HomeMy WebLinkAboutMINUTES - 01171995 - 1.4 (3) 1.39 through 1.43
THE BOARD OF SUPERVISORS OF
CONTRA COSTA COUNTY, CALIFORNIA
Adopted this Order on January 17, 1995, by the following vote:
AYES: Supervisors Roger, Smith, DeSaulnier, Torlakson, and Bishop
NOES: None
ABSENT: None
ABSTAIN: None
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SUBJECT: CORRESPONDENCE
Item No.
1.39 LETTER from Associate Planner, Urban Futures, Inc., transmitting documents relative to
the commencement of redevelopment activities in the Lafayette area.
"REFERRED TO COUNTY ADMINISTRATOR,COMMUNITY DEVELOPMENT
DIRECTOR AND COUNTY COUNSEL
1.40 LETTER from D. L. Patrick, Martinez, expressing concerns relative to the modification
project at the Shell Refinery.
"REFERRED to Environmental Health Department, County Administrator, and
Community Development Department, the letter from D.L. Patrick, Martinez,
expressing concerns relative to the modification project at the Shell Refinery, for
review,contacting the Bay Area Air Quality Management District Board, and report
to the Board of Supervisors with information for consideration of possible hiring of a
consultant relative to the issues involved.
1.41 LETTER from L. Marracci, Lafayette, commenting on access time on cable television.
"REFERRED TO CABLE FRANCHISE ADMINISTRATOR
1.42 LETTER from Chair, Advisory Council on Equal Employment Opportunity, requesting a
opportunity to meet with the Internal Operations Committee.
"REFERRED TO INTERNAL OPERATIONS COMMITTEE
1.43 LETTER from Trident Environmental and Engineering, Inc., expressing concern that a
possible conflict of interest exists in the award of the contract for solid waste engineering
review for the County.
"REFERRED TO HEALTH SERVICES DIRECTOR
I hereby certify that this is a true and correct copy of
an action taken and entered on the minutes of the
Board of Sup isors on the date sho �
ATTESTED: r�.t '1 n
cc: Correspondents PHIL BA HELOR, Cle of the Boar
p of Supervidors and County Administrator
Counry Administrator
Community Development Director a1� )ilM�v� LiA."LIDeputy
County Counsel
Community Development Director
Cable Franchise Administrator
Internal Operations Committee
Health Services Director
46
DOCUMENTATION:
1993 PROJECT:
Shell's 1993 modification project proposes to produce gasoline that meets Clean
Air Act requirements and includes a residual coker to replace gasoline lost to
expanded processing without increasing crude oil throughput. The EIR
description of the residual coking complex and its impacts indicates that Shell will
double gasoline production.
The 1993 EIR Clean Fuels Proiect does not specify existing or anticipated production.
The project continues the same 1980 BAAQMD permit limiting production of 128,000
barrels/day. The BAAQMD maintains expansion is allowed under 1984 permit
modifications that established a refinery emission banking system called either a
"bubble" or a "cap". No language in the 1984 permit modification facilitates expansion.
Shell's existing refinery includes a residual coker. The 1993 Clean Fuels Project
includes a second residual coking complex composed of
• a Delayed Coker Unit' including six vertical drums 120 feet tall with a combined
length of 180' and width of 30'. The drilling equipment would be approximately 130'
tall, making the combined structure 250' tall. In addition there are three heaters
100' tall by 60' square with a 250' tall stack 11' in diameter, and three columns: 175'
x 8', 170' x 19' and 145' x 10.
• a Coke Barn2 400' x 200' and 100 feet tall.
• a Coker Gasoline Splitter Columna, 110' tall x 7' in diameter.
• and a Lube Hydrotreatee, to be located near the existing lubricants facility, with a
150' x 2' stack.
The second residual coking complex is now under construction 600' from the 1-680 near
the Benicia bridge. The EIR does not describe-the capacity of any equipment.
' Page 3-49, DEIR Shell Oil Company Clean Fuels Project (Land Use Permit 2009-92; State
Clearinghouse#92093028) Contra Costa County, May 1993.
2 Page 349
3 Page 3-48 describing the Coker Gasoline Splitter Column states"This unit is in keeping with
Shell's objective of upgrading heavy fuels and thus maintaining existing levels of gasoline
production while producing reformulated gasoline." while page 3-17 Project Objectives in
contrast claims, "These units, the Delayed Coking Unit, Coker Gasoline Splitter Column, and the
Lube Hydrotreater are not required to producing reformulated gasoline."
