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    • Abstract: Technical Support Document forPrevention of SignificantDeterioration (PSD) Permit 10-01BP Cherry Point RefineryClean Fuels ProjectBlaine, WashingtonOctober 28, 2010 TABLE OF CONTENTS

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Technical Support Document for
Prevention of Significant
Deterioration (PSD) Permit 10-01
BP Cherry Point Refinery
Clean Fuels Project
Blaine, Washington
October 28, 2010
TABLE OF CONTENTS
1. EXECUTIVE SUMMARY .................................................................................................................. 1
2. INTRODUCTION ................................................................................................................................ 1
2.1. The PSD Process ........................................................................................................................... 1
2.2. The Project .................................................................................................................................... 2
2.2.1. The Site ................................................................................................................................. 2
2.2.2. The Proposal ......................................................................................................................... 2
2.2.3. Project Effects on Existing Units .......................................................................................... 5
2.3. PSD Applicability and Air Pollutant Emissions ........................................................................... 9
2.4. New Source Performance Standards ........................................................................................... 15
2.5. Minor NSR and Other State Regulations .................................................................................... 16
3. DETERMINATION OF BEST AVAILABLE CONTROL TECHNOLOGY .................................. 16
3.1. Particulate Matter (PM) BACT Analysis for the #3 DHDS Charge Heater and the #2 H2 Plant
SMR Furnace .......................................................................................................................................... 16
3.2. Particulate Matter (PM) BACT Analysis for the #2 H2 Plant Flare ............................................ 19
4. AIR QUALITY IMPACTS ANALYSIS ........................................................................................... 21
4.1. Model Selection and Procedures ................................................................................................. 21
4.2. Dispersion Modeling Pollutant Emission Rates.......................................................................... 22
4.3. Maximum Concentrations From the Project ............................................................................... 22
4.4. Analysis of Results ..................................................................................................................... 23
4.5. Toxic Air Pollutants .................................................................................................................... 24
5. CLASS I AREA IMPACT ANALYSIS ............................................................................................ 24
5.1. Model Selection and Procedures ................................................................................................. 25
5.2. Criteria Pollutant Concentrations ................................................................................................ 25
5.3. Nitrogen and Sulfur Deposition .................................................................................................. 26
5.4. Visibility—Regional Haze .......................................................................................................... 27
5.5. Conclusion Concerning AQRVs ................................................................................................. 30
6. ADDITIONAL IMPACTS ANALYSIS ............................................................................................ 30
6.1. Class II Area Growth .................................................................................................................. 31
6.2. Class II Visibility ........................................................................................................................ 31
6.3. Soils and Vegetation ................................................................................................................... 31
6.4. Ozone Analysis ........................................................................................................................... 32
7. CONCLUSION .................................................................................................................................. 33
APPENDIX A. RBLC and District Permitting and BACT Guidance Summary Tables ........................... 34
APPENDIX B. Detailed Emission Calculations ........................................................................................ 36
ii
LIST OF TABLES
Table 1. Regulated Pollutant Emission Increase for Clean Fuels Project.................................... 11
Table 2. Clean Fuels Project PSD—NOX and PM10 Netting Analysis ........................................ 12
Table 3. #2 Hydrogen Plant—Design Basis and Monitoring Methods ....................................... 14
Table 4. #3 DHDS—Design Basis and Monitoring Methods...................................................... 14
Table 5. Clean Fuels Project—NSPS Applicability Summary .................................................... 15
Table 6. Maximum Predicted Criteria Air Pollutant Concentrations .......................................... 23
Table 7. Class I Areas and Q/D Analysis .................................................................................... 25
Table 8. Predicted Class I Area Criteria Pollutant Concentrations .............................................. 26
Table 9. Predicted Class I Area Deposition Fluxes ..................................................................... 27
Table 10. Maximum Predicted Extinction Change by Class I Area, Method 2........................... 29
Table 11. Maximum Predicted Extinction Change by Class I Area, Method 8........................... 30
iii
1. EXECUTIVE SUMMARY
To meet upcoming federal mobile source fuel specifications for diesel and gasoline, the BP
Cherry Point Refinery (BP) proposes to add a new hydrogen production unit, a new diesel hydro-
desulfurization unit, and to retrofit an ultra-low NOX burner (ULNB) into the largest of their
existing Hydrocracker heaters. The project will reduce the sulfur content of diesel fuel currently
sold for off-road diesel-fueled engines, which will reduce both sulfur dioxide (SO2)emissions
and diesel particulate matter due to sulfate emitted by these engines. The project will also reduce
benzene emissions from gasoline fuel. The project will not provide an increase in total refinery
fuel production capacity. The project is referred to as the Clean Fuels Project.
