increase from the proposed modification to determine if a significant net emission increase will occur.

For step 1, the applicant prepared a table of all emissions from new equipment, as shown below. This table lists each operating unit, the sources proposed, the heat input rate (for fired units), and anticipated emissions, in TPY, to be authorized by this permit. PM may be assumed to be PM10.

Unit Source MMBTUH SO2 NOX PM CO VOC

DCU

Coker Heater 221 25.4 72.6 7.2 38.7 5.2Material Handling N/A N/A N/A 2.1 N/A N/A

Cooling Tower N/A N/A N/A 0.7 N/A 1.5Flare #3 (pilots) 0.05 0.0001 0.01 0.002 0.08 0.001

CDU #2 ADU#2 Heater 283 32.6 43.4 9.2 49.6 6.7VDU#2 Heater 110 12.7 16.9 3.6 19.3 2.6

HCUReactor Charge Htr 92 10.6 14.1 3.0 16.1 2.2

Fractionator Feed Htr 86 9.9 13.2 2.8 15.1 2.0Cooling Tower N/A N/A N/A 1.2 N/A 3.1

H2 Plant H2 Plant Heater 604 17.4 119 19.7 105.8 14.3SRU #3 TGTU #3 N/A N/A 5.5 0.8 5.5 0.4SRU #4 TGTU #4 N/A N/A 5.5 0.8 5.5 0.4SRU #5 TGTU #5 N/A N/A 5.5 0.8 5.5 0.4

35


Unit Source MMBTUH SO2 NOX PM CO VOCSRU

#3/#4/#5TGTU #3/#4/#5 (SO2

bubble)* N/A 204.5 N/A N/A N/A N/A

Tank Farm

Tank #7 N/A N/A N/A N/A N/A 12.0Black Oil Tank N/A N/A N/A N/A N/A 3.8Biosolids Tank N/A N/A N/A N/A N/A 0.02

Sludge tank N/A N/A N/A N/A N/A 0.02SWS Tank N/A N/A N/A N/A N/A 4.0

Equipment Leaks Fugitive Emissions N/A N/A N/A N/A N/A 84.0

WWTP Tank # 478 N/A N/A N/A N/A N/A 1.7DNF N/A N/A N/A N/A N/A 17.2

Totals 314.0 296.4 52.3 261.8 161.5* As noted in Section III (Emissions), applicant has accepted a voluntary combined limit on the three SRUs, because the systems are heavily redundant.

Continuing with Step 1, applicant then constructed a table of emissions for sources modified by the HCPE project. The following table reflects only expected emissions, with no attempt yet to analyze previous actual emissions to determine the increase or decrease. Heat input here reflects the rating to be authorized in this permit. As noted in preceding sections of this memorandum, modifications include such items as adding controls and re-rating heaters. This PSD analysis does not revisit those topics; it only presents the numbers.

Unit Source MMBTUH SO2 NOX PM CO VOCDHTU Charge Heater 55.0 6.3 8.4 1.8 9.6 1.3

FCCU B2 Heater 73.3 8.4 12.8 2.4 12.8 1.7Regenerator N/A 55.4 31.8 39.4 96.9 2.1

CCR

Charge Heater 67.1 7.7 14.7 2.2 11.8 1.6#1 Interheater 121.6 14.0 26.6 4.0 21.3 2.9#2 Interheater (2A) 123.3 14.2 18.9 4.0 21.6 2.9#2 Interheater 30.5 3.5 4.7 1.0 5.3 0.7Stabilizer Reboiler 64.5 7.4 14.1 2.1 11.3 1.5Regenerator Stack N/A 0.08 0.06 Neg 0.67 Neg

Penex Unifiner Heater 45.9 5.3 19.7 1.5 16.6 1.1Totals 122.4 151.8 58.4 207.9 15.8

Continuing with Step 1, applicant then constructed a table of emissions for sources not modified by the HCPE project, but expected to have a change in operation due to the project. Some analyses refer to these as upstream or downstream increases. Heater emissions in the table at the end of this step 1 discussion reflect only expected emissions from heaters, with no attempt yet to analyze previous actual emissions to determine the increase or decrease. Heat input here reflects the rating currently authorized by previous permits.

As described in Section II (A), this project will result in increased heavy crude oil entering the refinery, increased intermediate (i.e., gasoline and distillate fuel oil) production and increased finished gasoline and distillate fuel oil production. Crude oils and gasoline intermediates and products are stored in floating roof tanks. Distillate fuel oils are typically stored in fixed roof tanks. The majority of VOC emissions from these sources occur from standing losses, which are not dependent upon throughput.

36


The facility has estimated the increase in storage tank working losses resulting from increases in throughput based on the following analysis. Several storage tanks in crude oil, intermediate and product service were chosen to represent all other existing tanks in similar service at the refinery. Crude oil and light intermediate tank throughputs were compiled for calendar year 2006. The forecasted crude oil and light intermediate tank throughputs resulting from the HCPE project were based on scaling the 2006 throughputs by the nominal refinery crude charge rate increase, or 2006 throughput 115,000 BPD / 75,000 BPD. Black oil and asphalt tank throughputs were based on the nominal Coker Unit capacity of 30,000 BPD.

Working losses for calendar year 2006 and forecasted working losses resulting from the HCPE project were then calculated using EPA’s Tanks Program 4.09d. The difference between forecasted working losses and reported 2006 working losses on a per tank basis were taken as representative of increased emissions for all tanks in the group. Emission increases for each representative tank were multiplied by the number of tanks in that service and summed to obtain the estimated total increase in emissions due to increased throughput resulting from the HCPE project. The following table shows some of the calculations performed in this effort. Forecasted throughput for all but two of the “contents” types listed is approximately 153% of 2006. Throughput for the two “black oil/asphalt” types is forecasted at 307% of 2006 throughput.

Example Tank No. Contents Type

Working Losses Lb/yr

# of Similar Tanks (2006)

TPY Working

Loss Increase2006 HCPE

3 Crude oil IFR 4,135 6,339 4 4.41117 #2 Diesel Fixed Roof 1,863 2,174 11 1.71116 #1 Diesel Fixed Roof 1,200 1,279 3 0.12459 LSR* IFR 129 198 27 0.9317 LCO Fixed Roof 53 77 1 0.01

125 Black oil/asphalt Heated, Fixed Roof 441 1,354 16 7.31107 Black oil/asphalt Heated, Fixed Roof 4,871 14,972 1 5.05122 Decant Heated, Fixed Roof 10 15 3 0.01

9 Gas oil Heated, Fixed Roof 7,693 11,795 4 8.21Totals 70 27.8

* LSR (Light Straight Run) covers HSR, LSR, slop oil, WW, all gasolines, penate, and alkylate.

The following table summarizes the unmodified sources.

Unit Source MMBTUH SO2 NOX PM CO VOCNHDS Charge Heater 39.0 4.5 8.5 1.3 6.8 0.9

Stripper Reboiler 44.2 5.1 9.7 1.4 7.7 1.0SRU #2 TGTU #2 N/A 24.6 9.6 0.5 15.9 0.3Tanks Working losses N/A N/A N/A N/A N/A 27.8Scanfiner SCAN Heater 25.2 2.9 7.7 0.8 9.1 0.6

Totals 37.1 35.5 4.1 39.6 30.6

37


For step 2, the applicant reviewed “net emission increase” in the definitions of OAC 252:100-8-31, where (B) states that “An increase or decrease in actual emissions is contemporaneous with the increase from the particular change only if it occurs within 3 years before the date that the increase from the particular change occurs.” EPA guidance and discussions with AQD suggest that the “date” referenced in the definition is the date commencement of construction of the project begins. Based upon an April 1, 2008, commencement of construction date, the contemporaneous period began on April 1, 2005.

The facility constructed two tables for step 3; one to cover increases and a second to cover decreases. Every increase/decrease is tagged with the permit number under which it was or is considered. Only two base permits are involved; including modifications to the original Part 70 Permit No. 98-021-TV and the current construction Permit No. 2007-005-C (M-1) covering the HCPE project. For convenience, all references to modifications of the original TV permit are identified by the type of modification (C for construction, TV for operating, and AD for applicability determination) followed by the modification number, and the HCPE permit is identified as HCPE. Step 3 makes no attempt to determine which of these increases/decreases is creditable.

INCREASESPermit No. Emission source Emission increases Basis for emissions

C (M-26) Various (this is the low sulfur diesel project)

SO2, NOX, PM,CO, and VOC Permit application

C (M-28) Replace Tank #9 VOC Permit applicationC (M-34) Tank #476 VOC Permit applicationTV (M-36 & 39) Tank #31 VOC Permit applicationAD (M-38) Additive tank at rack VOC Permit applicationTV (M-40) Tank #16 VOC Permit applicationAD (M-45) Alky cooling tower PM & VOC Permit applicationTV (M-48) Tank #14 VOC Permit applicationTV (M-50) Replace Tank #472 VOC Permit applicationTV (M-51) Tank #115a VOC Permit application

38


DECREASESPermit No. Emission source Emission decreases Basis for emissions

C (M-26) Various (this is the low sulfur diesel project) SO2, NOX, PM,CO, and VOC Permit application

C (M-28) Old Tank #9 VOC Permit applicationTV (M-40) Remove Tank #16 VOC Permit applicationHCPE Remove Tank #472 VOC Average 2005/2006 AEIHCPE Remove Tank #7 VOC Average 2005/2006 AEIHCPE Remove Tanks #106 and 1211 VOC Average 2004/2005 AEIHCPE Remove Tanks #120, 127, 400, & 401 VOC Average 2005/2006 AEIHCPE Remove #1 SRU/TGTU from service SO2, NOX, PM,

CO, and VOCAverage 2005/2006 AEI

HCPE Remove CDU #1 heaters from service SO2, NOX, PM, CO, and VOC

Average 2005/2006 AEI

HCPE Eliminate fuel oil from BOHO PM Average 2005/2006 AEI2

HCPE Flares #1 & #2 decrease from flare gas recovery system

CO and VOC 80% of average 2005/2006 AEI

HCPE Tank #459 service change VOC Average 2005/2006 AEIHCPE Install water seals on selected process drains VOC Controlled/noncontrolled

factor differenceHCPE Remove CDU #1 process drains from service VOC Non-controlled factorHCPE Remove API separators from service VOC Average 2005/2006 AEIHCPE Aeration basin emission changes from

DNF/RTOVOC 3

1. BOHO 3/4 burned both oil and gas, while BOHO 1/2 burned only gas. Thus, the credit taken for PM reflects the difference in PM emissions for these two sources for the AEI periods considered.

2. 2006 was not a representative year, so 2004 & 2005 were used. 3. Explanation follows in text.

The following tables reflect the emission amounts deriving from the preceding two tables. The item referenced as “Install water seals on selected process drains” is analyzed by comparing before and after control installation. There are 461 existing drains in the facility, of which 35% are controlled. The facility plans to increase the number of controlled drains to 68%. As mentioned in Emissions Section III above, the emission factor used for drains is 0.07 lb/hr, taken from Edition 4 of AP-42. Control efficiency is taken to be 75%. Thus, the decrease in emissions effected by controlling drains may be calculated by comparing the emissions before and after the project establishes controls on the various drains, as shown in the following table.

Existing ProposedNumber of drains 461 461Uncontrolled 65% 32%Controlled 35% 68%Uncontrolled emission factor 0.07 lb/hr 0.07 lb/hrControlled emission factor 0.0175 lb/hr 0.0175 lb/hrLb/hr VOC 23.8 15.8TPY VOC 104.2 69.3Net decrease VOC 35.0

The DNF/RTO installation greatly alters emissions from the wastewater system. The facility has calculated emissions from the wastewater system for its annual inventory by combining three

39


sets of data. One is an analysis of drains, using AP-42 4th Edition emission factors, another involves tanks, using Tanks 4.0 or a predecessor, and the last uses Water9, which covers the remainder of the system, starting at the diversion block. The API separators used in previous versions of Water9 will be replaced by the DNF/RTO as part of the HCPE project. Analysis of drains is accounted for in two items in the preceding table, and the separators are covered by another. Because of the mix of methods used in calculating the overall total, it is difficult to identify the exact amount of decrease in emissions from the aeration basin. The 2006 emission inventory stated 387 tons of VOC from the entire system. The facility deliberately overstated expected VOC entrained at the physical point at which the Water9 program commences (762 TPY) and assumed that all will pass through the DNF/RTO, thus overestimating RTO emissions by nearly double. While post-HCPE emissions from the basin will not be zero, they will be very low. Therefore, the facility stated that the decrease in aeration basin emissions will be nearly 60.8 TPY, the average of the Water9 calculations for 2005 and 2006.

INCREASES (TPY)Emission source SO2 NOX PM CO VOCVarious (this is the low sulfur diesel project) 129.9 267.2 5.8 227.5 39.5

Replace Tank #9 N/A N/A N/A N/A 13.7Tank #476 N/A N/A N/A N/A 1.9Tank #31 N/A N/A N/A N/A 3.6Additive tank at rack N/A N/A N/A N/A 0.04Tank #16 N/A N/A N/A N/A 6.3Alky cooling tower N/A N/A 2.2 N/A 4.6Tank #14 N/A N/A N/A N/A 9.3Replace Tank #472 N/A N/A N/A N/A 5.97Tank #115a N/A N/A N/A N/A 4.2Totals 129.9 267.2 8.0 227.5 89.1

DECREASESEmission source SO2 NOX PM CO VOCVarious (this is the low sulfur diesel project) 1,053.5 261.1 11.9 132.0 5.0Old Tank #9 N/A N/A N/A N/A 1.5Remove Tank #16 N/A N/A N/A N/A 5.0Remove Tank #472 N/A N/A N/A N/A 5.2Remove Tank #7 N/A N/A N/A N/A 6.5Remove Tanks #106 and 121 N/A N/A N/A N/A 33.6Remove Tanks #120, 127, 400, & 401 N/A N/A N/A N/A 8.9Remove #1 SRU/TGTU from service 34.9 4.9 0.3 69.5 0.1Remove #1 SRU/TGTU fugitive components N/A N/A N/A N/A 0.3Remove CDU #1 heaters from service 18.3 248.6 8.6 94.6 3.6Eliminate fuel oil from BOHO N/A N/A 67.0 N/A 0Flares #1 & #2 decrease because of flare gas recovery system N/A N/A N/A 40.8 7.6

Tank #459 service change N/A N/A N/A N/A 7.0Install water seals on selected process drains N/A N/A N/A N/A 35.0Remove CDU #1 process drains from service N/A N/A N/A N/A 15.3Remove CDU #1 fugitive components N/A N/A N/A N/A 14.7Remove API separators from service N/A N/A N/A N/A 52.3Aeration basin emission change N/A N/A N/A N/A 60.8Totals 1,106.7 514.6 87.7 336.9 263.4

40


Step 4 determines that all of the emission changes listed in step 3 are creditable because: the emission changes are not relied upon in a previously issued PSD permit; the increase and decrease in emissions occurred after the associated major and minor source baseline dates; emission decreases will be federally enforceable and in place before the new and modified equipment limits start; emission decreases have the same health and welfare significance as the proposed increases from the facility; and the emission decreases are not used to correct non-compliance.