4 Page 3-50
1
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Indications of expanded gasoline manufacturing within the 1993 EIR:
• The coking complex objective titled `B. Upgrade,Heavy Fuels and Sustain Existing
Gasoline Production"states:
"...To meet its objective of maintaining gasoline production levels without
increasing crude rate, Shell is including new units which will upgrade
heavy fuel stocks to lighter products in order to replace lost gasoline
volume. In addition, the upgrading of high sulfur fuel(marine fuel oil) and
lubricant oils will produce cleaner and more economically valuable
products5... ,6
Importing residuals is carefully phrased in the last sentence above.
• Additional coking materials(marine fuel oil and lubricant oils) and the increased
gasoline and jet fuel produced from them are included in a list of 2,151,171
additional barrels of hazardous material that will be on site after proiect completion
including:
• 424,599 additional barrels of gasoline and
9 310,945 additional barrels of jet fuel,
that will be manufactured from the following:
0 87,747 additional barrels of sludges
80,724 additional barrels of rerun hydrocarbon
• 164,524 additional barrels of marine fuel oil
93,231 additional barrels of lube oil
202,910 additional barrels of crude oil
Over 1000 additional tons of air pollution? will be released annually. The Air District
claims that Shell has banked emission credits sufficient to cover increased air
pollution. Documentation that illustrates Shell's emission bank was established
with exaggerated emissions and dishonestly achieved a credit balance starts on
page 13.
5 Chapter 3., Project Description, Page 3-7, OBJECTIVES AND REQUIREMENTS, B. Upgrade
Heavy Fuels and Sustain Existing Gasoline Production, DEIR Shell Oil Company Clean Fuels
Project
6 Chapter 20. Alternatives, Page 20-1, the three project objectives are listed as:
1. To produce reformulated gasoline as required by new State and federal requirements;
2. To upgrade heavy fuels to higher value fuel products;and
3.. To maintain existing production levels of gasoline without increasing usage of crude
oil.
Again no mention of importing residual coking stock from other refineries.'
Response to Comments Document for the Shell Oil Company Clean Fuels Project, August,
1993, Letter 3 from the BAAQMD, Table 8-16. attachment#6
2
• ! �� ya
• Bob Andrews, Shell's current manager stated that 100 additional coke filled gondola
rail car trips/day8 will occur when the project is fully operational -- even though the
1993 EIR forecast rail car traffic will total 13,000 to 14,500 trips/year(40 trips/day),
with 85% of those cars anticipated to cant' coke9.
• The 1993 EIR undervalues existing rail use, claiming the same number as in the
1979 EIR -- 7.4 trips/day. Observation indicates rail traffic has expanded by more
than.ten cars/day.
• The 1993 EIR suggested (and the County approved) allowing two existing MTBE
tanks, with undisclosed storage capacity, be permitted to store either a variety of
oxidizing agents or gasoline without consideration of the potential for increased
gasoline manufacturing10. No new gasoline storage tanks were proposed in the '93
rp olect
• A diagram of the Delayed Coker Unit , Figure 3-1911, lists three sources of feed
stock, the last listed references importing residuals from other refineries:
1. Pitch (crude bottoms) from existing crude unit
2. Bottoms from existing catalytic cracking unit
3. Residual from existing lube and imported
Indications not included in the 1993 EIR that indicate Shell is significantly
expanding gasoline production:
1. Shell closed their other California refinery at Wilmington about four years ago,
creating the need to expand production elsewhere. Gasoline manufactured in
Martinez is now loaded into multiple marine tankers weekly for delivery to the
Wilmington wharf. Shell has only one other West Coast refinery, a smaller.
refinery at Anacortes Washington.
2. Tank#12467, a 140,000 barrel exterior floating roof gasoline tank with 100 x
annual throughput, (not described as existing or planned in the 1993 EIR), is now
under construction 85' from the Marina Vista Ave. roadway and below hillside
homes. The tank was originally permitted by the BAAQMD December 27, 1991.