The new hydrogen plant will provide 40 million standard cubic foot per day (MMSCFPD)
synthesized hydrogen production facility, which will provide additional diesel hydrotreating
capacity to 25,000 barrels per day of existing diesel fuel production. Removing sulfur from this
fuel that will be sold in Washington will avoid an estimated 3,200 to 9,600 tons per year of SO2
and about 100 tons of sulfate particulate emissions from the state airsheds when estimated at
current fuel consumption rates.
BP is also proposing to retrofit the existing 1st Stage Fractionator Reboiler (one of four heaters at
the Hydrocracker) with ULNBs. These new burners will reduce NOX and CO from the
Hydrocracker, even with an expected increase in its utilization. As a result, the Clean Fuels
Project will reduce annual refinery emissions of oxides of nitrogen (NOX).
The Washington State Department of Ecology’s (Ecology) review of BP’s applicability analysis
of the Clean Fuels Project indicates that no air pollutants are subject to federal PSD
requirements. The review does indicate that due to the different treatment of condensable
particulates, the project is subject to PSD permitting under the state PSD requirements for PM10
emissions. No other regulated pollutant is PSD-applicable under either set of PSD regulations.
Ecology will prepare a draft PSD permit that addresses the PM10 for the project. The Northwest
Clean Air Agency (NWCAA) will address all other air pollutant emissions through their Notice
of Construction permit.
Ecology finds that BP has satisfied all requirements for approval of the proposed PSD permit for
the Clean Fuels Project and now sends the proposed permit for public comment.
2. INTRODUCTION
2.1. The PSD Process
The Prevention of Significant Deterioration (PSD) procedure is established in Title 40, Code of
Federal Regulations (CFR), Part 52.21 and in Washington Administrative Code 173-400-700.
Federal rules require PSD review of all new or modified air pollution sources that meet certain
overall size and pollution rate criteria. The objective of the PSD program is to prevent serious
adverse environmental impact from emissions into the atmosphere by a proposed new or
modified source. PSD rules require that an applicant use the most effective air pollution control
equipment and procedures after considering environmental, economic, and energy factors. The
program sets up a mechanism for evaluating and controlling air emissions from a proposed
source to minimize the impacts on air quality, visibility, soils, and vegetation.
Technical Support Document Page 2
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
The United States Environmental Protection Agency (EPA) delegated the authority to implement
the PSD program described in Title 40 CFR. 52.21 and its supporting guidance and procedures
documents to the Engineering Unit staff1 of Ecology’s Air Quality Program.2
The current Federal PSD regulations (40 CFR 52.21(b)(50)(vi)) include a temporary exemption
from considering condensable emissions particulate when calculating PSD applicability for PM,
PM10, and PM2.5. This exemption is set to expire on January 1, 2011.
Ecology’s PSD regulation incorporates an earlier version of the federal program (as in effect
October 1, 2006) that does not include the exemption for condensable particulate material when
making applicability determinations. As a result, condensable particulates continue to be
included in PSD applicability determinations under the state PSD regulation.