Recall now that Step 5 calls for a determination of the amount of each contemporaneous and creditable emission increase and decrease on a pollutant-by-pollutant basis. The basis for determining these amounts relies on EPA’s “actual-to-potential test,” and is referenced in OAC 252:100-8-30(b)(5) as the “Hybrid test for projects that involve multiple types of emission units.” OAC 252:100-8-30(b)(6) allows the actual-to-potential test for existing units. In the usual process, actual emissions (which are based upon the average actual emissions of the previous two representative years) from the source are used. If a source has been in operation for less than two years, the PSD netting procedure allows the use of allowable emissions in lieu of actual emissions because the source has not yet begun “normal operation.” Where available, AEI data from 2005 and 2006 were used to calculate average emissions. Actual data were used in Tanks 4.09 calculations. However, the following items authorized under Permit No. 98-021-C (M-26) were not in service long enough to have accumulated two years worth of emission data, so the emission amounts authorized in that permit are used to represent their “actuals.”

Unit Source Unit Source

NHDS Charge heater

CCR

Charge heaterStripper reboiler Interheater #1

Interheater #2aDHTU Charge heater Interheater #2b

Stabilizer reboilerSRU #2 TGTU #2 Regenerator stack

The FCCU B2 heater will be required to provide NOX control under the Civil Action, and provisions of the Consent Decree will not allow NOx emission reductions achieved by installing “qualifying controls” to be used for other permitting project reductions. A reduction of zero is assured by arbitrarily setting “past actuals” equal to the amount authorized by the HCPE project. All pollutants other than NOX are taken from the 2005/2006 AEIs.

Similarly, FCCU Regenerator emission limits for SO2, NOX and PM will be required under the Civil Action, and may not be used for other permitting reductions. A reduction of zero is assured by arbitrarily setting “past actuals” equal to the amount authorized by the HCPE project. All pollutants other than SO2, NOX and PM are taken from the 2005/2006 AEIs.

Given the information from the two preceding paragraphs and the table before them, a table of past actual emissions can be constructed for these sources, as follows.

41


PAST ACTUAL EMISSIONS (TPY)Unit Source SO2 NOX PM CO VOC

NHDS Charge heater 4.5 8.5 0.3 14.1 0.9Stripper reboiler 5.1 9.7 0.4 16.0 1.0

DHTU Charge heater 6.3 48.2 0.4 19.8 1.3

FCCU B2 heater 3.6 12.8 1.8 19.6 0.7Regenerator 55.4 31.8 39.4 46.1 0.04

SRU #2 TGTU #2 24.6 9.6 0.5 4.4 0.3

CCR

Charge heater 13.8 26.3 1.0 43.3 2.8Interheater #1 16.3 31.0 1.2 51.1 3.3Interheater #2a 11.6 88.5 0.8 36.4 2.4Interheater #2b 2.9 21.9 0.2 9.0 0.6Stabilizer reboiler 9.8 18.6 0.7 30.7 2.0Regenerator 0.08 0.06 Neg. 0.67 Neg.

Scanfiner Heater 0.030 4.6 0.17 3.9 0.22Penex Unifiner heater 0.050 7.2 0.5 6.0 0.2Totals 154.0 318.9 47.4 301.1 15.8

Step 6 summarizes the results of the first five steps and compares the total for each pollutant with its significance threshold. The following table shows increases and decreases calculated above, indicating the decreases with minus signs. As shown, the net emission increase for each pollutant is less than its respective PSD significance level. Therefore, PSD does not apply to this project.

EMISSION CHANGE SUMMARY (TPY)Source SO2 NOX PM CO VOCNew equipment 314 296.4 52.3 261.8 161.5Modified sources 122.4 151.8 58.4 207.9 15.8Operating changes 37.1 35.5 4.1 39.6 30.6Contemporaneous emission changes

129.9 267.2 8.0 227.5 89.1-1,106.7 -514.6 -87.7 -336.9 -263.4

Previous “actual” -154.0 -318.9 -47.4 -301.1 -15.8Net change -657 -82 -12.3 98.8 17.8Significance threshold 40 40 15* 100 40Significant? No No No No No

* 15 TPY is the PM10 threshold; the project clearly meets the 25 TPY PM threshold.

VII. OKLAHOMA AIR POLLUTION CONTROL RULES

OAC 252:100-1 (General Provisions) [Applicable]Subchapter 1 includes definitions but there are no regulatory requirements.

OAC 252:100-2 (Incorporation by Reference) [Applicable]This subchapter incorporates by reference applicable provisions of Title 40 of the Code of Federal Regulations listed in OAC 252:100, Appendix Q. These requirements are addressed in the “Federal Regulations” section.

42


OAC 252:100-3 (Air Quality Standards and Increments) [Applicable]Subchapter 3 enumerates the primary and secondary ambient air quality standards and the significant deterioration increments. At this time, all of Oklahoma is in “attainment” of these standards.

OAC 252:100-5 (Registration, Emissions Inventory and Annual Operating Fees) [Applicable]Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission inventories annually, and pay annual operating fees based upon total annual emissions of regulated pollutants. Emission inventories were submitted and fees paid for previous years as required.

OAC 252:100-8 (Permits for Part 70 Sources) [Applicable]Part 5 includes the general administrative requirements for Part 70 permits. Any planned changes in the operation of the facility that result in emissions not authorized in the permit and that exceed the “Insignificant Activities” or “Trivial Activities” thresholds require prior notification to AQD and may require a permit modification. Insignificant activities refer to those individual emission units either listed in Appendix I or whose actual calendar year emissions do not exceed the following limits.

5 TPY of any one criteria pollutant 2 TPY of any one hazardous air pollutant (HAP) or 5 TPY of multiple HAP or 20%

of any threshold less than 10 TPY for a HAP that the EPA may establish by rule

Emission limitations and operational requirements necessary to assure compliance with all applicable requirements for all sources are taken from the pending TVR permit, from the HCPE project application, or are developed from the applicable requirement.

Section VI of this memorandum addresses overall PSD significance, but a specific issue needs further consideration here. The facility accepted a daily limit on alkylate production under Permit No. 98-021-C in order to assure netting out of a potential PSD significance situation. STRC now wishes to be released from the 5,500 BPD limit, which requires significant modification of their permit per §8-7.2(b)(2)(A)(iv), and needs justification. The Alky has no independent source of steam, so the increase from the then-current level of 3,260 BPD to the proposed level of 5,500 BPD required additional steam, which was available only from the BOHO. A worst-case estimate made in the construction application was that 78,000 lb/hr of steam would give rise to 31.4 TPY of additional NOX emissions from the BOHO, below the PSD significance level of 40 TPY. Therefore, alkylate production at 5,500 BPD was accepted as a surrogate limit assuring that the PSD level would not be breached. The analysis offered under EUG 8 in Section III shows that increases in alkylate production will occasion no increase in BOHO emissions; indeed, after all steam demands are met, there remains an excess of 58,000 lb/hr of steam, almost enough to compensate for the original need of 78,000 lb/hr. The surrogate limit imposed under Permit No. 98-021-C and embedded in the succeeding TV and TVR permits may be released.

43


OAC 252:100-9 (Excess Emissions Reporting Requirements) [Applicable]In the event of any release which results in excess emissions, the owner or operator of such facility shall notify the Air Quality Division as soon as the owner or operator of the facility has knowledge of such emissions, but no later than 4:30 p.m. the next working day. Within ten (10) working days after the immediate notice is given, the owner or operator shall submit a written report describing the extent of the excess emissions and response actions taken by the facility. In addition, if the owner or operator wishes to be considered for the exemption established in 252:100-9-3.3, a Demonstration of Cause must be submitted within 30 calendar days after the occurrence has ended.

OAC 252:100-13 (Open Burning) [Applicable]Open burning of refuse and other combustible material is prohibited except as authorized in the specific examples and under the conditions listed in this subchapter.

OAC 252:100-19 (Particulate Matter (PM)) [Applicable]Section 19-4 regulates emissions of PM from new and existing fuel-burning equipment, with emission limits based on maximum design heat input rating. Fuel-burning equipment is defined in OAC 252:100-19 as any internal combustion engine or gas turbine, or other combustion device used to convert the combustion of fuel into usable energy. The flares of EUG-12 are not pieces of fuel-burning equipment under the state definition and are not affected by this rule. The same argument applies to the incinerators at TGTU #3, #4, and #5.All fuel-burning equipment added by the HCPE project uses gaseous fuel. AP-42 (7/98) Table 1.4-2 lists natural gas total PM emissions to be 7.6 lbs/million scf or about 0.0076 lbs/MMBTU, which is in compliance. The following new or modified equipment is subject to the requirements of this subchapter.

EquipmentMaximum Heat Input

(MMBTUH)

Emissions (Lbs/MMBTU)Appendix C Potential Rate

FCCU Charge Heater (B-2) 73.3 0.37 0.008Unifiner Heater (H-1) 45.9 0.42 0.008CCR #1 Interheater (10H-113) 121.6 0.33 0.008CCR Charge Heater(10H-101) 67.1 0.38 0.008CCR #2 Interheater-1(10H-102) 123.3 0.33 0.008CCR #2 Interheater-2(10H-103) 30.5 0.46 0.008CCR Stabilizer Reboiler (10H-104) 64.5 0.39 0.008DCU Coker Heater 221 0.29 0.008ADU #2 Heater 283 0.34 0.008VDU #2 Heater 110 0.34 0.008HCU Reactor Charge Heater 92 0.35 0.008HCU Fractionator Feed Heater 86 0.36 0.008H2 Plant heater 604 0.23 0.008Flare #3 pilots 0.05 0.60 0.008RTO 1.5 0.60 0.008

44


Section 19-12 sets limits on particulate emissions from any new or existing industrial process. The facility compared throughput of crude and catalyst with reported emissions for 2006 in its TVR application. Conservatively calculated emissions were approximately 90% of the allowable. Although some new sources of particulate emissions will be added, improved control of existing sources, coupled with the cessation of liquid fuel-burning at the BOHO, suggest that future emissions will be less than the amount that will be allowed by the increased throughput. This issue will be reviewed further when the operating permit application is received.

OAC 252:100-25 (Visible Emissions and Particulates) [Applicable]No discharge of greater than 20% opacity is allowed except for short-term occurrences that consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours. In no case shall the average of any six-minute period exceed 60% opacity. The flares are potential sources of visible emissions at this facility. Proper operation of the smokeless flares should maintain compliance.

Subsection 25-5(a) requires continuous monitoring of opacity at the FCCU catalyst regenerator. The continuous opacity monitoring (COM) system is in place and has met all requirements. The addition of a scrubber to control vent emissions means that an alternative monitoring plan (AMP) will become necessary for this unit, as described elsewhere in this memorandum.Subsection 25-5(d) allows an alternative to meeting the monitoring requirement, and it is expected that the AMP will meet the requisite criteria. The AMP has not been provided because the scrubber design has not been completed. As a final point to this discussion, the pending civil action is expected to redefine the FCCU as subject to NSPS Subpart J, which will exempt the unit from §25-5(a) per §25-5(c).This subsection also applies to fossil-fueled steam generators with heat input greater than 250 MMBTUH. Although the CDU #2 atmospheric heater and the H2 Plant heater are rated in excess of 250 MMBTUH each, they are process heaters that do not fit the definition of steam generating units.

OAC 252:100-29 (Fugitive Dust) [Applicable]No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the property line on which the emissions originate in such a manner as to damage or to interfere with the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the maintenance of air quality standards. Heavy traffic areas, including the racks and the offices, are paved. Vehicular traffic in the unpaved areas is greatly restricted for safety reasons. Under normal operating conditions, this facility will not cause fugitive dust problems, therefore it is not necessary to require specific precautions to be taken.

OAC 252:100-31 (Sulfur Compounds) [Applicable]Part 2 lists maximum ambient air SO2 concentration limits of 1,300 g/m3 for a 5-minute period, 1,200 g/m3 (1-hour average), 650 g/m3 (3-hour average), 130 g/m3 (24-hour average), and 80 g/m3 (annual average), for existing equipment. Screen3 analysis was performed in the initial TV Memorandum for all emission points using RFG or liquid fuel. At the time the original TV operating permit was issued, these standards were frequently interpreted to apply to each source. Wording in Part 2 makes it clear that this standard applies to aggregated sources. The HCPE project will bring the count of SO2-emitting sources to at least 20. Stack data for most of the

45


proposed new units is unavailable, because detailed engineering design has not been completed. The number of sources and the lack of stack data make it necessary to use some simplifying assumptions to obtain estimates of ground level concentrations. Reviewing the previous effort, the most direct method is to assume all flow through a single stack whose height, diameter, and exhaust velocity most closely match those of the original modeling effort.

Each of these independent variables was estimated by calculating an average value, using TPY of SO2 emitted to weight each value. This analysis resulted in a stack with height slightly greater than 165', diameter slightly greater than 5.5', and exhaust velocity approximately 55 fps. Temperature was arbitrarily set at 550F. Total SO2 emissions are assumed to be the PTE shown in the TVR memorandum less the decrease expected by STRC for the HCPE project. Because the TVR numbers were typically conservatively high, this should yield high results. Thus, the SO2 input datum is 557 lbs/hr. With these input assumptions, Screen3 showed a maximum one-hour concentration of 294 μg/m3 at 6,890 feet.

Screen3 provided 1-hour, 3-hour, 8-hour, 24-hour, and annual impacts. A 5-minute impact was calculated using a factor of 1.6 on the 1-hour factor, as presented in “Screening Procedures for Estimating the Air Quality Impact from Stationary Sources,” Revised (EPA-454/R-92-019). These results are tabulated below, and demonstrate compliance.

Ambient Impacts of SO2

Averaging Time Standard (g/m3) Ground Level Concentration (g/m3)5-minute 1,300 4711-hour 1,200 2943-hour 650 265

24-hour 130 118Annual 80 24

Part 2 also sets a 24-hour ambient air concentration limit of 0.2 ppm for emissions of H2S. Emissions of SO2 represent the fairly efficient combustion of H2S. Assuming only 90% conversion and comparing molecular weights of the two compounds suggests that the highest 24-hour impact that H2S is capable of causing at the property line is approximately 118 g/m3 (10%/90%) (34/64) = 7 g/m3. The subchapter standard of 0.2 ppm converts to approximately 280 g/m3, so compliance is demonstrated for all sources.

Part 5 covers new equipment standards.In particular, section 31-25 addresses sulfur oxides. New gas fuel-burning equipment, such as the nine new process heaters added by the HCPE project, must meet a standard of 0.2 lbs of SO 2

per MMBTU, three-hour average, per §25(a)(1). Because a permit condition limits H2S content of the RFG to 0.1 gr/dscm, stoichiometric conversion of all H2S to SO2 would yield emissions of 0.027 lbs/MMBTU, well within the limit set forth. Emission monitoring, fuel monitoring, and recordkeeping standards are set in §25(c), but apply to only those items rated at 250 MMBTUH or greater. In this instance, the H2 Plant heater, at 604 MMBTUH, and the CDU #2 atmospheric tower heater, at 283 MMBTUH, are affected facilities. Continuous monitoring of opacity and of SO2 emissions is required. An exemption from opacity monitoring is granted when only gaseous fuel is combusted, as is the case for these two heaters. An exemption from SO2 monitoring is possible when only gaseous fuel with sulfur content less than 0.1% by weight is combusted. The NSPS Subpart J standard of 0.10 grains per dry standard cubic foot is approximately equal to less

46


than 0.04% by weight, so compliance with Subpart J satisfies the criterion for exemption from SO2 monitoring under §31-25.

Section 31-26(a)(1) covers hydrogen sulfide, setting requirements on the removal efficiency and emission rates for H2S for exhaust gasses. The new process units added by the HCPE project must meet this standard. All vent streams containing H2S will be routed to flares with combustion efficiency greater than 95%, satisfying the requirements of this section.