Permitting irregularities for this tank include:
8 Response to questioning at Board of Supervisors hearing on Clean Fuels Project, October,
1993
9 Page 11-47, Draft EIR, Chapter 11. Risk of Upset
10 "The proposed project also includes use of the two existing methyl tertiarybutyl ether(MTBE)
tanks (Tank 12445 and Tank 12446)to store other oxygenates and gasoline and gasoline
blending compounds." Page 3-2, and also page 3-53 which lists four other oxygenates besides
MTBE and gasoline, and says "Shell's current Air District Permit to Operate allows them to store
these other materials in these tanks, but they also need a land use permit for this action."
11 Page 3-49, 1993 Draft EIR, Chapter 3. Project Description attachment#5
3
• issuing a ministerial permit, exempting tank#12467 from risk analysis because it
didn't have a stack nor was it located in a building --without consideration to it's
location within a group of six antiquated, exterior floating roof gasoline tanks,
five of which are in close proximity to the road below peoples homes. A copy of
BAAQMD engineer, Hon Ting's memo to Shell exempting this tank from risk
analysis is attached. Also a copy of the current BAAQMD risk screen that
exempted the tank from risk review and the 1991 BAAQMD risk screen that it
replaced -- which would have required risk screening. Why did the BAAQMD
structure risk screening to exempt gasoline tanks?
• Tank#12467 was originally ministerially permitted in 1991 when the 1985 AP-42
(which undervalues emissions by seven times) was still in effect. Had it been
permitted today the 1985 AP-42 would still have been used as LARGE TANKS
(20,000 gallons or greater)12 require application of the out-of-date AP-42.
• Shell reported that tank#12467 would not lead to an expansion in production
nor present risk on their City of Martinez land use permit application. The
BAAQMD permit allows 100x annual throughput and does not require a flow
meter.
• Bechtel Environmental, Inc. July 1993 submission to the City of Martinez for
Tank#12467 land use permit, claimed the tank "will not cause an increase in
the present MMC production capacity.13i -- Bechtel is building Shell's Clean
Fuels Project. .
• Bechtel's report called this a "replacement of four existing fuel storage tanks
j with a new unleaded gasoline tank14," the four tanks equaled half the capacity
and the second largest tank, #128 was taken out of service in 1981.
• Bechtel avoids disclosing that no risk assessment was accomplished and states
"Placement of the tank in this location provides a greater margin of safety (with
respect to distance from a public thoroughfare) than the current location of Tank
994 which is approximately 45 feet from Marina Vista Blvd.15" Tank 12467 is
said to be 85' from the street. � The 1979 E/R reported that "The closest
exposure (approximately 100 feet) the public has to oil storage facilities is the
"Crude Hill"area...Because of the close proximity of these storage tanks to the
public, Shell long ago adopted a policy of storing only low-volatility oils (e.g.
12 BAAQMD tank permitting criteria, page 21-4 (adopted 7/15/91) attachment#11
13 Page 2-1, Shell Oil Company Martinez Manufacturing Complex, Conditional Use Permit
Application for Tank 12467, Submitted to City of Martinez, Bechtel Environmental, Inc., July
1993
14 Page 2-2
15 page 4-4
4
heavy gasoils, lube oils, residual fuels and diesel) in these tanks 16" The hillside
community is now sandwiched between Crude Hill-- which now contains jet fuel
tanks and the six exterior floating roof gasoline tanks below.
• Leonard Clayton, a retired air district engineer applying current AP-42 risk
analysis, determined that should this tank catch fire and explode, a fireball
over one mile in diameter could cause death within a four mile radius. His
report" advises requiring an EIR.
• John Swanson, permitting chief for the BAAQMD, spoke on behalf of She at a
City of Martinez public hearing on this tank and encouraged issuance of a
negative declaration rather than examining risk through the CEQA process as
requested by most speakers during the three hour hearing. He stated that the
BAAQMD issued ministerial permits for all tanks.
• The tank location noted on the BAAQMD application, permit and
correspondence is inaccurately listed as 3485 Pacheco Blvd., on the other side
of the refinery in unincorporated Martinez78. Marina Vista neighbors who saw
the BAAQMD storage tank notice with a Pacheco Blvd. address had no way of
knowing that this gasoline tank would be located near their homes.
3. Shell converted some of the tanks located less than 100' from Marina Vista to
gasoline storage after 1980. This conversion was not anticipated in the 1979 EIR,
nor were neighbors notified.. A copy of Shell's application to convert tank 1046 to
from jet fuel to gasoline storage to gasoline is attached.