A September 28, 2008, letter from EPA to Ecology addresses the changes to 52.21 adopted by
EPA on July 15, 2008. One item in this rule amendment was to insert the temporary exemption
for condensable particulate matter for PSD applicability determinations. The letter amendment
recognizes the Ecology version of the PSD regulation, but does not include the July 2008 rule
change. This confirms that PM2.5 is not a PSD pollutant regulated under current Washington
PSD regulations, only under the federal PSD regulation.
2.2. The Project
2.2.1. The Site
BP operates a refinery at Cherry Point in Whatcom County, Washington. The refinery is located
in a rural setting near Blaine and Birch Bay, Washington. The surrounding land use is zoned
heavy impact industrial and is mostly vacant. Historical uses were agricultural (dairy farming).
Immediately to the west is the Puget Sound Energy’s Whitehorn gas-turbine power generating
station. About two miles west northwest of the refinery is Birch Bay State Park. UTM
coordinates are Zone 10 519600E and 5414800N.
2.2.2. The Proposal
The two primary components of the Clean Fuels Project are a new diesel hydrotreater to provide
additional sulfur removal capacity for 25,000 barrels per day (BPD) from the current diesel fuel
production, and a 40 million standard cubic feet per day (MMSCFPD) synthesized hydrogen
plant.
The project also includes retrofitting the 1st Stage Fractionator Reboiler (one of the four
Hydrocracker heaters) with ULNBs, piping changes at the existing diesel blending skid,
wastewater treatment plant upgrades, and extensive tie-ins to existing refinery utility systems
1
An organizational unit in the Science and Engineering Section.
2
Agreement for the Delegation of the Federal Prevention of Significant Deterioration (PSD) Regulations by the
United States Environmental Protection Agency, Region 10 to the State of Washington Department of Ecology
(February 23, 2005).
Technical Support Document Page 3
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
New Diesel Hydro-Desulfurization Unit #3
The new diesel hydrotreater, referred to as #3 diesel hydro-desulfurization unit (or #3 DHDS),
will produce 25,000 BPD of ultra-low sulfur distillate. The purpose of this unit is to remove
additional sulfur from currently produced diesel fuel to meet the new 15 ppm non-road diesel
sulfur specification.
Hydrotreating is the process where hydrocarbons containing sulfur, nitrogen and metals are
purified by catalytic reaction in a hydrogen rich atmosphere. Sulfur compounds are catalytically
converted to hydrogen sulfide and nitrogen compounds are catalytically converted to ammonia.
The basic process steps of the unit are feed preheating, reaction, separation, stripping, drying,
and compression. The new unit would be configured to accept straight run and cracked
feedstocks. New tie-ins to the Crude Unit and Coker would be constructed to facilitate the
transfer of hot feeds.
The ability to direct any of these feedstocks to any of the diesel hydrotreaters is planned as a
means to facilitate periodic turnarounds of individual units. The ability to process a variety of
cold feeds from tankage would also be constructed. Aside from component leaks, the only
source of emissions associated with #3 DHDS is a 28 million British thermal units per hour
(MMBtu/hr) Charge Heater. The Charge Heater will be equipped with ULNBs to control
emissions of NOX. The burner pilots would be fired with natural gas and the heater would
combust refinery fuel gas from the existing refinery mix drum.
Although the Charge Heater will be designed with a maximum heat input of 28 MMBtu/hr, this
firing rate will only be required during startup because hydro-desulfurization is exothermic. BP
anticipates the typical firing rate of this heater will be substantially lower, approximately
12 MMBtu/hour. At lower operating rates, mass emissions are lower but pollutant
concentrations may be higher.
New Hydrogen Plant #2
Removal of additional sulfur to meet the ULSD fuel specification requires additional hydrogen.
Hydrogen is also required to convert benzene into less harmful gasoline blending components.