Section 31-26(a)(2) covers SO2 recovery standards for the SRUs. Specifically, the three new SRUs, rated at 150 LTD each, are covered by the standard described in subparagraph D. The SO2 reduction efficiency requirement for any SRU is defined by the equation Z = 92.34 X0.00774, where Z is the required efficiency and X is the throughput in LTD. For these SRUs, the result is 96.0%. Using only the 250 ppmvd standard identified in Emissions Section III above, each SRU/TGTU is capable of emitting SO2 at 31.7 lbs/hr. Converting 150 LTD of sulfur to SO2

equivalent yields 27,974 lbs/hr. SO2 emissions represent only 0.113% of total SO2 available, so the efficiency of these new units is expected to be 99.9%, significantly better than the 96.0% requirement.

OAC 252:100-33 (Nitrogen Oxides) [Applicable]This subchapter limits new gas-fired fuel-burning equipment with rated heat input greater than or equal to 50 MMBTUH to emissions of 0.20 lbs of NOx per MMBTU, three-hour average. There are numerous heaters to be added by the HCPE project and a number of heaters that will be modified. Heaters accepting lower emission limits in order to comply with the civil action are not affected by this regulation, although they will all be in compliance. Heaters taking increased heat input ratings under the HCPE project are considered to be affected sources. The following list shows that heaters meeting any of the criteria as affected sources will be in compliance with the 0.20 lbs/MMBTU standard.

Source Input (MMBTUH)

Limit Accepted (Lbs/MMBTU)

FCCU Charge Heater (B-2) 73.3 0.040HCU Reactor Charge Heater 92 0.035HCU Fractionator Feed Heater 86 0.035DCU Coker Heater 221 0.075H2 Plant Heater 604 0.045ADU #2 Heater 283 0.035VDU #2 Heater 110 0.035CCR #2 Interheater-1 (10H-102) 123.3 0.035CCR Stabilizer Reboiler Heater (10H-104) 64.5 0.050

OAC 252:100-35 (Carbon Monoxide) [Not Applicable]The catalytic cracking unit and catalytic reforming unit are existing sources, but are not subject to the standards of Paragraph 35-2(a) because Tulsa County is not a non-attainment area for carbon monoxide. If sufficient modifications were performed to either unit that they might become affected sources, they would meet the new source standards of 35-2(b) because both have complete secondary combustion systems. The FCCU has a monitor to establish that excess

47


oxygen is present in the flue gas. The CRU uses a portable analyzer that establishes that excess oxygen is present at various points in the system. This monitoring is not an OAC 252:100 requirement, and would become so only under the reconstruction or modification situation outlined above. If the conversion of the CRU to a CCR under the Low Sulfur Diesel Project covered by Permit No. 98-021-C (M-26) were sufficient to make this a “new” source, it would meet the new source standards of 35-2(b) because compliance with the standards of 40 CFR 63 Subpart UUU would satisfy the requirements of this subchapter.

OAC 252:100-37 (Volatile Organic Compounds) [Parts 3 & 7 Applicable]Part 3 concerns the control of volatile organic compounds.Section 37-15 (a) requires that all storage tanks with capacity greater than 40,000 gallons and storing a VOC with a vapor pressure greater than 1.5 psia shall be pressure vessels or shall be equipped with one of the following vapor-loss control devices.

(1) They shall be of EFR or fixed roof with IFR design, with the roof floating on the liquid surface at all times and equipped with a closure seal between the roof edge and the tank wall. Floating roofs are not suitable control for liquids with vapor pressure greater than 11.1 psia. All gauging and sampling devices shall be gas-tight except when gauging or sampling is taking place.(2) They shall have an 85% efficient vapor recovery system and a vapor disposal system. All gauging and sampling devices shall be gas-tight except when gauging or sampling is taking place.(3) They shall have other equipment or methods with efficiency at least equal to those devices listed above.

The sludge, biosolids, and black oil tanks being added to EUG 3 have capacities greater than 40,000 gallons, but none of them stores liquid with vapor pressure greater than or equal to 1.5 psia. These three tanks are exempt from the provisions of Section 37-15 per §37-4(a).The heavy naphtha and sour water storage tanks being added to EUG 5 have capacity greater than 40,000 gallons and are IFR tanks subject to Subpart Kb. These tanks are exempt from the provisions of Section 37-15 per §37-15(c).

Section 37-15 (b) requires storage tanks with a capacity of 400 gallons or more and storing a VOC with a vapor pressure greater than 1.5 psia to be equipped with a permanent submerged fill pipe or with an organic vapor recovery system per §37-15(a)(2). The tanks identified in the discussion of Subsection 15(a) satisfy the submerged fill condition.

Section 37-16 establishes standards for the loading of volatile organic compounds. Offloading of distillate proposed in the HCPE is not a loading operation affected by this section, and the distillate will probably have vapor pressure below 1.5 psia, and be exempt from the provisions of this section per §37-4(a).Part 5 limits the organic solvent content of coating or other operations. This facility does not normally conduct coating or painting operations except for routine maintenance of the facility and equipment, which is exempt.Part 7 regulates specific processes.Section 37-36 requires fuel-burning equipment to be operated and maintained so as to minimize emissions. New flare #3 will not be considered fuel-burning equipment and will not be an affected source. New emergency pump engines, the electrical generator engine, CBA

48


regenerators, and new and modified process heaters in EUGs 9, 25, 26, and 27, are affected sources. Proper maintenance and operation to provide essentially complete combustion provide compliance.Section 37-37 concerns water separators that receive water containing more than 200 gallons per day of VOC. The only new equipment that may be affected by this section is the separator at the WWTP identified as Tank 478 of EUG 23. This EFR tank is subject to NESHAP FF and compliance with the alternate requirements of 40 CFR 61.352(a)(1), as identified in 40 CFR 60.693-2(a), satisfy the requirements of OAC 252:100-37-37(2). However, the section is not applicable to either of these situations because testing of the effluent has shown it to involve material with vapor pressure well below 1.5 psia, leaving it exempt from the provisions of this Section per §37-4(a).Section 37-38 affects compressors that handle VOC. Compressors handling hydrogen are not in VOC service, so proposed modifications to the recycle compressor are exempt from this rule.

OAC 252:100-39 (VOC in Non-attainment Areas) [Applicable]Part 3 affects petroleum refinery operations.Section 39-15 concerns petroleum refinery equipment leaks and is frequently referred to as LDAR, for Leak Detection and Reporting. It applies to all new and existing components that might have leaks of VOC when tested by EPA Reference Method 21 as found in the NSPS regulations of 40 CFR Part 60. For the purposes of this section, VOC with vapor pressure less than 0.0435 psia is exempt. Standards and operating procedures are set out in §39-15(c), monitoring requirements are found in §39-15(f), and recordkeeping and reporting requirements are identified in §39-15(g) and (h).Section 39-16 concerns petroleum refinery process unit turnarounds and outlines procedures to be used during the planned shutdown, inspection, repair, and restart of a unit. VOC in the unit shall be routed to a flare or vapor recovery system until the unit is blown down to pressure compatible with the control device pressure. The system may then be purged using appropriate materials. The unit may not be vented to atmosphere until unit pressure is less than 5 psig. VOC may not be emitted to the atmosphere through any control device unless it is burned in a smokeless flare or equivalent device, except for special circumstances. Written notice of the unit to be shut down, the date of shut down and the amount of VOC emissions anticipated shall be provided to AQD at least 15 days in advance. Scheduled turnarounds may be exempted from the control requirements during non-oxidant season if the required notice makes a specific request to that effect. The facility has provided the appropriate notices for past turnarounds and will remain in compliance.

Section 39-18 concerns refinery effluent water separators. The only equipment that may be affected by this section is the new separator, identified as Tank 478 in EUG 23. The section is not applicable to Tank 478 because testing of the effluent has shown it to involve material with vapor pressure well below 1.5 psia, leaving the proposed separator exempt from the provisions of this section per §39-4.

Part 5 concerns petroleum processing and storage.Section 39-30 affects petroleum liquid storage in external floating roof EFR tanks of capacity greater than 40,000 gallons located in Tulsa County. New tanks variously contain fluids with vapor pressure less than 1.5 psia and are exempt per §39-4, or are subject to either NSPS Subpart

49


Kb or MACT CC. Tanks subject to NSPS Subparts Kb are exempt from this section per §39-30(b)(3) and tanks subject to NESHAP MACT Subpart CC are exempt from this section per §39-30(b)(4). Thus, all tanks potentially subject to §39-30 are exempt.

Part 7 contains rules affecting specific processes.All subsections of 39-41 have been discussed in the TVR memorandum. The HCPE project adds no new sources to those treated in the TVR and does alter the applicability of any sources addressed in the TVR.

OAC 252:100-40 (Friable Asbestos During Demolition & Renovation Operations) [Applicable]The HCPE project may involve asbestos removal. Section 40-5 describes procedures for the proper handling of asbestos. These procedures are detailed in the Specific Conditions.

OAC 252:100-42 (Toxic Air Contaminants (TAC)) [Applicable]This subchapter regulates toxic air contaminants (TAC) that are emitted into the ambient air in areas of concern (AOC). Any work practice, material substitution, or control equipment required by the Department prior to June 11, 2004, to control a TAC, shall be retained, unless a modification is approved by the Director. Since no AOC has been designated there are no specific requirements for this facility at this time.

OAC 252:100-43 (Testing, Monitoring, and Recordkeeping) [Applicable]This subchapter provides general requirements for testing, monitoring and recordkeeping and applies to any testing, monitoring or recordkeeping activity conducted at any stationary source. To determine compliance with emissions limitations or standards, the Air Quality Director may require the owner or operator of any source in the state of Oklahoma to install, maintain and operate monitoring equipment or to conduct tests, including stack tests, of the air contaminant source. All required testing must be conducted by methods approved by the Air Quality Director and under the direction of qualified personnel. A notice-of-intent to test and a testing protocol shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests. Emissions and other data required to demonstrate compliance with any federal or state emission limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained, and submitted as required by this subchapter, an applicable rule, or permit requirement. Data from any required testing or monitoring not conducted in accordance with the provisions of this subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive use, of any credible evidence or information relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed.

The following Oklahoma Air Pollution Control Rules are not applicable to this facility.OAC 252:100-11 Alternative Reduction not requestedOAC 252:100-15 Mobile Sources not in source categoryOAC 252:100-17 Incinerators not type of emission unitOAC 252:100-23 Cotton Gins not type of emission unitOAC 252:100-24 Feed & Grain Facility not in source categoryOAC 252:100-47 Municipal Solid Waste Landfills not in source category

VIII. FEDERAL REGULATIONS

50


PSD, 40 CFR Part 52 [Applicable]Full PSD review is not applicable to this project since emission net increases are less than the significance levels. See Section VI of this memorandum for a full discussion of significance.As indicated above, Section VI of this memorandum addresses overall PSD significance, but a specific issue needs further consideration here. The facility accepted a daily limit on alkylate production under Permit No. 98-021-C, issued October 19, 2000, in order to assure netting out of a potential PSD significance situation. STRC now wishes to be released from the 5,500 BPD limit, which requires significant modification of their permit per Oklahoma Rule and needs justification. The justification is presented in some detail in Section VII (Oklahoma Rules, OAC 252:100-8) and the surrogate limit imposed under previous construction and operating permits may be released.

NSPS, 40 CFR Part 60 [Subparts A, J, Kb, GGG, and IIII Are Applicable]Subpart A (General Provisions)New flare #3 is subject to the general control device requirements of 40 CFR 60.18(b), which references two pages of requirements covering design, operating limits, and work practices.Subparts D, Da, Db, Dc (Steam Generating Units)These subparts apply to steam generating units of various sizes constructed, modified, or reconstructed after various dates. Although the boilers of EUG 8 will accept restrictions on liquid fuel use arising from the civil action, they will not be modified or reconstructed under the HCPE project and will not experience emission increases. Steam generated at some of the new units to be constructed will use waste heat from process heaters. Similarly, waste heat from the TGTU incinerators will also be used to produce steam, but this is clearly not their primary function. Neither of these processes fits the definition of steam generating unit, so the HCPE project adds no units subject to these subparts.Subpart J (Petroleum Refineries)Fluid catalytic cracking unit (FCCU) catalyst regenerators, fuel gas combustion devices (FGD), and Claus sulfur recovery plants except Claus plants producing less than 20 long tons per day are all affected facilities under this subpart. Flares may be considered to be FGDs under specific circumstances and would thus be affected facilities. With certain exceptions, the effective date for all affected facilities is June 11, 1973. The FCCU will undergo emission reduction as a result of modifications to the control systems on the regenerator vent, so it will not become subject to Subpart J. However, the FCCU will become subject to Subpart J as a result of the civil action. The HCPE project will result in construction of at least nine new FGDs. Subpart J includes limits on SO2 emissions and various monitoring, recordkeeping, and reporting requirements. All three new SRUs will be subject to Subpart J. Standards required for these equipment items may be found in Specific Conditions covering EUGs 10, 25, and 26.Subpart Kb (VOL Storage Vessels Constructed after July 23, 1984)

There are two tanks that are subject. Tank #7 for heavy straight run naphtha and a proposed storage tank for sour water have been added to EUG 5. These two tanks will meet the standards of 40 CFR 60.112b(a) with an internal floating roof (IFR) with a mechanical shoe seal, and will satisfy the requirements of §112b(a)(1)(i – ix). Tank #478 has been assigned to EUG 20. This tank is an aboveground external floating roof tank and will be used as an oil-water separator tank. It is subject to NESHAP Subpart FF (Benzene Waste Operations). Although not directly subject to

51


NSPS Subpart Kb, overlap provisions in MACT CC indicate that compliance with Subpart Kb demonstrates compliance with both FF and MACT CC.Subpart UU (Asphalt Processing and Asphalt Roofing Manufacture)Affected facilities at refineries are each asphalt storage tank and asphalt blowing still. STRC has no blowing stills. The effective date for tanks storing asphalt used for roofing only or for roofing and other purposes is November 18, 1980. The effective date for tanks storing nonroofing asphalt is May 26, 1981. The CDU, storage, and loading equipment that handle asphalt were constructed in 1949. Any work performed on these tanks since 1981 has been insufficient to meet the modification or construction criteria. Construction of a new CDU and DCU under the HCPE project will not include the construction of stills or new tanks, and will not modify any of the existing equipment.Subpart XX (Bulk Gasoline Terminals)This subpart applies to loading racks at bulk gasoline terminals for which construction or modification commenced after December 17, 1980. The four-spot rack was constructed in 1951, and is not an affected facility. As mentioned earlier in this memorandum, use of the terminal is dependent on local demand, so that any increase in production will be shipped from the refinery by pipeline, with no increase in throughput expected at the racks. Additionally, the HCPE project will not modify the existing equipment.Subpart GGG (VOC Equipment Leaks in Petroleum Refineries)A compressor is an affected facility and the group of all equipment within a process is an affected facility. The word “equipment” in the preceding sentence is defined in 40 CFR 60.591 to mean each valve, pump, pressure relief device, sampling connection system, open-ended valve or line, and flange or other connector in VOC service. Any affected facility that commences construction or modification after January 4, 1983, is subject to the requirements of this subpart. All of the modifications and new construction under the HCPE project will be subject to this subpart. Standards described in NSPS Subpart VV at 40 CFR 60.482-1 through 10 are stated in the Specific Conditions.Subpart KKK (VOC Equipment Leaks from Onshore Natural Gas Processing Plants)No natural gas processing will occur at this facility.Subpart LLL (Onshore Natural Gas Processing: SO2 Emissions)No natural gas processing will occur at this facility.Subpart NNN (VOC from SOCMI Distillation Operations)This subpart affects vent streams from distillation units, but applies to distillation units that manufacture, as products, by-products, or co-products, at least one gigagram (1,100 tons) of any of roughly 200 chemicals identified in 40 CFR 665. The subpart affects all facilities constructed, reconstructed, or modified after December 30, 1983. STRC produces several of the chemicals, but the only one that commenced production later than 1983 is propylene. Because the C3/C4 splitter reconfigure to produce propylene was a piece of equipment that could process the raw material and produce the propylene, this was not a modification per 40 CFR 60.14(e)(4). The material produced must be in an individual stream and not simply a constituent of a larger stream in order to be subject to NNN. The HCPE project is not expected to have any streams affected by Subpart NNN.Subpart QQQ (VOC from Petroleum Refinery Wastewater Systems)Affected facilities include each individual drain system, each oil-water separator, and each aggregate facility, where aggregate facility is the subject of further definition. Facilities constructed, modified, or reconstructed after May 4, 1987, are subject to the requirements of this subpart. Systems are grouped as Group 1 or Group 2 under Refinery MACT CC (q.v.), where

52


Group 1 members are those emission points to which control criteria apply. Under this division, Group 1 activities are subject to the standards of MACT CC, while Group 2 activities are subject to Subpart QQQ, if they meet the applicability criteria. An EPA Applicability Determination issued June 11, 2007, by George Czerniak indicates that if a facility identifies a Group 2 system as Group 1, and subjects it to the control standards of NESHAP Subpart FF, that system is exempt from NSPS QQQ. STRC has decided to treat all new systems as Group 1 members, making them subject to MACT CC, but not to NSPS Subpart QQQ.Subpart IIII (Stationary Compression Ignition Internal Combustion Engines)Emergency equipment to be installed, including fire pumps and generators, may be subject to this subpart. Standards found in 40 CFR 60.4205 are determined based on engine model year and cylinder displacement. Details of these small design elements is not available this far in advance.