4. In January 1994 the ARB approved a 20% increase (33,103 additional barrels/day)
in gasoline loading at six Shell bulk loading terminals in California. The 7,806
additional barrels increased loading at the Martinez bulk terminal equates to 30
more tanker truck trips on Marina Vista. The Marina Vista bulk loading terminal's
expansion was not considered in the 1993 Clean Fuels Project EIR.
note: the 1979 EIR claimed 54 existing truck trips that would expand by seven to a
total of 61 truck trips/day post modemization19 Observation indicates that the
current number of truck trips/day is significantly higher.
Shell's.bulk gasoline loading terminal is accessed without dedicated tum lanes or
other traffic control measures on Marina Vista, an undersized arterial with 10'wide
16 page D-2, Health and Safety, Appendicies Volume DER SHELL OIL COMPANY MARTINEZ
MANUFACTURING COMPLEX MODERNIZATION, Prepared by Contra Costa County, October
1979
17 Leonard R. Clayton, Environmental Engineer, May 10, 1994 review of gasoline storage tank
#12467 attachment#8
1e In 1991 the CCC planning director requested that the BAAQMD start notifying the County of
pending permits. This tank was listed on a 1991 report as a storage tank with the Pacheco Blvd.
address. I thought at the time that it would trigger County Ordinance 86-100 requiring permit
review for expansions. Instead the tank was constructed in the City and Shell claimed that it
wouldn't contribute to an expansion.
19 Page G-1-1, 1979 DER Appendicies Volume
5
lanes and no siding. The entry space before the bulk terminal gate is insufficiently
sized, requiring that when more than one double tanker is in line, the back end of
the second is on the street and if other tankers arrive, they wait in a traffic lane on
the street.
5. Shell ceased internal rail switching about three years ago, and now switches
hazardous material on the SP rails through town at night. Was this change
accomplished in anticipation of the need to switch more than 100 cars/day, or was
Shell freeing up the location of the internal switching yard for a different use? Shell
now claims that they have always switched cars through town. The 1979 E/R
described the on site rail car switching track that would continue to be used after
project completion.
6. During the past three years the number of hazardous material filled tank cars stored
on the unprotected rails west of town has increased dramatically. Could Shell be
storing cars here in order to establish this expanded use as an ongoing practice --
or has production increased again?
7. Shell began operating a 260,000,000 BTU/hour thermal oxidizer in November
1992 to incinerate marine loading vapors as required by BAAQMD Regulation 8,
Rule 44, The Marine Vessel Loading Terminals rule. This rule requires that marine
loading emissions of over 2 lbs/1000 barrels of liquid loaded be reduced by 95% by
weight from uncontrolled conditions. Shell should have been exempt from this rule
based on calculated loading emissions established in the 1984 permit condition
modifications which claims that none of Shell's marine loading emissions are higher
than 1.7'Ib/1000 gallons loaded. The highest emissions in this permit are for various
types of crude oil rated at 1.7 Ib./1000 gallons, even though the only crude Shell
loads (for transport to the Anacortes refinery) is San Joaquin Valley crude rated at
.06 Ib/1000 gallons. Shell's loading emission factor for finished gasoline is only 1.4
Ib/1000 gallons loaded.
How Shell can double gasoline production without public scrutiny:
Equipped with a modification EIR that doesn't address expanded gasoline production,
but documents impacts from expanded gasoline production, a County land use permit
that doesn't limit production, at least three new gasoline tanks20, a thermal oxidizer
scaled to accommodate higher volumes of marine gasoline loading vapors, and a new
wastewater system of unknown size under construction, Shell will rely on the BAAQMD
Rules and Regulations to facilitate this expansion by employing BAAQMD Regulation
2-1-404 (attached) which allows equipment to increase production:
"if emissions resulting from such changes are not of such quantity as would cause
denial of an authority to construct..."
or Regulation 2-2-223
20 Two MTBE tank conversions of unknown size and the 140,000 barrel tank currently under
construction
6
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"...Unless previously limited by a permit condition the following shall not be
considered changes in method of operation:"
223.1 An increase in the production rate if such increase does not exceed the
operating design capacity or the actual demonstrated capacity of the
facility as approved by the APCO."
Since emissions and impacts are listed in the EIR without a description of existing or
future gasoline manufacture or crude oil throughput, Shell can develop up to the
emissions described and if the coking emissions increase, Shell will rely on their 1984
"Bubble Permit" that established the emission cap/bank system that allows emissions
reduced elsewhere to be transferred, in this case to the residual coking facility. (A
description of how Shell's emission banking account was inflated when established and
operated in favor of Shell starts on page 13.