Cherry Point Refinery currently generates hydrogen by two methods: steam-methane reforming
is used in the existing Hydrogen Unit (#1 Hydrogen); and catalytic reforming is used in the two
existing semi-regenerative reformers.
BP is proposing to construct and operate a new plant (#2 Hydrogen) consisting of a steam
methane reformer (SMR) with pressure swing adsorption purification (PSA) system. PSA
technology is more efficient than the existing hydrogen plant’s method of purification and will
produce higher purity hydrogen than the existing plant. Feedstocks will include natural gas and
certain high hydrogen content refinery off gas streams. The proposed SMR would synthesize 40
MMSCFD of hydrogen from natural gas and would purify an additional 4 MMSCFD of
hydrogen from refinery off gas streams (ROG).
Technical Support Document Page 4
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
The new Hydrogen Plant will consist of feed knock out pots, feed conditioning reactors, a
product compressor, a furnace, a hot shift reactor, PSA vessels, purge gas vessel, steam
production equipment, motor control center, pipe racks and ancillary equipment. The unit would
be equipped with an elevated flare that would combust minute quantities of volatile compounds
during normal operation but would be sized to accommodate much higher volumes during
startup, shutdown and malfunction events.
SMRs produce hydrogen by reacting superheated steam with a source of light hydrocarbons in
the presence of a nickel catalyst where most of the hydrocarbon is converted to CO2 and H2.
Carbon monoxide (CO) is produced as a reaction byproduct. CO and H2O are converted to CO2
and H2 in the hot shift reactor, which contains a catalyst.
The hydrogen is then purified by separating it from the other gases in the PSA vessels; these
vessels contain an adsorbent that collects all gases except hydrogen, which passes through.
Periodically, the gases collected on the adsorbent are removed. This material is known as PSA
residue and is burned as fuel in the SMR furnace. The high purity hydrogen exiting the PSA
vessels is then compressed and distributed for use within the refinery.
Sulfur is harmful to the catalyst used to synthesize hydrogen. To prevent catalyst degradation,
the unit will be equipped with chloride and sulfur guard beds. The chloride guard bed would
contain activated alumina. The sulfur guard beds would contain a catalyst where sulfur species
would be converted to hydrogen sulfide (H2S) and zinc oxide (ZnO) beds, which would adsorb
the H2S. The unit would be equipped with a ZnO bed. The guard bed will reduce the sulfur
content of the natural gas feed to the SMR to less than one tenth of one part per million by
volume. As a result, the PSA residue used as fuel will have extremely low sulfur content.
The SMR furnace would be top-fired, downward-flow and co-current configuration. It would
have a heat input capacity of 430 MMBtu/hour (HHV) during normal operations and a maximum
heat input capacity of 496 MMBtu/hour. The furnace would be fired by pipeline grade natural
gas and PSA residue. Approximately, 90% of the heat input to the furnace would be from PSA
residue and 10% from natural gas. Refinery fuel gas from the existing fuel gas mix drum would
not be used.3 The majority of sulfur emissions would be because of natural gas combustion.
The furnace will be equipped with ULNBs and a selective catalytic reduction unit (SCR) with
aqueous ammonia injection system will be used to control NOX emissions from the SMR
furnace. Ammonia for the SCR would be supplied from the existing aqueous ammonia storage
tank that serves #6 and #7 Boilers.
The new Hydrogen Plant would produce steam to support the reforming reaction and for export
for use elsewhere in the refinery. Approximately 140 KPPH (thousand pounds per hour) of
steam would be exported to the refinery. Thus, the Clean Fuels Project would be a net producer
of steam and would reduce utilization of the refinery’s existing steam generating units.
However, no emission netting credit is taken for emission reductions from the boilers.
3
PSA reject gas or ―residue‖ would be regulated as ―refinery fuel gas‖ under NSPS Subpart Ja. A SO 2 CEMS could
also be installed on the stack to demonstrate compliance.