NESHAP, 40 CFR Part 61 [Subparts M and FF Applicable]Of the pollutants listed in 40 CFR 61 (asbestos, benzene, beryllium, coke oven emissions, inorganic arsenic, mercury, radionuclides, and vinyl chloride), only asbestos and benzene may be emitted by this facility as a result of the HCPE project. Several subparts cover emissions of benzene but all product streams are less than the 10% threshold.Subpart J (Equipment Leaks) does not apply because no equipment is in “benzene service.”Subpart M (Asbestos) applies to this facility. The HCPE project may require the removal of asbestos and STRC shall abide by the applicable requirements of §61.145.Subpart Y (Benzene Storage Vessels) This facility is not an affected source.Subpart BB (Benzene Transfer Operations) This facility is not an affected source.Subpart FF (Benzene Waste Operations) This facility is a petroleum refinery and is an affected source per 40 CFR 61.340(a). Sections (b) and (c) contain requirements affecting the HCPE project, including §§61.346 (Individual drain systems) and 61.347 (Oil-water separators). STRC has requested the alternate standards of §61.352 for the oil-water separator. Sections 61.354-6 concern monitoring, recording, and reporting benzene wastes, and contain a great amount of detail on these topics.

NESHAP, 40 CFR Part 63 [Subpart CC is Applicable]Subparts F and G (SOCMI)Neither subpart is directly applicable to the refinery, but portions of MACT G are incorporated by reference in 40 CFR 63 Subpart CC, often called the refinery MACT.Subpart Q (Industrial Process Cooling Towers)This subpart applies only to cooling towers using chrome. The new towers will not use chrome.Subpart CC (Petroleum Refineries)Various process units and related emission points at petroleum refineries may be affected sources. They must be located at a plant site that is a major source per §112(a) of the Clean Air Act and they must emit or have equipment containing or contacting any of the organic HAP listed in Table 1 of the subpart. STRC is an affected facility. Following are the source categories listed in 40 CFR 63.640(c) and a summary of applicable requirements for each. (c)(1) Miscellaneous process vents from petroleum refining process units. Vents identified

as Group 1 vents are those having VOC emissions of at least 33 kilograms (73 pounds) per day from existing sources or at least 6.8 kilograms (15 pounds) per day from new sources, both measured after any final recovery device, but before any control device or discharge to

53


the atmosphere. All new process vents will be routed to the refinery fuel gas (RFG) system. Those emissions routed to the RFG system are not affected sources, per §643(d)(5).

(c)(2) Storage vessels associated with petroleum refining process units. Group 1 storage vessels are required to comply with §§63.119 through 63.121 of Subpart G except as provided for in §63.646(b) through (l). Group 1 storage vessels for an existing source are those vessels with design capacity at least 177 m3 (46,758 gallons), storing a liquid with a maximum true vapor pressure at least 10.4 kPa (1.5 psia) and annual average true vapor pressure at least 8.3 kPa (1.2 psia), and storing a liquid with an annual average organic HAP concentration greater than 4 percent by weight. Subpart G is the MACT for Process Vents, Storage Vessels, Transfer Operations, and Wastewater at Synthetic Organic Chemical Manufacturing Industries (SOCMI). Most of the exceptions are simply substitute language to properly identify references and terminology; any substantive exceptions will be identified in the Specific Conditions of this permit. The sections cited essentially repeat the language of NSPS Subpart Kb.

(c)(3) Wastewater streams and treatment operations associated with petroleum refining process units. A Group 1 wastewater stream is one with a total benzene load of at least 10 megagrams (Mg) per year (11 TPY), a flow of at least 0.02 liters per minute (0.32 gph), a benzene concentration of at least 10 ppm, and not exempt from the control requirements of NESHAP Subpart FF. STRC’s wastewater stream exceeds 10 Mg per year and is subject to 40 CFR 61 FF. Individual streams may be exempted from control requirements if they contain more than 10% water by volume, provided that the total benzene content of such exempted streams does not exceed 6 Mg per year. Exemptions of such streams must be demonstrated and documented.

(c)(4) Equipment leaks from petroleum refining process units. The standards for all equipment are found in 40 CFR 60 Subpart VV, with certain minor exceptions. Among these are the necessary corrections to definitions of organic HAP as found in MACT CC and the requirement that all records be maintained for at least five years. Exceptions as to new sources, hydrogen service, and others are described in the Specific Conditions.

Subpart UUU (Petroleum Refineries – Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Plant Units)The FCCU catalyst regeneration flue vent is subject to metal and organic HAP emission standards described in §§1564 and 1565 of MACT UUU. Because the FCCU is not currently subject to NSPS Subpart J, the facility chooses to demonstrate compliance using Option 3 of Table 1, which requires that emissions of nickel not exceed 0.029 lbs/hour. Catalytic reforming unit vents are subject to organic HAP emission limits during depressuring and purging events, which includes depressurization, purging, coke burn, catalyst rejuvenation, and reduction or activation purge. The requirements outlined in Table 15 of the MACT are satisfied by compliance with OAC 252:100-39-16, which contains procedures for such events. The requirements of Table 22 Option 3 are met by monitoring HCl concentration. The FCCU will become subject to NSPS Subpart J upon issuance of the civil action and the regenerator vent will be subject to the PM, CO, and SO2 standards, monitoring, recordkeeping, and reporting of Subpart J. All SRUs are subject to NSPS Subpart J, compliance with which satisfies the requirements of MACT UUU.Subpart ZZZZ (Stationary Reciprocating Internal Combustion Engines {RICE}) affects RICE rated at 500 bhp or more. Regardless of the final size of the fire pump or electrical generator

54


engines, they are all emergency-use engines and exempt from all but initial notification provisions of MACT ZZZZ per 40 CFR 63.6590(b)(1).Subpart DDDDD (Industrial, Commercial, and Institutional Boilers and Process Heaters) EPA is planning to issue guidance or a rule on what actions applicants and permitting authorities should take regarding MACT determinations under either Section 112(g) or Section 112(j) for sources that were affected sources under Subpart DDDDD and other vacated MACTs. It is expected that the guidance or rule will establish a new timeline for submission of section 112(j) applications for vacated MACT standards. At this time, AQD has determined that a 112(j) determination is not needed for sources potentially subject to a vacated MACT, including Subpart DDDDD. This permit may be reopened to address Section 112(j) when necessary.

CAM, 40 CFR Part 64 [Not Applicable to this Project]Compliance Assurance Monitoring (CAM) as published in the Federal Register on October 22, 1997, applies to any pollutant specific emission unit at a major source that is required to obtain a Title V permit, if it meets all of the following criteria.

It is subject to an emission limit or standard for an applicable regulated air pollutant It uses a control device to achieve compliance with the applicable emission limit or standard It has potential emissions, prior to the control device, of the applicable regulated air

pollutant of 100 TPY

None of the sources planned under the HCPE project satisfies these criteria.

Accidental Release Prevention, 40 CFR Part 68 [Applicable]Naturally occurring hydrocarbon mixtures, prior to entry into a natural gas processing plant or a petroleum refining process unit, including condensate, crude oil, field gas, and produced water, are exempt for the purpose of determining whether more than a threshold quantity of a regulated substance is present at the stationary source. Listed materials produced and held for sale as fuel are also exempt. STRC filed a Risk Management Plan with the EPA on June 21, 1999, and filed a revised and updated plan on June 21, 2004. EPA’s file number is 1000 0014 6567.STRC will file any amendments or modifications that may be required by the HCPE project.

Stratospheric Ozone Protection, 40 CFR Part 82 [Applicable]These standards require phase out of Class I & II substances, reductions of emissions of Class I & II substances to the lowest achievable level in all use sectors, and banning use of nonessential products containing ozone-depleting substances (Subparts A & C); control servicing of motor vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations which meet phase out requirements and which maximize the substitution of safe alternatives to Class I and Class II substances (Subpart D); require warning labels on products made with or containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons (Subpart H).Subpart A identifies ozone-depleting substances and divides them into two classes. Class I controlled substances are divided into seven groups; the chemicals typically used by the manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform

55


(Class I, Group V). A complete phase-out of production of Class I substances is required by January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs. Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances, scheduled in phases starting by 2002, is required by January 1, 2030.This facility does not utilize any Class I & II substances.

IX. COMPLIANCE

Tier Classification and Public ReviewThis application has been classified as Tier II based on the request for construction at an existing major source. Public notice of filing of this application was published in the Tulsa World on September 19, 2007. Copies of the application were made available for public review at the DEQ Regional Office at Tulsa and at the DEQ Air Quality Office in Oklahoma City. Notice of the availability of a Draft permit will also have to be published. This facility is not located within 50 miles of the border with a contiguous state.

Fee PaidModification at a major source construction permit fee of $1,500.

X. SUMMARY

The applicant has demonstrated the ability to comply with applicable state and federal air pollution control rules and regulations. Ambient air quality standards are not threatened at this site. There are no active Air Quality compliance and enforcement issues concerning this facility. Issuance of the permit is recommended, contingent upon public and EPA review.

56

DRAFT

PERMIT TO CONSTRUCTAIR POLLUTION CONTROL FACILITY

SPECIFIC CONDITIONS

Sinclair Tulsa Refining Company Permit Number 2007-005-C (M-1)Tulsa RefineryHeavy Crude Processing Expansion Project

The permittee is authorized to construct in conformity with the specifications submitted to the Air Quality Division (AQD) on September 7, 2007, with additional information submitted in response to questions and during visits to the facility during the intervening period. The Evaluation Memorandum dated January 16, 2008, explains the derivation of applicable permit requirements and estimates of emissions; however, it does not contain operating limitations or permit requirements. Commencing construction and continuing operations under this permit constitutes acceptance of, and consent to, the conditions contained herein.

SPECIFIC CONDITION 1

The permittee shall be authorized to operate the facilities proposed in this permit continuously (24 hours per day, every day of the year) subject to the following conditions. Records necessary to show compliance with each of the requirements below must be maintained.

[OAC 252:100-8-6(a)(1)]

a. The following fuel combustion units have heat input limits specified below. Compliance with hourly heat inputs is shown by dividing the monthly heat input by the hours of operation for the month. The “authorization” column indicates the permit under which each limit was set. “R” refers to the TV renewal Permit No. 2007-005-TVR, “H” refers to new equipment under the current construction Permit No. 2007-005-C (M-1), “M” refers to the situation in which a heater was previously authorized at a different level or had no previous limit (grandfathered) and has accepted limits under this permit, and “26” refers to currently open construction Permit No. 98-021-C (M-26), often referenced as the low sulfur diesel project.

Heater EUG Heat Input LimitMMBTU/hr (HHV) Authorization

DCU Coker Heater 26 221.0 HADU#2 Heater 26 283.0 HVDU#2 Heater 26 110.0 HHCU Reactor Charge Heater 25 92.0 HHCU Fractionator Feed Heater 25 86.0 HH2 Plant Heater 26 604.0 HDHTU Reactor Charge (1H-101) 27 55.0 26FCCU Charge Heater (B2) 27 73.3 MCCR Charge Heater (10H-101) 27 67.1 MCCR #1 Interheater (10H-113) 26 121.6 MCCR #2 Interheater-1 (10H-102) 27 123.3 M

SPECIFIC CONDITIONS 2007-005-C (M-1) DRAFT

Heater EUG Heat Input LimitMMBTU/hr (HHV) Authorization

CCR #2 Interheater-2 (10H-103) 27 30.5 MCCR Stabilizer Reboiler (10H-104) 27 64.5 MUnifiner Heater (H-1) 9 45.9 MNHDS Charge (02H-001) 25 39.0 26NHDS Stripper Reboiler (02H-002) 25 44.2 26Scanfiner Charge (12H-101) 25 25.2 R

b. The following units have the noted TPY emission limits. In most cases, compliance with these limits is met by throughput limits and appropriate CEMs. [OAC 252:100-8-6]

EUG Source PM10 NOX SO2 VOC CO10 TGTU#2 0.5 9.6 24.6 0.3 15.910 TGTU#3 0.8 5.5 N/A 0.4 5.510 TGTU#4 0.8 5.5 N/A 0.4 5.510 TGTU#5 0.8 5.5 N/A 0.4 5.5

10 TGTU#3/#4/#5 (SO2 Bubble) N/A N/A 205.4 N/A N/A

c. STRC will directly measure stack flow and SO2 concentration at TGTU#3, TGTU#4 and TGTU#5 to determine compliance with the following SO2 bubble emission limit: For purposes of clarity, the first 365-day SO2 bubble compliance date shall be 365 days after start-up of TGTU#3, TGTU#4 or TGTU#5.

SO2 365-day rolling average205.4 tpy

d. The FCCU regenerator process vent is subject to the following emission limits. For purposes of clarity, the first 365-day compliance date for CO shall be 365 days after start-up of the FCCU scrubbing system. The first 365-day compliance demonstration for NOX

and SO2 is December 31, 2010.