The BAAQMD has historically accepted misinformation that facilitated unregulated
growth. This practice is now required by
Regulation 2-1-428 Procedure for Ministerial Evaluations:
"...For such projects, the District will merely apply the law to the facts as presented
in the permit application, and the District's decision regarding whether to issue the
permit will be based only on the criteria set forth in Section 2-1-428 and in Volume 11
of the District's Manual of Procedures."
(Adopted July 17, 1991)
Will Shell scrap the 1977 emission baseline in favor of the current emissions
Banking Credit Period Rule 2-4-202 as follows?
"...The last twelve consecutive month period of actual emissions or a more
representative twelve consecutive month period, approved by the APCO,
occurring during the last five years immediately preceding the banking
application date."
(Adopted July 17, 1991)
THE 1979/8 PROJECT
The 1979 Shell Oil Company Martinez Manufacturing Modernization Project EIR
proposed a modification project to process high sulfur crude and increase
gasoline production by 11,000 barrels/day and jet fuel by 4,000 barrels/day without
increasing throughput. The wharf was to be strengthened and modernized to
import Alaskan crude oil. Contra Costa County was lead agency.
7
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1979/80 MODIFICATION PROJECT EIR CLAIMED TO MAINTAIN
PRODUCTION -- INSTEAD, PRODUCTION IS EXPANDED BY 42,000
BARRELS/DAY
1. Shell's recorded refining capacity was 108,000 barrels21 when the 1979 Martinez
Manufacturing Complex Modernization EIR, (based on Shell's 1979 BAAQMD
application,) claimed refining capacity as 128,000 barrels/day. Manufacturing was to
be modernized to increase gasoline manufacturing by 11,000 additional barrels/day
and aviation turbine fuel production by 4000 more barrels/day22 without increasing
crude oil throughput23,.
In 1992 production had expanded to around 150,000 barrels/day24 even though
Shell's BAAQMD permits still limit throughput to 128,00 barrels/day.
2. The EIR also claimed that existing gasoline production represented as 51% of a
barrel of crude oil would increase to 60% per barre125. Long term Shell employees will
tell you that Shell was incapable of producing 51% gasoline prior to installation of
modernization equipment. Shell Oil Co., Martinez was known as a lube oil plant then.
1980 BAAQMD PERMITS LISTS BIG INCREASE IN GASOLINE PRODUCTION:
"the proposed modifications will not increase the overall capacity of the refinery,
which is presently 128,000 ba►rels/calendarday. However, these
modifications will significantly increase crude distilling capacity, resulting
in increased gasoline and aircraft turbine fuel production and a
corresponding decrease in heavy fuel production26
The BAAQMD and numerous consultants hired to scrutinize Shell's 1979 application
and prepare the EIR, had access to documentation and professional expertise to
determine that the EIR falsely described the project's use, exaggerated existing
throughput and gasoline manufacturing capability. Experts would know that ship
pumps unload whereas loading is accomplished by on shore pumps. There was no
reason to install the proposed equipment to unload Alaskan crude oil. Experts would
21 The Oil and Gas Journal, March 20, 1978, page 116 attachment#23
22 79 EIR, pages 1, 13
23 79 EIR pages 1, 13
24 The Oil and Gas Journal, December 21, 1992, page 85 lists calendar day throughput as
146,500 barrels/day, indicating stream day was 150,000 b/d. 128,000 and 108,000 are listed as
stream day. attachment#24
25 page 14
26 page, 1, SHELL OIL COMPANY ENGINEERING EVALUATION APPLICATION#26786,
3/19/80, 1. Project Scope-first paragraph. attachment#27
8
know the capacity of proposed equipment and additional tankage would increase
manufacturing by 50%.