Technical Support Document Page 5
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
A new flare would continuously combust small flows (anticipated to be approximately 4,600
scf/hr) but would be designed for higher flows associated with startup, shutdown and
malfunction events. The flare would be of an elevated torch configuration attached to the stack
of the SMR furnace. Only the new hydrogen plant would be served by the new flare. The
primary function of the flare is to combust off-spec hydrogen during startup.
The flare will have uninterruptible natural gas to operate the pilot burners. Flaring will be
minimized to the extent practicable and will include nitrogen purges from compressor seals and
compressor distance piece vents and natural gas sweep gas to maintain the collection header free
of oxygen.
Hydrocracker Burner Retrofit
As part of the Clean Fuels Project, BP proposes to retrofit ULNBs in the 1st Stage Fractionator
Reboiler. The Reboiler is one of four heaters associated with the Hydrocracker Unit, and is the
heater with the highest rated firing capacity. As a result of the retrofit, potential NOX and CO
emissions from the Reboiler would decrease by approximately 80 and 40 percent, respectively.
2.2.3. Project Effects on Existing Units
The following subsections identify how the Clean Fuels Project affects operation of and
emissions from existing refinery emission units. This step is necessary because increases in
emissions from existing units attributable to a project must be considered when evaluating PSD
applicability.
Compared with existing sources of hydrogen, the new hydrogen plant will cost less to operate
and use less energy per unit of production, and provide a product of higher purity. Given these
economic incentives, the new plant would be used preferentially over the existing hydrogen-
producing units. The distribution of the higher purity material would be through new dedicated
piping.
Hydrocracker
The Hydrocracker converts gas oils from the coker and vacuum section of the crude unit to jet
fuel and gasoline blending stocks. The unit is comprised of two reaction stages and two
fractionation stages. Reaction stages change the molecular structure of the feed. Fractionation
stages use distillation to separate the material that is converted by the reactors. The unit contains
four heaters, one for each stage. All heaters are fired by refinery fuel gas. As part of the
proposed Clean Fuels Project, BP will retrofit the existing 1st Stage Fractionator Reboiler with
ULNBs, which will significantly reduce potential NOX and CO emissions from the existing
heater.
From a regulatory perspective, the availability of additional hydrogen from #2 Hydrogen will
debottleneck the Hydrocracker because it will alleviate existing hydrogen shortages resulting
from production dips from Reformer regeneration events and the gradual reduction in Reformer
hydrogen production over its turnaround cycle. The net effect will be increases in annual firing
Technical Support Document Page 6
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
and emissions from the Hydrocracker’s four RFG-fired heaters. There would be no increase in
the potential hourly emissions from any of the heaters because they currently fire at capacity
under certain operating conditions and because the heaters will not be modified. Because the 1st
Stage Fractionator Reboiler will be retrofitted with ULNBs, BP expects potential hourly and
annual NOX and CO emission rates to decrease compared to the existing conventional burners;
emissions of other pollutants would not change.
Reformers
The purpose of the Catalytic Reforming Units (CRU or Reformers) is to convert low octane
naphtha range feedstocks into a stabilized high octane gasoline blending stock. The octane
number of the feed is increased by passing it over a platinum-rhenium catalyst at high
temperatures in a hydrogen-rich atmosphere. Reforming consists of four primary chemical
reactions: cyclization, dehydrogenation, isomerization, and cracking. Cyclization and
dehydrogenation are the dominant reactions making the overall process endothermic. These two
reactions result in the production of a hydrogen rich byproduct stream, which is compressed and
distributed throughout the refinery on the 460# hydrogen header for use in various other process
units. The Hydrocracker consumes the vast majority of the 460# hydrogen.
The Reformers are of semi-regenerative configuration meaning that they are taken out of service
periodically for catalyst regeneration. The volume of hydrogen produced declines throughout
the production cycle. As a result, the production rate of the Hydrocracker is limited by the
Reformers ability to provide hydrogen.