1.SO2 7-day rolling average SO2 365-day rolling average

50 ppmvd (0% O2) 25 ppmvd (0% O2)

2.NOx 7-day rolling average NOx 365-day rolling average

40 ppmvd (0% O2) 20 ppmvd (0% O2)

2


3.PM1

0.5 lb PM / 1000 lb coke burnoff1 PM is non-sulfate particulate matter, as determined by 40 CFR 60 Appendix A Method 5F

4.CO 1-hour average CO 365-day rolling average500 ppmvd (0% O2) 100 ppmvd (0% O2)

SPECIFIC CONDITION 2Standards for affected Emission Unit Groups (EUG). Only those EUGs to which equipment will be added or deleted or for which conditions or limits will be modified are listed. EUGs that will be unchanged by the current project are not listed. [OAC 252:100-8-6(a)]


These storage vessels are regulated under 40 CFR 63 Subpart CC (MACT CC) Group 2 Storage Vessels and are limited to the existing equipment as it is. Due to the overlap provisions of CC (§63.640(n)), this list includes any Group 2 storage vessels that are also regulated under NSPS Subparts K or Ka but are not required to meet any control standards, as they must meet these requirements (§640(n)(7)). Storage vessels required to meet control requirements under NSPS Subparts K and Ka are required to comply only with those subparts (§640(n)(6)) and are not included in this list.

Tank No. Point ID


Capacity9 6242 2005 48' 150' 151,10010 6180 1910 30' 96' 37,50011 6181 1910 30' 96' 37,50015 6244 1949 48' 140' 130,00016 6245 2003 48' 150' 151,10017 6183 1910 30' 96' 37,50019 6247 1922 30' 52' 11,30034 6252 1922 30' 53' 11,70036 6253 1922 30' 53' 11,50039 6254 1922 35' 28' 3,29040 6185 1923 40' 32' 6,10041 6248 1922 35' 29' 3,90063 TBD 1973 18' 20' 1,000102 6189 1907 30' 96' 37,500103 6190 1907 30' 96' 37,500104 6255 1907 30' 96' 37,500107 6257 1949 48' 140' 131,000108 6191 1907 30' 96' 37,500

1

3


Tank No. Point ID


Capacity109 6192 1907 30' 96' 37,500110 6193 1907 30' 96' 37,500111 6194 1907 30' 96' 37,500112 6195 1907 30' 96' 37,500115a TBD 2007 48’ 150’ 150,000115b TBD 2007 48’ 150’ 150,000116 6199 1907 30' 96' 37,500117 6200 1907 35' 115' 63,500118 6201 1907 30' 96' 37,500119 6202 1907 30' 96' 37,500122 6203 1907 30' 96' 37,500123 6260 1907 30' 96' 37,500124 6261 1907 30' 96' 37,500125 6262 1907 30' 96' 37,500126 6263 1907 30' 96' 37,500129 6204 1949 36' 35' 6,100130 6205 1949 36' 35' 6,100131 6265 1907 30' 96' 37,500132 6206 1907 30' 96' 37,500451 6229 1930 30' 53' 11,700452 6230 1930 30' 53' 11,700603 23132 1951 30' 20' 1,617

Black Oil TBD Proposed 47’ 175’ 197,000Biosolids TBD Proposed 29.6’ 16’ 1,000Sludge TBD Proposed 29.6’ 16’ 1,000

a. Fixed roof tanks in EUG 3 are subject to only the recordkeeping requirements of MACT Subpart CC for Group 2 storage vessels, as follow. [40 CFR 63.654(i)(1)(iv)]

1. Readily accessible records showing the dimensions of each vessel and an analysis of the capacity of each vessel shall be maintained for the life of the vessel.

[40 CFR 63.123(a)]2. Data, assumptions, and procedures used in determining Group 2 status for these

tanks shall be documented. [40 CFR 63.646(b)(1)]

EUG 4 MACT CC Wastewater Tanks

These storage vessels are regulated under 40 CFR 63 Subpart CC (MACT CC) as wastewater management units and are limited to the existing equipment as it is. Due to the overlap provisions of MACT CC, the requirements of 40 CFR 61 Subpart FF (BWON), and 40 CFR 60 Subpart QQQ (NSPS QQQ), these vessels are required to comply with 40 CFR 60 Subpart Kb to meet the applicable standards under MACT CC, BWON, and NSPS QQQ.

4


Tank No.

Point ID


Capacity (bbl)13 6243 1976 40' 116' 75,25018* 6246 1910 30' 96' 37,50052 22638 1972 36' 40' 7,50056 36193 1992 16' 25' 1,40057 36193 1992 16' 25' 1,40067 23134 1992 12' 10' 165140 23134 1971 16' 36' 2,900369 23134 1960 23' 12' 480370 23134 1967 23' 12' 480

* Also listed in EUG 1

a. The permittee shall comply with the applicable sections of MACT CC, Wastewater Provisions of 63.647 for the affected storage tanks. [40 CFR 63.640-654]

1. The permittee shall comply with the requirements of § 61.340 through 61.355 of 40 CFR 61 Subpart FF.To accomplish this, the storage tanks will: [40 CFR 63.647(a)]

A. Comply with the Alternative Standards for Storage Tanks of 40 CFR 61.351 and 40 CFR 60 Subpart Kb;

B. Meet the requirements of 40 CFR 61.343 for Tanks; orC. Be counted as uncontrolled and included in the 6 BQ calculation under

61.355(k).

b. Recordkeeping is required per 40 CFR 61.356. [40 CFR 63.654(a)]c. Reporting is required per 40 CFR 61.357. [40 CFR 63.654(a)]

EUG 5 NSPS Subpart Kb Storage Vessels - Internal Floating Roof (IFR)

These storage vessels are regulated under 40 CFR 60, Subpart Kb (NSPS) and are limited to the existing equipment as it is. Due to the overlap provisions of MACT CC, these vessels are required to comply only with NSPS Kb.

Tank No.

Point ID


Capacity4 23129 2003 48' 134' 120,6007 TBD Proposed 47' 175' 200,00031 6250 1998 48' 48' 15,000472 TBD 2007 48’ 150’ 140,000605 6278 1951* 32' 30' 3,400

SWS TBD Proposed 48' 150' 150,000*Built as a fixed roof in 1951, converted to IFR in 1987, subject to Kb 1992.

5


a. IFR Tanks in EUG 5 are subject to NSPS Kb. The “overlap” provisions of MACT CC [§63.640(n)(1)] state that these storage vessels are required only to comply with the provisions of Kb.

1. Mechanical design and operating specifications. [40 CFR 60.112b(a)(1)]2. Compliance testing and procedures. [40 CFR 60.113b(a)]3. Monitoring provisions [40 CFR 60.116b]

b. Tanks in this EUG may be used in MACT CC Group 1 wastewater service as they comply with the Alternative Standards for Storage Tanks of 40 CFR 61.351 and 40 CFR 60 Subpart Kb.

c. Recordkeeping requirements include inspection results, dimensions and capacity of the storage vessels, VOL stored, period of storage, and maximum TVP.

[40 CFR 60.115b and 116b]

d. Reporting requirements include semi-annual reporting of deviations during inspections, notifications, and initial certifications. [40 CFR 60.116b]


Only the Unifiner heater has a heat input limit and is subject to NSPS Subhpart J. Other equipment is limited to the existing equipment as it is. This EUG contains fuel-burning equipment with heat input less than 100 MMBTUH. These sources were proposed for regulation under 40 CFR 63 Subpart DDDDD (MACT DDDDD), but that MACT has been vacated. This permit may be reopened to address Section 112(j) when necessary.

Source Point ID

Manu-facturer Burner Type No. of

BurnersMMBTUH

(HHV)Heater Date

FCCU Air Heater (B-1)1 6159 M W

Kellogg Peabody M-18 1 38.42 1949

Unifiner Heater (H-1) 6167 Refinery

EngrJZ-UOV-4 Twin

head 12 45.9 1955

1 vents to FCCU regenerator stack.2 estimated capacities per Sinclair; June 1998 DEQ facility inspection; not a permit limit.

a. Compliance with the SO2 limit for the Unifiner heater is demonstrated by compliance with the 0.1 gr/dscf H2S limit imposed on fuel gas combustion devices by NSPS Subpart J and fuel input. Compliance with the heat input limit will be calculated by using the monthly fuel input to calculate hourly average heat input. [OAC 252:100-8-6]

b. Compliance with the NOX limit for the Unifiner heater is demonstrated by performance testing. Compliance with this limit is demonstrated by heat input, using monthly fuel input to calculate hourly averages multiplied by the emission factor. [OAC 252:100-8-6]

c. Compliance with CO, PM10, and VOC limits for the Unifiner heater is demonstrated by throughput, since the factors used are all AP-42 Tables 1.4-1 and 2. Compliance with these

6


limits is demonstrated by heat input to the unit, using monthly fuel inputs to calculate hourly averages multiplied by the emission factor. [OAC 252:100-8-6]

d. These sources were to be regulated under 40 CFR 63 Subpart DDDDD (MACT DDDDD), but this rule has been vacated. Per 40 CFR 63.7506(b), these heaters would be exempt from all regulations except the initial notification requirements under 40 CFR 63 Subpart A.

[40 CFR 63 Subpart DDDDD]

e. The Unifiner heater must comply with 40 CFR 60 Subpart J, and shall comply with all applicable provisions including but not limited to: [40 CFR 60, Subpart J]

1. §60.104 Standards for sulfur dioxide – (a)(1);2. §60.105 Monitoring of operations – (a)(4), (e)(3)(ii);3. §60.106 Test methods and procedures – (e).

[40 CFR 60, Subpart J and OAC 252:100-43]

f. All fuel-burning equipment shall be operated and maintained to minimize emissions of VOC. Such conditions mean adherence to manufacturer’s recommendations or to good operating and maintenance practices, and that temperature and sufficient air to provide essentially complete combustion are supplied. [OAC 252:100-37-36]

g. Recordkeeping is required as follows.

1. NSPS J records as required under 40 CFR 60 Subpart A. [40 CFR 60.7]2. H2S CEM to show compliance with SO2 emission limits for specified heaters.

[OAC 252:100-43]3. NOX performance tests for specified heaters. [OAC 252:100-43]4. Monthly fuel use for each piece of fuel-burning equipment in EUG 9 with a heat input

limit shall be maintained, along with a calculation demonstrating that the average hourly firing rate of each item is not greater than the heat input rate set forth in SC #1. These records shall be maintained on a 12-month rolling basis. [OAC 252:100-43]

h. Reporting is required for the Unifiner heater on a semi-annual basis, including the information required in NSPS Subpart A. [40 CFR 60.107 and 60.7]

EUG 10 Sulfur Recovery Units

SRU #2 became operational in June 2006. STRC anticipates SRU#3, SRU#4 and SRU#5 will become operational in 2009. Each unit has a tail gas treating unit (TGTU) utilizing water based scrubbing technology to control SO2 emissions in its exhaust. The SRU#2 incinerator is rated at 12.1 MMBTUH and exhausts 6,450 ACFM at 780F through a 2.5 diameter stack at 101 above grade. SRU#3, SRU#4 and SRU#5 incinerators are rated at 18.0 MMBTUH each, but stack information for these proposed units is not yet available.

a. SRU#2, SRU#3, SRU#4 and SRU#5 are subject to NSPS J and shall comply with all applicable provisions including but not limited to: [40 CFR 60 Subpart J]

1. §60.104 Standards for sulfur dioxide – (a)(2)(i);2. §60.105 Monitoring of operations – (a)(5)(i & ii) & (e)(4)(i);

7


3. §60.106 Test methods and procedures – (a) & (f)(1 & 3).

b. SRU#2, SRU#3, SRU#4 and SRU#5 are subject to NESHAP Subpart UUU and shall comply with all applicable provisions by the dates specified in § 63.1563(b). [40 CFR 63 Subpart UUU]

1. §63.1568 What are my requirements for HAP emissions from sulfur recovery units? – (a)(1), (b)(1, 3, 4, 5, 6, & 7), & (c)(1 & 2);

2. §63.1569 What are my requirements for HAP emissions from bypass lines? – (a)(1 & 3), (b)(1-4), & (c)(1 & 2);

3. §63.1570 What are my general requirements for complying with this subpart? – (a) & (c-g);

4. §63.1571 How and when do I conduct a performance test or other initial compliance demonstration? – (a) & (b)(1-5);

5. §63.1572 What are my monitoring installation, operation, and maintenance requirements? – (a)(1-4) & (d)(1-2);

6. §63.1574 What notifications must I submit and when? – (a)(2) & (f)(1, 2(i), 2(ii), 2(viii), 2(ix), & 2(x));

7. §63.1577 What parts of the General Provisions apply to me?

c. Recordkeeping is required as follows.

1. Per NSPS Subparts A and J, including, but not limited to, CEMs information and periods of excess emissions and monitor unavailable time.

[40 CFR 60.107 and 60.7]2. Per MACT Subparts A and UUU, including, but not limited to, CEMs information,

periods of excess emissions, SSM records, performance and RATA tests, and OMM records. [40 CFR 63.1576, 63.6, 63.8 and 63.10]

d. Reports are required as follows.

1. Per NSPS Subparts A and J, including, but not limited to, semi-annual compliance reports and CEMs excess emission report. [40 CFR 60.107 and 60.7]

2. Per MACT Subparts A and UUU, including, but not limited to, semi-annual compliance reports, SSM reports, and CEMs excess emission reports.

[40 CFR 63.1575, 63.6, 63.8, and 63.10]

EUG 11 FCCU

Although minor changes will occur under the HCPE project, there is no change to permit requirements. Modifications to be performed under the Civil Action are not considered to be part of the HCPE project permitting process.

8


EUG 12 Flares

There are no emission limits applied to this EUG under Title V but it is limited to the existing equipment as it is. Sources in other EUGs under various regulations utilize the flares as air pollution control devices. Monitoring, recordkeeping, and reporting requirements related to flare pilot monitoring are found in each affected EUG, and not included here.

Flare Make/Model Height (ft) Date#1 Zink/STF-SA-18 230 1949#2 Zink/STF-SA-36-C 250 1972#3* Proposed TBD Proposed

*For emergency use

a. The flares are regulated under 40 CFR 60 Subpart A and 40 CFR 63 Subpart A. Requirements include, but are not limited to:

1. General control device requirements [40 CFR 60.18]2. Control device requirements [40 CFR 63.11]


Equipment leaks from the entire refinery, including but not limited to the process units, storage tanks, and the terminal are included in this Group. Distillate fuel oil truck deliveries to storage tanks are accounted for under this EUG. There are no emission limits applied to this EUG under Title V but it is limited to the existing equipment as it is. Because all equipment leaks are subject to the LDAR requirements of OAC 252:100-39-15 and some are also subject to LDAR requirements of NSPS GGG or to the LDAR requirements of MACT CC, the permittee will comply by meeting the following conditions. Units subject to NSPS GGG include the CDU, J-50 (wet gas compressor), Unifiner, POLY, Scanfiner, and NHDS, under Permit No. 2007-005-TVR. [40 CFR 60.590 and OAC 252:100-39-15]

a. All affected equipment, in HAP service (contacting >5% by weight HAP), shall comply with NESHAP, 40 CFR 63, Subpart CC. The permittee shall comply with the applicable sections for each affected component. [40 CFR 63, Subpart CC]

1. §63.642 General Standards – (c), (d)(1), (e), & (f);2. §63.648 Equipment Leak Standards – (a), (b), (c), & (e-i);3. §63.654 Reporting and Recordkeeping Requirements – (d), & (f-h).