Documentation is available that reports actual ship visits and quantities loaded 27
THE 1979 EIR CLAIMED WHARF IMPROVEMENTS WERE REQUIRED TO
IMPORT ALASKAN CRUDE OIL AND INSTEAD IMPROVEMENTS WERE
USED TO EXPORT GASOLINE AND CRUDE OIL -' ACTIVITIES NOT
ADDRESSED IN EIR
The 1979 EIR reported: "Records of vessel operation indicate that the wharf .
accommodated a total of 194 ship (tanker) and 247 barge voyages (round trips) during
1977
SHELL'S 1980 BAAQMD ENGINEERING EVALUATION REVEALS AIR
DISTRICT KNEW SHELL PLANNED TO LOAD 10.9 MILLION BARRELIYEAR
GASOLINE AT WHARF
Shell's BAAQMD engineering evaluation addressed loading 10.9 barrels/yr of gasoline
at Shell's wharf. Loading 10.9 million barrels/year of gasoline was not mentioned in the
EIR. The BAAQMD received wharf use and refining records regularly to know that
Shell did not have capability to load gasoline (except through 5" hoses).
Had Shell loaded 5.3 million barrels/year gasoline in the past, as reported in the
engineering evaluation, BAAQMD rule required permit review for expanded use.
How Shell's 1979 EIR, 1980 BAAQMD permit and 1984 modifications exaggerated
ship trips and loading emissions to establish the marine loading terminal. And
how independent documentation contradicts Shell/BAAQMD tanker visits and
wharf emissions.
Shell likely planned to export San Joaquin Valley Crude to their A nacortes refinery and
arranged installation of the equipment to do so by claiming to import Alaskan crude.
The BAAQMD modified their permit in 1984 to accomodate this change even though
Shell started loading SJV crude in 1982.
27 State lands Commission barrel tax records for Aug., Sept. & Oct. 1979 indicate that
Shell did not have the capacity to load finished gasoline at their wharf until the end of
1979. No finished gasoline was loaded during this reporting period. attachment# 15
US Army Corps of Engineers,Waterborne Commerce Division records indicate a total of
only 140 ship visits(loading/unloading) in 1977, this includes bay transfers of crude oil delivered
to Shell's wharf by barge. 1977 Shell/BAAQMD reported more gasoline loading at Shell's wharf
than reported by the five refineries with wharves in the Carquinez Strait region. attachment#28
9
Why was the focus of the'79 EIR on Very Large Crude Carrier stack emissions, listed
as the number one air quality impact, and ballasting emission 28 when gasoline loading
emissions, though grossly undervalued in the BAAQMD application were accepted as
3221 tons/year?
Prior to installation of the 16" gasoline line from the refinery to the wharf in late 1979 or
early 1980, the EIR identified Shell's only marine gasoline loading capability as
stringing 5" hoses from the refinery to the wharf. The existing pipelines to the wharf
(prior to the end of 1979 when the gasoline line was installed,) were "black lines" too
contaiminated to carry gasoline. The BAAQMD received monthly loading records from
Shell's wharf to know that gasoline loading would be a new activity that should have
been addressed in the EIR.
1. Shell never received Alaskan crude oil but the following equipment listed in the
1979 EIR was installed to unload it from Very Large Crude Carriers 29
• Four 16" and one 10" articulated loading arms supported by additional
piles,
• an elevated operators shelter,
• an emergency shut-off system with hydraulic valves and hydraulic coupling
to ships the ships manifold and unloading equipment:
• a 36" crude oil pipeline,
• . a 16" gasoline line and 4500 ft. of 16" pipeline from Berth #1 & 2 and over
Marina Vista pipebadge30
• a 386,000 barrel crude receiving tank.
2. The '79 EIR did not describe loading gasoline. The only gasoline marine loading
reference mentioned that a 16" gasoline line would be installed from the refinery to
the wharf,.
3. The equipment was installed but never used to import Alaskan crude. Instead it has
been used since 1982 to load San Joaquin Valley Crude piped from Shell's
Bakersfield oil field, for delivery to the Anacortes refinery.
4. The 1979 EIR claimed the most significant air quality impact resulted from SO2
emissions from Very Large Crude Carriers stacks37
-- which never arrived.