The proposed hydrogen plant would be used to remedy the end of run hydrogen shortage at the
Hydrocracker by providing a new continuous supply of high purity hydrogen. The resulting
operational severity of the Reformers would be reduced, resulting in substantial emissions
reductions from the heaters and High Pressure Flare. Although emissions will decrease, there is
no modification to the reformers and no PSD netting credit is requested
Isomerization Unit
The Isomerization Unit #45 (ISOM) processes light naphtha feed stocks to produce a gasoline
blending component that has essentially no benzene, olefins, or sulfur and is higher in octane
than its feed. It does this by isomerizing low octane C5 paraffins to their higher octane isomers
and by saturating gasoline component streams containing higher benzene concentrations in the
BenSat section.
In 2011, the allowable benzene content in gasoline will be reduced to 0.62% volume on a
company-wide annual average basis. To meet the tighter benzene standard, a portion of
hydrogen generated by the #2 Hydrogen Plant will be directed to ISOM (see Figure 2-8). The
availability of additional hydrogen will enable BP to produce gasoline that meets the new
benzene standard.
Emissions from the ISOM unit occur as a result of combustion of refinery fuel gas in its heater
and from component leaks. No increase in emissions from component leaks is expected as a
Technical Support Document Page 7
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
result of the Clean Fuels Project. Benzene saturation is an exothermic reaction, which occurs
downstream from the IHT Heater. As a result, no increase in firing of the IHT charge heater will
be necessary.
Diesel Units
BP currently operates two diesel hydrotreaters. The #1 diesel unit (#1DHDS, Unit #13) has a
small reactor and its design is not suitable for producing ultra-low sulfur products from a wide
range of feedstocks. #1DHDS currently produces high sulfur diesel (500-5,000 ppm wt %) from
straight run and cracked feedstocks.
In order for the small reactor to hydrotreat the incoming feedstock to the 15 ppm S level, the feed
rate must be reduced with the remaining volume filled with recycled ULSD from #2DHDS or
#3DHDS. The ULSD recycle stream is necessary to control reactor temperatures since the
process is exothermic. New lines from #2DHDS and #3DHDS would be installed to deliver
finished ULSD to be used as recycle feed to #1DHDS.
#1DHDS unit is currently capable of operating in this manner but the ULSD recycle feed is
pumped from tankage. No changes are proposed for #1DHDS, so no emissions increases or
decreases from operation of #1DHDS are included with the overall project emissions inventory.
The #2 diesel unit commenced operation in 2006. It was designed to meet the EPA ultra-low
diesel specification now in place for on-road vehicles. No changes in operation of #2DHDS are
planned, so no emission increases or decreases from operation of #2DHDS are included in the
emission inventory
Sulfur Recovery Unit and Lean & Rich Amine Systems
Existing unused capacity within the amine regeneration unit will be used to recover the
additional sulfur from #3DHDS. The two new scrubbers in #3DHDS would be connected to
these existing units.
The scope of work within the amine regeneration unit includes minor re-piping around the amine
filter system, and tie-ins from the new diesel unit to both the amine and sour water headers. No
other capital investment in the amine regeneration unit is planned as part of the proposed Clean
Fuels Project. There are no emissions from the amine regeneration unit.
The Sulfur Recovery Unit has the capacity to accommodate the additional sour gas load. The
current production of elemental sulfur will increase by up to 15 long tons per day. No physical
or operational changes to the Sulfur Recovery Unit are required. No changes in existing permit
conditions are required. Increases in annual emissions from the Sulfur Recovery Unit are
considered in the PSD applicability and ambient impact analyses.
Technical Support Document Page 8
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
Sour Water Unit
Existing unused capacity within the sour water unit will be used to strip the H2S and NH3 from
the sour water generated by #3DHDS. The existing sulfur recovery unit will be used to recover
the additional sulfur. The new sources of sour water include the feed surge drum, cold high
pressure separator, stripper overhead drum and vacuum dryer separator drum. The additional
sour water would be directed to the sour water unit for stripping.