9


b. Equipment determined not to be in HAP service (contacting <5% by weight HAP) and which is in VOC service (contacting >10% by weight VOC) shall comply with the requirements of NSPS 40 CFR 60, Subpart GGG. [40 CFR 60, Subpart GGG]

1. §60.592 Standards (a-e).2. §60.593 Exceptions (a-e).3. Subconditions b.1 and b.2 reference the standards described in §60.592, which are

taken from NSPS Subpart VV §§60.482-1 through 60.482-10. Test methods and procedures, record-keeping, and reporting are described in §§60.485, 486, and 487, respectively.

c. Certain equipment is regulated as described in OAC 252:100-39-15.

d. Permittee shall maintain records identifying which components are regulated under each requirement. Separate records shall not be required if all components are treated by permittee as subject to the most stringent requirements.

e. Recordkeeping provisions for these regulations are very extensive and are not summarized here. Records for components covered by the above requirements are found in the applicable rule. [40 CFR 63.654, 40 CFR 60.486, and OAC 252:100-39-15]

f. Reporting provisions for these regulations are very extensive and are not summarized here. A single report may be submitted to comply with all of the reporting requirements above, so long as all reporting requirements for each regulation are included.

[40 CFR 63.654, 40 CFR 60.487, and OAC 252:100-39-15]

g. For purposes of confirming the reduction in VOC emissions taken as part of the PSD netting process, a tabulation of all drains retrofitted with control shall be provided with the application for operating permit following completion of the HCPE project.


The wastewater system consists of several different sewer systems and the wastewater treatment plant, as described in Part N of Section II (Facility Description) above. The facility is subject to 40 CFR 61 Subpart FF (BWON) and 40 CFR 63 Subpart CC (MACT CC), while areas of the refinery are subject to 40 CFR 60 Subpart QQQ (NSPS QQQ). Due to the overlap regulations under MACT CC (40 CFR 63.640(o)), all Group 1 wastewater streams also regulated under NSPS QQQ must meet only MACT CC standards, while all Group 1 wastewater streams also regulated under BWON must meet only BWON standards. A June 11, 2007, EPA Applicability Determination (AD) issued to BP Products North America and signed by George Czerniak, states that a Group 2 wastewater stream may be treated under BWON exclusively if the facility declares it to be Group 1 and satisfies the requirements of Subpart FF for the stream. Given this AD, the entire SCAN Unit, entire NHDS Unit, entire DCU, entire CDU#2, entire HCU, entire SRU#3, entire SRU#4, entire SRU#5, and new construction at the DHTU and CCR are subject to BWON. The entire SRU/TGTU #2 is subject to NSPS QQQ, and therefore, only to MACT CC. Aggregated emission points are identified as Point ID 13409. The proposed Dissolved Nitrogen Flotation (DNF) system shall be controlled by a Regenerative Thermal Oxidizer (RTO) designed

10


to achieve a 97.7% VOC destruction efficiency. RTO performance shall be monitored per the standards of 40 CFR 61.349.a. The Refinery is subject to NESHAP, 40 CFR 61, Subpart FF and shall comply with all

applicable requirements. [40 CFR 61, NESHAP, Subpart FF]

1. § 61.342 Standards: General.2. § 61.343 Standards: Tanks.3. § 61.344 Standards: Surface Impoundments.4. § 61.345 Standards: Containers.5. § 61.346 Standards: Individual drain systems.6. § 61.347 Standards: Oil-water separators.7. § 61.348 Standards: Treatment processes.8. § 61.349 Standards: Closed-vent systems and control devices.9. § 61.350 Standards: Delay of repair.10. § 61.351 Alternative standards for tanks.11. § 61.352 Alternative standards for oilwater separators.12. § 61.353 Alternative means of emission limitation.13. § 61.354 Monitoring of operations.14. § 61.355 Test methods, procedures, and compliance provisions.15. § 61.356 Recordkeeping requirements.16. § 61.357 Reporting requirements.

b. These records shall be maintained in accordance with the recordkeeping requirements under 40 CFR 61.356.

c. These reports shall be maintained in accordance with the reporting requirements under 40 CFR 61.357.


Cooling towers are considered to be trivial sources for Title V purposes, so the following table is shown only for the sake of completeness.

Number Point ID Purpose Date3 25053 Cooling water for the FCCU 19493a 25054 Cooling water for SCANfiner 2003

4 and 5 25055 Cooling water for the CDU 19497 25056 Cooling water for the ALKY, POLY & ISOM 20078 25057 Cooling water for the OIF 1972

Coker Cooling Tower TBD Cooling water for the DCU ProposedHCU Cooling Tower TBD Cooling water for the HCU Proposed

11


EUG 20 NSPS Kb Tanks (EFR) - MACT CC Group 1 Wastewater

These storage vessels are regulated under 40 CFR 60, Subpart Kb and are limited to the existing equipment as it is. Due to the overlap provisions of MACT CC, these vessels are required to comply only with NSPS Subpart Kb, except as noted in 40 CFR 63.640(n)(8).

Tank No.

Point ID


Capacity474 15940 1997 48' 106' 73,000475 15941 1997 48' 106' 73,000476 36590 2005 45' 55’ 15,000478 TBD Proposed 48' 106' 73,000

a. EFR Tanks in EUG 20 are subject to NSPS Subpart Kb. The “overlap” provisions of MACT CC [§63.640(n)(1)] state that these storage vessels are required only to comply with the provisions of Kb, with the modifications noted in 63.640(n)(8).

1. Mechanical design and operating specifications. [40 CFR 60.112b(a)(2)]2. Compliance testing and procedures. [40 CFR 60.113b(b)]3. Monitoring provisions [40 CFR 60.116b]

b. Tanks in this EUG may be used in MACT CC Group 1 wastewater service as they comply with the Alternative Standards for Storage Tanks of 40 CFR 61.351 and 40 CFR 60 Subpart Kb.

c. The sliding cover shall be in place over the slotted-guidepole opening through the floating roof at all times except when the sliding cover must be removed for access. Visually inspect the deck fitting for the slotted guidepole at least once every 10 years and each time the vessel is emptied and degassed. If the slotted guidepole deck fitting or control device(s) have defects, or if a gap or more than 0.32 centimeters (1/8 inch) exists between any gasket required for control of the slotted guidepole deck fitting and any surface that it is intended to seal, such items shall be repaired before filling or refilling the storage vessel with regulated material. Tanks out of hydrocarbon service, for any reason, do not have to have any controls in place during the time they are out of service.

[EPA’s Storage Tank Emission Reduction Partnership Agreement]

d. Recordkeeping requirements include:

1. Inspection results, dimensions and capacity of the storage vessels, VOL stored, period of storage, and maximum TVP. [40 CFR 60.115b and 116b]

2. Records sufficient to demonstrate that no more than one of Tanks 474 and 475 is storing VOL at any time. [OAC 252:100-8]

e. Reporting requirements include semi-annual reporting of deviations during inspections, notifications, and initial certifications. [40 CFR 60.116b and 63.640(n)(8)(v)]

12


EUG 25 New Fuel-Burning Equipment with Heat Input < 100 MMBTUH

This EUG contains new fuel-burning equipment with heat input less than 100 MMBTUH. These sources were proposed for regulation under 40 CFR 63 Subpart DDDDD (MACT DDDDD), but that MACT has been vacated. This permit may be reopened to address Section 112(j) when necessary.

Source Point ID

Manu-facturer

Burner Type

No. of Burner

s

MMBTUH (HHV)

Const. Date

NOx lb/MMBTU

(HHV)Scanfiner Charge Heater (12H-101) 23133 Tulsa

Heaters, IncZeeco

Low NOX3 25.2 2004 0.07

NHDS Charge Heater (02H-001) 36580 Tulsa

Heaters, IncZeeco

Low NOx 4 39.0 2006 0.05

NHDS Stripper Reboiler

(02H-002)36584 Tulsa

Heaters, IncZeeco

Low NOx 6 44.2 2006 0.05

HCU Reactor Charge Heater * TBD

Optimized Process

FurnacesTBD TBD 92.0 Proposed 0.035

HCU Fractionator Feed Heater * TBD

Optimized Process

FurnacesTBD TBD 86.0 Proposed 0.035

* The HCU Reactor Charge and the HCU Fractionator Heaters will discharge to atmosphere through a common stack.

a. Compliance with SO2 limits is demonstrated by compliance with the 0.1 gr/dscf H2S limit imposed on fuel gas combustion devices by NSPS Subpart J and fuel input. Compliance with the fuel input limits will be calculated by using the monthly fuel input to calculate hourly average heat input.

b. Compliance with the NOX limits is demonstrated by performance testing of the low-NOX

burners. Compliance with these limits is demonstrated by heat input to each unit, using monthly fuel inputs to calculate hourly averages.

c. Compliance with CO, PM10, and VOC limits are demonstrated by throughput, since the factors used are in accordance with AP-42 Tables 1.4-1 and 2. Compliance with these limits is demonstrated by heat input to each unit, using monthly fuel inputs to calculate hourly averages.

d. All heaters must comply with 40 CFR 60 Subpart J, and shall comply with all applicable provisions including but not limited to: [40 CFR 60, Subpart J and OAC 252:100-43]

1. §60.104 Standards for sulfur dioxide – (a)(1)2. §60.105 Monitoring of operations – (a)(4), (e)(3)(ii)3. §60.106 Test methods and procedures – (e)

13


e. All heaters were to be regulated by 40 CFR 63 Subpart DDDDD, but this rule has been vacated. As proposed, the subpart would have required compliance with all applicable provisions including, but not limited to the following.

1. §63.7480 - .7495 What This Subpart Covers2. §63.7499 - .7500 Emission Limits and Work Practice Standards3. §63.7505 - .7507 General Compliance Requirements4. §63.7510 - .7530 Testing, Fuel Analyses, and Initial Compliance Requirements5. §63.7535 - .7541 Continuous Compliance Requirements6. §63.7545 - .7560 Notifications, Reports, and Records7. §63.7565 - .7575 Other Requirements and Information

f. Compliance with the H2S destruction efficiency criterion and H2S emission limitation of OAC 252:100-31-26 concerning the SCANfiner process unit shall be demonstrated using the SRU CEMS or through engineering calculations and judgment. [OAC 252:100-31]

g. Recordkeeping is required as follows:


[OAC 252:100-8]3. NOx performance tests for specified heaters. [OAC 252:100-8]4. Monthly fuel use for each piece of fuel-burning equipment in EUG 25 with a heat input

limit shall be maintained, along with a calculation demonstrating that the average hourly firing rate of each item is not greater than the heat rate set forth in SC #1. These records shall be maintained on a 12-month rolling basis. [OAC 252:100-8]

h. Reporting is required for NSPS Subpart J heaters on a semi-annual basis, including the information required in NSPS Subpart A. [40 CFR 60.107 and 60.7]

EUG 26 New Fuel-Burning Equipment with Heat Input ≥ 100 MMBTUH

These sources are all regulated under NSPS J. Applicability of proposed NSPS Ja will need to be determined when the rule becomes final.

Source Point ID Manufacturer Burner

TypeNo. of

BurnersMMBTUH

(HHV)Const. Date

NOx lb/MMBTU

(HHV)CCR #1 Interheater (10H-113)

TBD Tulsa Heaters, Inc

Zeeco Low NOx

18 121.6 2005 0.05

DCU Coker Heater TBD Foster Wheeler TBD TBD 221.0 Proposed 0.075

ADU#2 Heater TBD TBD TBD TBD 283.0 Proposed 0.035VDU#2 Heater TBD TBD TBD TBD 110.0 Proposed 0.035H2 Plant Heater TBD Technip TBD TBD 604.0 Proposed 0.045

14


a. Compliance with SO2 limits is demonstrated by compliance with the 0.1 gr/dscf H2S limit imposed on fuel gas combustion devices by NSPS Subpart J and fuel input. Compliance with the fuel input limits will be calculated by using the monthly fuel input to calculate hourly average heat input.

b. Compliance with the NOX limits is demonstrated by performance testing of the low-NOX


c. Compliance with CO, PM10, and VOC limits is demonstrated by throughput, since the factors used are in accordance with AP-42 Tables 1.4-1 and 2. Compliance with these limits is demonstrated by heat input to each unit, using monthly fuel inputs to calculate hourly averages.

d. All heaters must comply with 40 CFR 60 Subpart J, and shall comply with all applicable provisions including but not limited to: [40 CFR 60, Subpart J and OAC 252:100-43]

1. §60.104 Standards for sulfur dioxide – (a)(1)2. §60.105 Monitoring of operations – (a)(4), (e)(3)(ii)3. §60.106 Test methods and procedures – (e)

e. All heaters were to be regulated by 40 CFR 63 Subpart DDDDD, but this rule has been vacated. As proposed, the Subpart would have required compliance with all applicable provisions including, but not limited to the following. [40 CFR 63 Subpart DDDDD]


f. Compliance with the H2S destruction efficiency criterion and H2S emission limitation of OAC 252:100-31-26 concerning the SCANfiner process unit shall be demonstrated using the SRU CEMS or through engineering calculations and judgment. [OAC 252:100-31]

g. Recordkeeping is required as follows.


[OAC 252:100-8]3. NOX performance tests for specified heaters. [OAC 252:100-8]4. Monthly fuel use for each piece of fuel-burning equipment with a heat input limit shall be

maintained, along with a calculation demonstrating that the average hourly firing rate of each item is not greater than the heat rate set forth in SC #1. These records shall be maintained on a 12-month rolling basis. [OAC 252:100-8]

15


h. Reporting is required for NSPS Subpart J heaters on a semi-annual basis, including the information required in NSPS Subpart A. [40 CFR 60.107 and 60.7]

EUG 27 Existing Fuel-Burning Equipment Accepting NO X Limits

These sources were proposed for regulation under 40 CFR 63 Subpart DDDDD (MACT DDDDD), but that MACT has been vacated. This permit may be reopened to address Section 112(j) when necessary. Although heaters in this EUG generally predate permitting rules and regulations (i.e. they are “grandfathered”), all have accepted federally enforceable limits on capacity under the current HCPE project.

Source Point ID

Manu-facturer Burner Type No. of

BurnersMMBTUH

(HHV)Heater Date

NOx lb/MMBTU

(HHV)DHTU Reactor Charge Heater

(1H-101)6157 Foster-

Wheeler JZ-LOF-27-30 16 55.0 1972 0.035

FCCU Charge Heater (B-2) 6158 M W

Kellogg JZ-VBM-14 32 73.3 1949 0.040

CCR Charge Heater

(10H-101)16163 SELAS JZ MA-20 12 67.1 1972 0.050

CCR #2 Interheater-1 (10H-102)1

6163 SELAS Callidus CRG-LN-8P 8 123.3 1972 0.035

CCR #2 Interheater-2 (10H-103)1

6163 SELAS JZ MA-22 2 30.5 1972 0.035

CCR Stabilizer Reboiler

(10H-104)1TBD SELAS JZ MA-20 8 64.5 1972 0.050

1 CCR Heaters part of Permit 98-021-C (M-26) to be placed in service in 2007.

a. Compliance with the NOX limits is demonstrated by performance testing of the low-NOX


b. All heaters were to be regulated by 40 CFR 63 Subpart DDDDD, but this rule has been vacated. As proposed, the subpart would have required compliance with all applicable provisions including, but not limited to the following. [40 CFR 63 Subpart DDDDD]

16



c. Monthly fuel use for each piece of fuel-burning equipment with a heat input limit shall be maintained, along with a calculation demonstrating that the average hourly firing rate of each item is not greater than the heat rate set forth here and in SC #1. These records shall be maintained on a 12-month rolling basis. [OAC 252:100-8]

Insignificant Activities

Various records shall be maintained to demonstrate the continued status of certain emission sources as Insignificant Activities, as follow.

1. The amount of fuel dispensed from tanks #419 and #420 (monthly).

Tank No.