Shell's 1980 BAAQMD engineering evaluation 32 listed gasoline loading that should
have been addressed in the 1979 EIR:
28 Page C-2-15 and C-2-16 , 1979 Appendicies Volume
29 Pages 12 & 13, Goal I, 1979 DEIR Attachment# 14
30 Page B-2-2, Description Of Proposed Facilities, 1979 DEIR Appendicies Volume
31 Page 41, Air Quality Impact Summary, 1979 DEIR
32 Page 10, BAAQMD permit titled "SHELL OIL COMPANY ENGINEERING EVALUATION
APPLICATION#26786, 3/19/80 Attachment#27
10
"The following marine operations shall be limited to those volumes listed in Tables 3
and 4 - WharfNolume I of the Permit Application, namely:
a. Gasoline loading 10,950 M barrels/year
b. Turbine fuel loading 1,925 M barrels/year
c. Ballast for crude tankers 649 M barrels/year
without segregated ballast
d. Lightering of crude within S.F. Bay 1,099 M barrels/year
The Air District knew that Shell did not have the capability to load gasoline, except.by 5"
hoses strung from the refinery, prior to installation of loading equipment. The District
had also received wharf shipping records for many years prior to Shell's 1979
application and should have questioned Shell's claim to have loaded 5.3 million barrels
of gasoline. Why didn't the Air District require vapor recovery for the (undervalued) 322
annual tons.of hydrocarbon emissions anticipated in Shell's application? Wickland
Martinez and Tosco both were required to install vapor recovery systems at their
loading docks around that time.
EIR AND ENGINEERING EVALUATION FALSIFY SHIPPING STATISTICS:
1. The 1979 EIR reported "Records of vessel operation indicate that the wharf
accommodated a total of 194 ship tanker and 247 barge voyages (round trips)
during 1977. The maximum cargo capacities of the ships ranged from 30,000 to
70,000 deadweight tons."
2. Shell's 1980 BAAQMD Engineering Evaluation claimed:
"the increases are for the most part due to maneuvering, and unloading, of
the 120 to 189,000 dead weight ton vessels which will visit Shell's wharf in
the future. Use of these larger vessels will however reduce the total number
of vessels visiting the wharf from 441 to 370 per year....Only hydrocarbon
emissions will increase, due to increased ship loading of gasoline. This
increase will be offset by additional control of hydrocarbon emissions from
refinery storage tanks."
(US Army corps of engineers reported 140 total ship visits. Increased gasoline
loading not mentioned in 1979 EIR. The 1984 permit modification also credits
Shell's baseline for storage tank controls)
3. The 1979 EIR based on Shell's 1979 BAAQMD application, exaggerated existing
wharf emissions by claiming 245 tons of hydrocarbon were released from the wharf
in 1977
33 The BAAQMD accepted Shell's undervalued gasoline loading formula of 1.4 lbs per 1000
gallons loaded.
4 Wickland is current owner, previous was something like Urich or UCO
35 Page 57, 1979 DEIR, attributed to M.S. Waller, Staff Engineer, Shell Oil Company
36 Unnumbered page 4, SHELL OIL COMPANY ENGINEERING EVALUATION APPLICATION
#26786 dated 3/19/80 attachment#27
11
4. The State Lands Commissions started collecting a barrel tax from refineries whose
wharves were on State lands in August, 1979. Shell provided explicit
documentation as to materials loaded/unloaded. Since most of the same ships
visited Shell's wharf in 1979 as in 1977, it is likely that the barrel tax shipping
records for a three month period in 1979, reporting that no finished gasoline was
loaded or unloaded at Shell's wharf in August, September or October 1979,
supports the premise that Shell did not regularly load gasoline. Application of the
Shell loading factors suggest that annual wharf emissions averaged about 80
tons/year maximum. A list of the materials and quantities loaded for this period is
attached.
5. The US Army Corps of Engineers, Waterborne Commerce records report only a
total of 140 ships either visited or were unloaded into barges in the Bay for transfer
to Shell's wharf in 1977. Shell claims to have loaded more gasoline and crude oil
that was recorded in total for the five refinery wharves located in the Carquinez
Straits Region for 197737. [note: the EPA obtained these records which are
supposed to list materials comparable to those included in Steve Hill's memo.
These records must be reviewed to determine how 15,698,666 barrels of materials
(including 5,321,690 barrels of gasoline) could be loaded into approximately 70
small ships.] Gasoline can only be loaded into clean, dedicated ships or barges.
SF Marine Exchange record that the same ships visited Shell's wharf in 1977 as the
1979 period in which the State Lands Commission records indicate_no finished
gasoline was loaded at the wharf. Finished gasoline marine loading in 1977 is
extremely unlikely.