A separate project, called the Sour Water Handling Upgrade Project (SWHU), was permitted and
approved by the NWCAA in May 2009. Construction is ongoing. Although that project had
independent utility, the upgrade provided capacity needed to accommodate #3DHDS. The
contemporaneous emission increases are included with the Clean Fuels Project PSD
applicability determination and ambient impact analysis.
The extent of changes affecting the sour water unit is limited to tie-ins to the sour water header
from the new diesel hydrotreater. No other capital investment is planned as part of the proposed
Clean Fuels Project. As stated previously, no increase in allowable emissions from the sulfur
plant will be requested. The sulfur recovery complex will continue to be operated within
existing permitted emission limits.
Flare Gas Recovery Unit
Several new flare connections would be made from #3DHDS into the existing High Pressure
Flare. Examples of the types of connections include, but are not limited to, pump seals,
compressor seals, compressor distance piece vents, instrument purges and sweep gas used to
keep the flare header free of oxygen. Although the flare header is used as a means of collecting
the gases, both flare headers are equipped with flare gas recovery compressors. During normal
operation, the collected gases are treated for H2S in a shared amine absorber and routed to the
refinery fuel gas. The flare gas recovery system has excess capacity to handle all normal
operation flows from #3 DHDS. The Clean Fuels Project would not result in any increases in
routine flaring of the High Pressure Flare. However, #3 DHDS would be depressurized to the
High Pressure Flare in preparation for turnarounds. Emissions from planned startup and
shutdown events are included in the emission inventory.
High Pressure Flare
#3DHDS would be connected to the existing high pressure flare system. Any new or modified
flare would be subject to New Source Performance Standard Subpart Ja.
It is anticipated that applicability of Subpart Ja for the existing flares would be triggered prior to
construction of the Clean Fuels Project and the existing flares would be brought into compliance
with emission standards, monitoring, recordkeeping, and reporting requirements under a separate
capital project that would be completed prior to startup of the Clean Fuels Project. As of this
writing, the flare provisions are not yet finalized. Note, however, that the flare project would
reduce (not increase) emissions so it is not necessary to consider whether the flare project should
be aggregated with the Clean Fuels Project.
Technical Support Document Page 9
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
Steam
The refinery has different steam distribution networks named for the various delivery pressures.
The #3DHDS would consume 6,000 lb/hour of high-pressure steam for the stripper and
2,600 lb/hour of lower pressure steam for the lean amine heater. The proposed hydrogen plant
would produce enough steam to support the steam-methane reforming reactions that produce
hydrogen as well as export 140,000 lb/hour of steam onto the refinery distribution header. As a
result, the existing boilers would be used less, resulting in an emissions reduction. No netting
credit is requested.
2.3. PSD Applicability and Air Pollutant Emissions
BP is an existing major source4 of a regulated pollutant.5 The facility has several existing PSD
permits for refinery processes and equipment. It has minor new source review permits and a
Title V air permit issued by the Northwest Clean Air Agency (NWCAA).
A project is a major modification for a federal PSD regulated NSR pollutant at an existing source
if it causes two types of emissions increases: (1) a significant emissions increase, and (2) and a
significant net emissions increase.6 The first step includes emissions increases due to new
equipment, and any emissions increases in other refinery operations due to the project. The
second step applies to regulated pollutants that are found to be significant from the first step.
This step considers any emissions decreases due to the project, and any contemporaneous
increases and decreases at the refinery during the previous 5-year contemporaneous period.
Additions and modifications to the refinery that increase a pollutant’s emissions more than the
second step’s PSD Significant Net Emission Rate (SER) are considered ―major modifications‖
and are subject to the PSD permitting process.