Point ID

Year Built

Height Diameter Nominal Capacity (barrels)

419 23131 1976 6' 11' 70420 23130 1976 6' 11' 70

2. Vapor pressure for any tanks satisfying the criteria of capacity less than 39,894 gallons and storing a liquid with vapor pressure less than 1.5 psia (annual maximum).

3. Number of drums, no larger than 55 gallons and containing less than 3% by volume of residual material, washed and/or crushed (annual).

4. Total emissions from any source classified as Insignificant on the basis of its emissions (annual), as well as a description of the calculation method used and data used in the calculation.

5. Coke handling activities having potential to emit no more than 5 TPY (actual) of any criteria pollutant (see instructions in Title V application).

6. The RTO has a potential to emit no more than 5 TPY (actual) emissions of SO2, NOx, PM or CO and is considered insignificant for these pollutants.

17


EUG Plantwide Miscellaneous

The HCPE project does not cause the modification of conditions listed in Permit No. 2007-005-TVR.

SPECIFIC CONDITION 3

No later than 30 days after each anniversary date of the issuance of the initial Title V permit (September 1, 2002), the permittee shall submit to Air Quality Division of DEQ, with a copy to the US EPA, Region 6, certification of compliance with the terms and conditions of this permit. Compliance is demonstrated in the recordkeeping requirements of Specific Conditions 1 and 2 above. Certification shall show any circumstance when these records indicate non-compliance.

[OAC 252:100-8-6 (c)(5)(A) & (D)]

18

TITLE V (PART 70) PERMIT TO OPERATE / CONSTRUCTSTANDARD CONDITIONS

(December 6, 2006)

SECTION I. DUTY TO COMPLY

A. This is a permit to operate / construct this specific facility in accordance with Title V of the federal Clean Air Act (42 U.S.C. 7401, et seq.) and under the authority of the Oklahoma Clean Air Act and the rules promulgated there under. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

B. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma Department of Environmental Quality (DEQ). The permit does not relieve the holder of the obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or ordinances. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

C. The permittee shall comply with all conditions of this permit. Any permit noncompliance shall constitute a violation of the Oklahoma Clean Air Act and shall be grounds for enforcement action, for revocation of the approval to operate under the terms of this permit, or for denial of an application to renew this permit. All terms and conditions (excluding state-only requirements) are enforceable by the DEQ, by EPA, and by citizens under section 304 of the Clean Air Act. This permit is valid for operations only at the specific location listed.

[40 CFR §70.6(b), OAC 252:100-8-1.3 and 8-6 (a)(7)(A) and (b)(1)]

D. It shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of the permit. [OAC 252:100-8-6 (a)(7)(B)]

SECTION II. REPORTING OF DEVIATIONS FROM PERMIT TERMS

A. Any exceedance resulting from emergency conditions and/or posing an imminent and substantial danger to public health, safety, or the environment shall be reported in accordance with Section XIV. [OAC 252:100-8-6 (a)(3)(C)(iii)]

B. Deviations that result in emissions exceeding those allowed in this permit shall be reported consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements.

[OAC 252:100-8-6 (a)(3)(C)(iv)]

C. Oral notifications (fax is also acceptable) shall be made to the AQD central office as soon as the owner or operator of the facility has knowledge of such emissions but no later than 4:30 p.m. the next working day the permittee becomes aware of the exceedance. Within ten (10) working days after the immediate notice is given, the owner operator shall submit a written report describing the extent of the excess emissions and response actions taken by the facility. Every written report submitted under OAC 252:100-8-6 (a)(3)(C)(iii) shall be certified by a responsible official. [OAC252:100-8-6(a)(3)(C)(iii)]

MAJOR SOURCE STANDARD CONDITIONS December 6, 2006 2

SECTION III. MONITORING, TESTING, RECORDKEEPING & REPORTING

A. The permittee shall keep records as specified in this permit. Unless a different retention period or retention conditions are set forth by a specific term in this permit, these records, including monitoring data and necessary support information, shall be retained on-site or at a nearby field office for a period of at least five years from the date of the monitoring sample, measurement, report, or application, and shall be made available for inspection by regulatory personnel upon request. Support information includes all original strip-chart recordings for continuous monitoring instrumentation, and copies of all reports required by this permit. Where appropriate, the permit may specify that records may be maintained in computerized form.

[OAC 252:100-8-6 (a)(3)(B)(ii), 8-6 (c)(1), and 8-6 (c)(2)(B)]

B. Records of required monitoring shall include:(1) the date, place and time of sampling or measurement;(2) the date or dates analyses were performed;(3) the company or entity which performed the analyses;(4) the analytical techniques or methods used;(5) the results of such analyses; and(6) the operating conditions as existing at the time of sampling or measurement.

[OAC 252:100-8-6 (a)(3)(B)(i)]

C. No later than 30 days after each six (6) month period, after the date of the issuance of the original Part 70 operating permit, the permittee shall submit to AQD a report of the results of any required monitoring. All instances of deviations from permit requirements since the previous report shall be clearly identified in the report. [OAC 252:100-8-6 (a)(3)(C)(i) and (ii)]

D. If any testing shows emissions in excess of limitations specified in this permit, the owner or operator shall comply with the provisions of Section II of these standard conditions.

[OAC 252:100-8-6 (a)(3)(C)(iii)]

E. In addition to any monitoring, recordkeeping or reporting requirement specified in this permit, monitoring and reporting may be required under the provisions of OAC 252:100-43, Testing, Monitoring, and Recordkeeping, or as required by any provision of the Federal Clean Air Act or Oklahoma Clean Air Act.

F. Submission of quarterly or semi-annual reports required by any applicable requirement that are duplicative of the reporting required in the previous paragraph will satisfy the reporting requirements of the previous paragraph if noted on the submitted report.

G. Every report submitted under OAC 252:100-8-6 and OAC 252:100-43 shall be certified by a responsible official. [OAC 252:100-8-6 (a)(3)(C)(iv)]

H. Any owner or operator subject to the provisions of NSPS shall maintain records of the occurrence and duration of any start-up, shutdown, or malfunction in the operation of an affected facility or any malfunction of the air pollution control equipment. [40 CFR 60.7 (b)]


I. Any owner or operator subject to the provisions of NSPS shall maintain a file of all measurements and other information required by the subpart recorded in a permanent file suitable for inspection. This file shall be retained for at least two years following the date of such measurements, maintenance, and records. [40 CFR 60.7 (d)]

J. The permittee of a facility that is operating subject to a schedule of compliance shall submit to the DEQ a progress report at least semi-annually. The progress reports shall contain dates for achieving the activities, milestones or compliance required in the schedule of compliance and the dates when such activities, milestones or compliance was achieved. The progress reports shall also contain an explanation of why any dates in the schedule of compliance were not or will not be met, and any preventative or corrective measures adopted. [OAC 252:100-8-6 (c)(4)]

K. All testing must be conducted by methods approved by the Division Director under the direction of qualified personnel. All tests shall be made and the results calculated in accordance with standard test procedures. The use of alternative test procedures must be approved by EPA. When a portable analyzer is used to measure emissions it shall be setup, calibrated, and operated in accordance with the manufacturer’s instructions and in accordance with a protocol meeting the requirements of the “AQD Portable Analyzer Guidance” document or an equivalent method approved by Air Quality. [40 CFR §70.6(a), 40 CFR §51.212(c)(2), 40 CFR § 70.7(d), 40 CFR §70.7(e)(2), OAC 252:100-8-6 (a)(3)(A)(iv), and OAC 252:100-43]

The reporting of total particulate matter emissions as required in Part 70, PSD, OAC 252:100-19, and Emission Inventory, shall be conducted in accordance with applicable testing or calculation procedures, modified to include back-half condensables, for the concentration of particulate matter less than 10 microns in diameter PM10. NSPS may allow reporting of only particulate matter emissions caught in the filter (obtained using Reference Method 5). [US EPA Publication (September 1994). PM10 Emission Inventory Requirements - Final Report. Emission Inventory Branch: RTP, N.C.]; [Federal Register: Volume 55, Number 74, 4/17/90, pp.14246-14249. 40 CFR Part 51: Preparation, Adoption, and Submittal of State Implementation Plans; Methods for Measurement of PM10 Emissions from Stationary Sources]; [Letter from Thompson G. Pace, EPA OAQPS to Sean Fitzsimmons, Iowa DNR, March 31, 1994 (regarding PM10 Condensables)]

L. The permittee shall submit to the AQD a copy of all reports submitted to the EPA as required by 40 CFR Part 60, 61, and 63, for all equipment constructed or operated under this permit subject to such standards. [OAC 252:100-4-5 and OAC 252:100-41-15]

SECTION IV. COMPLIANCE CERTIFICATIONS

A. No later than 30 days after each anniversary date of the issuance of the original Part 70 operating permit, the permittee shall submit to the AQD, with a copy to the US EPA, Region 6, a certification of compliance with the terms and conditions of this permit and of any other applicable requirements which have become effective since the issuance of this permit. The compliance certification shall also include such other facts as the permitting authority may require to determine the compliance status of the source.

[OAC 252:100-8-6 (c)(5)(A), (C)(v), and (D)]


B. The certification shall describe the operating permit term or condition that is the basis of the certification; the current compliance status; whether compliance was continuous or intermittent; the methods used for determining compliance, currently and over the reporting period; and a statement that the facility will continue to comply with all applicable requirements.

[OAC 252:100-8-6 (c)(5)(C)(i)-(iv)]

C. Any document required to be submitted in accordance with this permit shall be certified as being true, accurate, and complete by a responsible official. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the certification are true, accurate, and complete.

[OAC 252:100-8-5 (f) and OAC 252:100-8-6 (c)(1)]

D. Any facility reporting noncompliance shall submit a schedule of compliance for emissions units or stationary sources that are not in compliance with all applicable requirements. This schedule shall include a schedule of remedial measures, including an enforceable sequence of actions with milestones, leading to compliance with any applicable requirements for which the emissions unit or stationary source is in noncompliance. This compliance schedule shall resemble and be at least as stringent as that contained in any judicial consent decree or administrative order to which the emissions unit or stationary source is subject. Any such schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the applicable requirements on which it is based, except that a compliance plan shall not be required for any noncompliance condition which is corrected within 24 hours of discovery.

[OAC 252:100-8-5 (e)(8)(B) and OAC 252:100-8-6 (c)(3)]

SECTION V. REQUIREMENTS THAT BECOME APPLICABLE DURING THE PERMIT TERM

The permittee shall comply with any additional requirements that become effective during the permit term and that are applicable to the facility. Compliance with all new requirements shall be certified in the next annual certification. [OAC 252:100-8-6 (c)(6)]

SECTION VI. PERMIT SHIELD

A. Compliance with the terms and conditions of this permit (including terms and conditions established for alternate operating scenarios, emissions trading, and emissions averaging, but excluding terms and conditions for which the permit shield is expressly prohibited under OAC 252:100-8) shall be deemed compliance with the applicable requirements identified and included in this permit. [OAC 252:100-8-6 (d)(1)]

B. Those requirements that are applicable are listed in the Standard Conditions and the Specific Conditions of this permit. Those requirements that the applicant requested be determined as not applicable are summarized in the Specific Conditions of this permit. [OAC 252:100-8-6 (d)(2)]


SECTION VII. ANNUAL EMISSIONS INVENTORY & FEE PAYMENT

The permittee shall file with the AQD an annual emission inventory and shall pay annual fees based on emissions inventories. The methods used to calculate emissions for inventory purposes shall be based on the best available information accepted by AQD.

[OAC 252:100-5-2.1, -5-2.2, and OAC 252:100-8-6 (a)(8)]

SECTION VIII. TERM OF PERMIT

A. Unless specified otherwise, the term of an operating permit shall be five years from the date of issuance. [OAC 252:100-8-6 (a)(2)(A)]

B. A source’s right to operate shall terminate upon the expiration of its permit unless a timely and complete renewal application has been submitted at least 180 days before the date of expiration. [OAC 252:100-8-7.1 (d)(1)]

C. A duly issued construction permit or authorization to construct or modify will terminate and become null and void (unless extended as provided in OAC 252:100-8-1.4(b)) if the construction is not commenced within 18 months after the date the permit or authorization was issued, or if work is suspended for more than 18 months after it is commenced. [OAC 252:100-8-1.4(a)]

D. The recipient of a construction permit shall apply for a permit to operate (or modified operating permit) within 180 days following the first day of operation. [OAC 252:100-8-4(b)(5)]

SECTION IX. SEVERABILITY

The provisions of this permit are severable and if any provision of this permit, or the application of any provision of this permit to any circumstance, is held invalid, the application of such provision to other circumstances, and the remainder of this permit, shall not be affected thereby.

[OAC 252:100-8-6 (a)(6)]

SECTION X. PROPERTY RIGHTS

A. This permit does not convey any property rights of any sort, or any exclusive privilege.[OAC 252:100-8-6 (a)(7)(D)]

B. This permit shall not be considered in any manner affecting the title of the premises upon which the equipment is located and does not release the permittee from any liability for damage to persons or property caused by or resulting from the maintenance or operation of the equipment for which the permit is issued. [OAC 252:100-8-6 (c)(6)]


SECTION XI. DUTY TO PROVIDE INFORMATION

A. The permittee shall furnish to the DEQ, upon receipt of a written request and within sixty (60) days of the request unless the DEQ specifies another time period, any information that the DEQ may request to determine whether cause exists for modifying, reopening, revoking, reissuing, terminating the permit or to determine compliance with the permit. Upon request, the permittee shall also furnish to the DEQ copies of records required to be kept by the permit.

[OAC 252:100-8-6 (a)(7)(E)]

B. The permittee may make a claim of confidentiality for any information or records submitted pursuant to 27A O.S. 2-5-105(18). Confidential information shall be clearly labeled as such and shall be separable from the main body of the document such as in an attachment.

[OAC 252:100-8-6 (a)(7)(E)]

C. Notification to the AQD of the sale or transfer of ownership of this facility is required and shall be made in writing within 10 days after such date.

[Oklahoma Clean Air Act, 27A O.S. § 2-5-112 (G)]

SECTION XII. REOPENING, MODIFICATION & REVOCATION

A. The permit may be modified, revoked, reopened and reissued, or terminated for cause. Except as provided for minor permit modifications, the filing of a request by the permittee for a permit modification, revocation, reissuance, termination, notification of planned changes, or anticipated noncompliance does not stay any permit condition.

[OAC 252:100-8-6 (a)(7)(C) and OAC 252:100-8-7.2 (b)]

B. The DEQ will reopen and revise or revoke this permit as necessary to remedy deficiencies in the following circumstances: [OAC 252:100-8-7.3 and OAC 252:100-8-7.4(a)(2)]

(1) Additional requirements under the Clean Air Act become applicable to a major source category three or more years prior to the expiration date of this permit. No such reopening is required if the effective date of the requirement is later than the expiration date of this permit.

(2) The DEQ or the EPA determines that this permit contains a material mistake or that the permit must be revised or revoked to assure compliance with the applicable requirements.

(3) The DEQ or the EPA determines that inaccurate information was used in establishing the emission standards, limitations, or other conditions of this permit. The DEQ may revoke and not reissue this permit if it determines that the permittee has submitted false or misleading information to the DEQ.

C. If “grandfathered” status is claimed and granted for any equipment covered by this permit, it shall only apply under the following circumstances: [OAC 252:100-5-1.1]

(1) It only applies to that specific item by serial number or some other permanent identification.