Two PSD programs operate concurrently in Washington State. A state PSD program is defined
in the state regulation WAC 173-400-700 to 750. The Federal PSD program is implemented by
the Washington State Department of Ecology’s Air Quality Program under a delegation
agreement dated February 23, 2005, which authorizes implementation of PSD regulations in
52.21 as of July 1, 2004 (with several restrictions). Authority for federal PSD regulatory
requirements newer than that date is achieved by EPA cosigning each PSD permit.
4
Petroleum Refineries are a major source under PSD regulations if they, in total, have the potential to emit more
than 100 tons per year of a pollutant regulated by the PSD permitting program. WAC 173-400-720(4)(a)(v) and 40
CFR 52.21(b)(1)(i)(a).
5
The PSD program directly regulates a list of specific pollutants listed in 40 CFR 52.21(b)(23). These are referred
to as ―regulated pollutants.‖ PSD regulates other pollutants indirectly through the broad categories of ―regulated‖
pollutants such as VOC and particulates. In Washington State, the local air authority issues its own permit that
complements the PSD permit and includes all emissions regulated by state and local regulations. WAC 173-400-
113.
6
40 CFR 52.21(a)(2)(iv)
Technical Support Document Page 10
BP Cherry Point Refinery PSD-10-01
Clean Fuels Project
Determination of PSD Applicable Pollutants
The proposed Clean Fuels Project will result in addition of two new process units, retrofitting
one Hydrocracker heater with ULNBs, and affect the utilization of seven existing process units at
the Cherry Point Refinery. This section summarizes the emission rate increases attributable to
the proposed project including potential emission rates for the new emission units and annual
emission rate increases for existing emission units. It also describes potential emissions
decreases due to the project, and contemporaneous increases and decreases in five other projects
that occurred during the 5 year contemporaneous period. More detailed calculation of these
emission increases and decreases are included in Appendix A.
This analysis fulfills the requirements of the two-step PSD applicability determination procedure
referenced above. Table 1 lists the emissions increases due to the new equipment and increased
utilization of existing refinery processes. Table 2 lists the decreases due to the project and the
contemporaneous increases and decreases.
Table 1. Regulated Pollutant Emission Increase for Clean Fuels Project
Compon HC 1st HC 2nd
#2 H2 #2 H2 #3DHDS Sulfur Total
ent HC R-1 HC R-4 Stage Stage #2 Cool. WWT HP Flare PSD
Plant Plant Charge Recovery Emission
Fugitives Heater b Heater b Frac. Frac. Tower b Pb b
SER d
SMR a Flare a Heater a a Plant b Increase
Rblr. c Rblr. b
Pollutant (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY) (TPY)
NOX 15.5 2.5 4.3 -- 2.4 0.1 12.6 0 23.4 -- -- 0.01 61 40
CO 18.9 6.5 4.5 1.3 9.3 10.8 3.9 16.7 4.6 -- -- 0.1 77 100
SO2 6.3 0.081 3.2 -- 4.6 5.4 2.5 10.8 3.0 -- -- 0.4 36 40
PM (filterable) 5.4 0.09 0.3 -- 0.03 0.5 0.2 1.0 0.3 0.7 -- 3.8E-04 9 25
PM10 (filterable) 5.4 0.09 0.3 -- 0.03 0.5 0.2 1.0 0.3 0.7 -- 3.8E-04 9 15
PM10 (total) 21.7 0.37 1.2 -- 0.13 2.1 1.0 4.2 1.2 0.1 -- 1.5E-03 32 15
e
PM2.5 (filterable) 5.4 0.09 0.3 -- 0.03 0.5 0.2 1.0 0.3 0.0009 -- 3.8E-04 8 10
VOC 11.7 3.8 0.7 2.4 0.07 1.1 0.5 2.3 0.6 1.24 10.5 0.02 35 40
Pb 1.1E- 1.8E- 1.0E- 4.8E- 2.1E- 5.7E-
6.0E-05 -- 6.6E-06


Use: 0.3765