(2) Grandfathered status is lost if the item is significantly modified or if it is relocated outside the boundaries of the facility.


D. To make changes other than (1) those described in Section XVIII (Operational Flexibility), (2) administrative permit amendments, and (3) those not defined as an Insignificant Activity (Section XVI) or Trivial Activity (Section XVII), the permittee shall notify AQD. Such changes may require a permit modification. [OAC 252:100-8-7.2 (b)]

E. Activities that will result in air emissions that exceed the trivial/insignificant levels and that are not specifically approved by this permit are prohibited. [OAC 252:100-8-6 (c)(6)]

SECTION XIII. INSPECTION & ENTRY

A. Upon presentation of credentials and other documents as may be required by law, the permittee shall allow authorized regulatory officials to perform the following (subject to the permittee's right to seek confidential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(18) for confidential information submitted to or obtained by the DEQ under this section):

[OAC 252:100-8-6 (c)(2)]

(1) enter upon the permittee's premises during reasonable/normal working hours where a source is located or emissions-related activity is conducted, or where records must be kept under the conditions of the permit;

(2) have access to and copy, at reasonable times, any records that must be kept under the conditions of the permit;

(3) inspect, at reasonable times and using reasonable safety practices, any facilities, equipment (including monitoring and air pollution control equipment), practices, or operations regulated or required under the permit; and

(4) as authorized by the Oklahoma Clean Air Act, sample or monitor at reasonable times substances or parameters for the purpose of assuring compliance with the permit.

SECTION XIV. EMERGENCIES

A. Any emergency and/or exceedance that poses an imminent and substantial danger to public health, safety, or the environment shall be reported to AQD as soon as is practicable; but under no circumstance shall notification be more than 24 hours after the exceedance.

[OAC 252:100-8-6 (a)(3)(C)(iii)(II)]

B. An "emergency" means any situation arising from sudden and reasonably unforeseeable events beyond the control of the source, including acts of God, which situation requires immediate corrective action to restore normal operation, and that causes the source to exceed a technology-based emission limitation under this permit, due to unavoidable increases in emissions attributable to the emergency. [OAC 252:100-8-2]

C. An emergency shall constitute an affirmative defense to an action brought for noncompliance with such technology-based emission limitation if the conditions of paragraph D below are met.

[OAC 252:100-8-6 (e)(1)]


D. The affirmative defense of emergency shall be demonstrated through properly signed, contemporaneous operating logs or other relevant evidence that:

[OAC 252:100-8-6 (e)(2), (a)(3)(C)(iii)(I) and (IV)]

(1) an emergency occurred and the permittee can identify the cause or causes of the emergency;

(2) the permitted facility was at the time being properly operated;(3) during the period of the emergency the permittee took all reasonable steps to minimize

levels of emissions that exceeded the emission standards or other requirements in this permit;

(4) the permittee submitted timely notice of the emergency to AQD, pursuant to the applicable regulations (i.e., for emergencies that pose an “imminent and substantial danger,” within 24 hours of the time when emission limitations were exceeded due to the emergency; 4:30 p.m. the next business day for all other emergency exceedances). See OAC 252:100-8-6(a)(3)(C)(iii)(I) and (II). This notice shall contain a description of the emergency, the probable cause of the exceedance, any steps taken to mitigate emissions, and corrective actions taken; and

(5) the permittee submitted a follow up written report within 10 working days of first becoming aware of the exceedance.

E. In any enforcement proceeding, the permittee seeking to establish the occurrence of an emergency shall have the burden of proof. [OAC 252:100-8-6 (e)(3)]

SECTION XV. RISK MANAGEMENT PLAN

The permittee, if subject to the provision of Section 112(r) of the Clean Air Act, shall develop and register with the appropriate agency a risk management plan by June 20, 1999, or the applicable effective date. [OAC 252:100-8-6 (a)(4)]

SECTION XVI. INSIGNIFICANT ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to operate individual emissions units that are either on the list in Appendix I to OAC Title 252, Chapter 100, or whose actual calendar year emissions do not exceed any of the limits below. Any activity to which a State or federal applicable requirement applies is not insignificant even if it meets the criteria below or is included on the insignificant activities list. [OAC 252:100-8-2]

(1) 5 tons per year of any one criteria pollutant.(2) 2 tons per year for any one hazardous air pollutant (HAP) or 5 tons per year for an

aggregate of two or more HAP's, or 20 percent of any threshold less than 10 tons per year for single HAP that the EPA may establish by rule.


SECTION XVII. TRIVIAL ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to operate any individual or combination of air emissions units that are considered inconsequential and are on the list in Appendix J. Any activity to which a State or federal applicable requirement applies is not trivial even if included on the trivial activities list. [OAC 252:100-8-2]

SECTION XVIII. OPERATIONAL FLEXIBILITY

A. A facility may implement any operating scenario allowed for in its Part 70 permit without the need for any permit revision or any notification to the DEQ (unless specified otherwise in the permit). When an operating scenario is changed, the permittee shall record in a log at the facility the scenario under which it is operating. [OAC 252:100-8-6 (a)(10) and (f)(1)]

B. The permittee may make changes within the facility that:

(1) result in no net emissions increases,(2) are not modifications under any provision of Title I of the federal Clean Air Act, and(3) do not cause any hourly or annual permitted emission rate of any existing emissions unit

to be exceeded;

provided that the facility provides the EPA and the DEQ with written notification as required below in advance of the proposed changes, which shall be a minimum of 7 days, or 24 hours for emergencies as defined in OAC 252:100-8-6 (e). The permittee, the DEQ, and the EPA shall attach each such notice to their copy of the permit. For each such change, the written notification required above shall include a brief description of the change within the permitted facility, the date on which the change will occur, any change in emissions, and any permit term or condition that is no longer applicable as a result of the change. The permit shield provided by this permit does not apply to any change made pursuant to this subsection. [OAC 252:100-8-6 (f)(2)]

SECTION XIX. OTHER APPLICABLE & STATE-ONLY REQUIREMENTS

A. The following applicable requirements and state-only requirements apply to the facility unless elsewhere covered by a more restrictive requirement:

(1) No person shall cause or permit the discharge of emissions such that National Ambient Air Quality Standards (NAAQS) are exceeded on land outside the permitted facility.

[OAC 252:100-3](2) Open burning of refuse and other combustible material is prohibited except as authorized

in the specific examples and under the conditions listed in the Open Burning Subchapter.[OAC 252:100-13]

(3) No particulate emissions from any fuel-burning equipment with a rated heat input of 10 MMBTUH or less shall exceed 0.6 lb/MMBTU. [OAC 252:100-19]


(4) For all emissions units not subject to an opacity limit promulgated under 40 CFR, Part 60, NSPS, no discharge of greater than 20% opacity is allowed except for short-term occurrences which consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours. In no case shall the average of any six-minute period exceed 60% opacity. [OAC 252:100-25]

(5) No visible fugitive dust emissions shall be discharged beyond the property line on which the emissions originate in such a manner as to damage or to interfere with the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the maintenance of air quality standards. [OAC 252:100-29]

(6) No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2 lb/MMBTU. No existing source shall exceed the listed ambient air standards for sulfur dioxide. [OAC 252:100-31]

(7) Volatile Organic Compound (VOC) storage tanks built after December28, 1974, and with a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia or greater under actual conditions shall be equipped with a permanent submerged fill pipe or with a vapor-recovery system. [OAC 252:100-37-15(b)]

(8) All fuel-burning equipment shall at all times be properly operated and maintained in a manner that will minimize emissions of VOCs. [OAC 252:100-37-36]

SECTION XX. STRATOSPHERIC OZONE PROTECTION

A. The permittee shall comply with the following standards for production and consumption of ozone-depleting substances. [40 CFR 82, Subpart A]

(1) Persons producing, importing, or placing an order for production or importation of certain class I and class II substances, HCFC-22, or HCFC-141b shall be subject to the requirements of §82.4.

(2) Producers, importers, exporters, purchasers, and persons who transform or destroy certain class I and class II substances, HCFC-22, or HCFC-141b are subject to the recordkeeping requirements at §82.13.

(3) Class I substances (listed at Appendix A to Subpart A) include certain CFCs, Halons, HBFCs, carbon tetrachloride, trichloroethane (methyl chloroform), and bromomethane (Methyl Bromide). Class II substances (listed at Appendix B to Subpart A) include HCFCs.

B. If the permittee performs a service on motor (fleet) vehicles when this service involves an ozone-depleting substance refrigerant (or regulated substitute substance) in the motor vehicle air conditioner (MVAC), the permittee is subject to all applicable requirements. Note: The term “motor vehicle” as used in Subpart B does not include a vehicle in which final assembly of the vehicle has not been completed. The term “MVAC” as used in Subpart B does not include the air-tight sealed refrigeration system used as refrigerated cargo, or the system used on passenger buses using HCFC-22 refrigerant. [40 CFR 82, Subpart B]

C. The permittee shall comply with the following standards for recycling and emissions reduction except as provided for MVACs in Subpart B. [40 CFR 82, Subpart F]


(1) Persons opening appliances for maintenance, service, repair, or disposal must comply with the required practices pursuant to § 82.156.

(2) Equipment used during the maintenance, service, repair, or disposal of appliances must comply with the standards for recycling and recovery equipment pursuant to § 82.158.

(3) Persons performing maintenance, service, repair, or disposal of appliances must be certified by an approved technician certification program pursuant to § 82.161.

(4) Persons disposing of small appliances, MVACs, and MVAC-like appliances must comply with record-keeping requirements pursuant to § 82.166.

(5) Persons owning commercial or industrial process refrigeration equipment must comply with leak repair requirements pursuant to § 82.158.

(6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant must keep records of refrigerant purchased and added to such appliances pursuant to § 82.166.

SECTION XXI. TITLE V APPROVAL LANGUAGE

A. DEQ wishes to reduce the time and work associated with permit review and, wherever it is not inconsistent with Federal requirements, to provide for incorporation of requirements established through construction permitting into the Sources’ Title V permit without causing redundant review. Requirements from construction permits may be incorporated into the Title V permit through the administrative amendment process set forth in Oklahoma Administrative Code 252:100-8-7.2(a) only if the following procedures are followed:

(1) The construction permit goes out for a 30-day public notice and comment using the procedures set forth in 40 Code of Federal Regulations (CFR) § 70.7 (h)(1). This public notice shall include notice to the public that this permit is subject to Environmental Protection Agency (EPA) review, EPA objection, and petition to EPA, as provided by 40 CFR § 70.8; that the requirements of the construction permit will be incorporated into the Title V permit through the administrative amendment process; that the public will not receive another opportunity to provide comments when the requirements are incorporated into the Title V permit; and that EPA review, EPA objection, and petitions to EPA will not be available to the public when requirements from the construction permit are incorporated into the Title V permit.

(2) A copy of the construction permit application is sent to EPA, as provided by 40 CFR § 70.8(a)(1).

(3) A copy of the draft construction permit is sent to any affected State, as provided by 40 CFR § 70.8(b).

(4) A copy of the proposed construction permit is sent to EPA for a 45-day review period as provided by 40 CFR § 70.8(a) and (c).

(5) The DEQ complies with 40 CFR § 70.8 (c) upon the written receipt within the 45-day comment period of any EPA objection to the construction permit. The DEQ shall not issue the permit until EPA’s objections are resolved to the satisfaction of EPA.

(6) The DEQ complies with 40 CFR § 70.8 (d).(7) A copy of the final construction permit is sent to EPA as provided by 40 CFR § 70.8 (a).(8) The DEQ shall not issue the proposed construction permit until any affected State and

EPA have had an opportunity to review the proposed permit, as provided by these permit conditions.


(9) Any requirements of the construction permit may be reopened for cause after incorporation into the Title V permit by the administrative amendment process, by DEQ as provided in OAC 252:100-8-7.3 (a), (b), and (c), and by EPA as provided in 40 CFR § 70.7 (f) and (g).

(10) The DEQ shall not issue the administrative permit amendment if performance tests fail to demonstrate that the source is operating in substantial compliance with all permit requirements.

B. To the extent that these conditions are not followed, the Title V permit must go through the Title V review process.

SECTION XXII. CREDIBLE EVIDENCE

For the purpose of submitting compliance certifications or establishing whether or not a person has violated or is in violation of any provision of the Oklahoma implementation plan, nothing shall preclude the use, including the exclusive use, of any credible evidence or information, relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed.

[OAC 252:100-43-6]

M. P. Bellinger, Refinery ManagerSinclair Tulsa Refinery CompanyP.O. Box 970Tulsa, OK 74101

Re: Construction Permit No. 2007-005-C (M-1)Tulsa Refinery – Heavy Crude Processing Expansion Project

Dear Mr. Bellinger:

Air Quality Division has completed the initial review of your permit application referenced above. This application has been determined to be a Tier II. In accordance with 27A O.S. § 2-14-302 and OAC 252:4-7-13, the enclosed draft permit is now ready for public review. The requirements for public review include the following steps that you must accomplish:

1. Publish at least one legal notice (one day) in at least one newspaper of general circulation within the county where the facility is located. (Instructions enclosed)

2. Provide for public review (for a period of 30 days following the date of the newspaper announcement) a copy of this draft permit and a copy of the application at a convenient location within the county of the facility.

3. Send to AQD a copy of the proof of publication notice from Item #1 above together with any additional comments or requested changes that you may have on the draft permit.

Thank you for your cooperation. If you have any questions, please refer to the permit number above and contact me at (918) 293-1624.

Sincerely,

Herb NeumannAir Quality Division

Encl.

M. P. Bellinger, Refinery ManagerSinclair Tulsa Refinery CompanyP.O. Box 970Tulsa, OK 74101

Re: Construction Permit No. 2007-005-C (M-1)Tulsa Refinery – Heavy Crude Processing Expansion (HCPE) Project

Dear Mr. Bellinger:

Enclosed is the permit authorizing construction of the referenced HCPE project. Please note that this permit is issued subject to certain standard and specific conditions that are attached.

Also note that you are required to annually submit an emission inventory for this facility. An emission inventory must be completed on approved AQD forms and submitted (hardcopy or electronically) by April 1st of every year. Any questions concerning the form or submittal process should be referred to the Emission Inventory Staff at 405-702-4100.

Thank you for your cooperation in this matter. If we may be of further service, please contact our office at (918) 293-1600. Air Quality personnel are located in the DEQ Regional Office at Tulsa, 3105 E. Skelly Drive, Suite 200, Tulsa, OK, 74105.

Sincerely,

Herb NeumannAir Quality Division

Encl.

PART 70 PERMITAIR QUALITY DIVISIONSTATE OF OKLAHOMA

DEPARTMENT OF ENVIRONMENTAL QUALITY707 N. ROBINSON, SUITE 4100

P.O. BOX 1677OKLAHOMA CITY, OKLAHOMA 73101-1677

Permit No. 2007-005-C (M-1)

Sinclair Tulsa Refining Company,

having complied with the requirements of the law, is hereby granted permission to

construct the Heavy Crude Processing Expansion (HCPE) Project at the Tulsa Refinery,

902 W. 25 th Street, Tulsa, Tulsa County, Oklahoma,

subject to standard conditions dated December 6, 2006, and specific conditions, both

attached.

In the absence of construction commencement, this permit shall expire 18 months from the issuance date, except as authorized under Section VIII of the Standard Conditions.

_________________________________

Eddie Terrill, Director Date

oklahoma department of environmental … · web viewheat generated by the thermal oxidizer is...

Documents