6. The San Francisco Marine Exchange recorded that 108 tankers arrived at Shell's
wharf in 1977. These records include the name and size of the ships. Most of the
ships that visited Shell's wharf were small T-2 parcel tankers with 15 to 20
compartments, leased to Shell and owned by Werner. The following Werner ships
were used extensively by Shell in 1977. The compartments could be loaded with
different materials during the same trip. The total capacity of each ship:
the Austin -with a net capacity of 11,524 tons
the Houston - 11,178 tons
the Pasadena 11,340 tons
In 1977 only one ship the Judith Prosperity, arriving from Singapore, docked
at Shell's wharf October 30, 1977 with net capacity of 35976 tons, was large
enough to accommodated 192,566 barrels of gasoline. (This ship may have
received gasoline as tanker holds are cleaned in Singapore.
37 1977 US Army Corps of Engineers, Waterborne Commerce record attachment#28
38 The 40 gasoline loads c@ 19,000 plus tons equals almost twice the size of these ships total
capacity.
12
7. 1983 BAAQMD Shell Wharf hydrocarbon shipping emission statistics stamped
Steve HiIP9 claims:
A total of 215 ships were loaded (with 18 receiving ballast) at Shell's wharf
in 1977,
40 of these were said to be loaded with 7,702,642 barrels of gasoline,
averaging 192,566 barrels per ship.
8. The 1993 EIR reported that 542 barges and 220 ships called at Shell's wharf in
198840.
SHELUBAAQMD INFLATED EMISSION CAP WAS INACCURATELY STRUCTURED
AND OPERATED TO CREATE 1000 TONNEAR PLUS EXCESS TO COVER 1993
1000 EXCESS EMISSIONS:
The 1984 WOR Permit Modification established Shell's "Bubble Permit" -emission
cap and banking system with exaggerated wharf loading emissions and included
tank emissions that were used as offsets in the `79 project. Shell's account was
manipulated to provide Shell with sufficient credits to construct the 1993 project
without purchasing emission credits or creating off-sets:
39 1 received this document from Gary Rubenstein who said he received it from and it was
authored by Steve Hill. Steve Hill gave me his 1984 memo without the loading hydrocarbon
calculations attached. It is stamped "Steve Hill Mar 21 1983" attachment#20
40 Page 8-63, 1993 DEIR, credited to Korve Engineering..
13
1984 BAAQMD permit modification to the 1980 permit "establishes an emissions
"bubble" for most of the refinery: emissions from sources will be tracked by computer'
according to the Notice of Permit Modification 41 The modification makes no mention of
expanding production beyond 128,000 barrels.
• Permit modification wording on page two established the wharf baseline:
"g. The actual emissions due to shipping in the base year 1977 were added to
the adjusted refinery baseline."
• The inflated emissions included in the application and altered in the EIR to avoid
referencing gasoline loading, were included as the 'Actual' and anticipated wharf
emissions as reported in the BAAQMD Engineering Evaluation42 as follows:
Pollutant Existing Wharf . Modified Refinery
ton/ ear ton/ ear
Sulfur Oxides 325 198,
Particulate 22 19
Nitrogen Oxides 115 116
Hydrocarbon 244 391
[note: similar emissions are included in the 1979 EIR, but are listed as on an hourly
basis.]
• The 1984 modification establishing the "cap" added tankage emissions to the
baseline 43 even though the same tank abatement emissions were used as offsets in
the '80 permit44. (Tankage emissions as other fugitive emissions are not counted in
the operation of the emissions cap.)
"d. The hydrocarbohn baseline profile has been increased by 2300/b/day due
to abatement on tankage (tankage is not included under the cap)."
• An October 9, 1981 BAAQMD internal memo from Steve Hill to Milton Feldstein, via
Peter Hess (attached) discloses:
1. that loading San Joaquin Valley crude oil was a new activity proposed in
1981 and that the District allowed Shell to commence loading crude oil in
violation of their own Regulation 2-1-40445 which required permit review for
new or modified uses; and
41 Dated 11/30/1984 by Milton Feldstein, APCO
42 TABLE 1: REFINERY EMISSION SUMMARY (EXISTING VS. MODIFIED), page 11, 3/19/80
SHELL OIL COMPANY ENGINEERING EVALUATION APPLICATION#26786 attached
43 Unnumbered page 2, BAAQMD, Shell WOR Permit Conditions, November 5, 1984
44 Unnumbered page 4, IV. Offsets, SHELL OIL COMPANY ENGINEERING EVALUATION
APPLICATION#26786, 3/19/80 attached
45 Regulation 2-1-404 was weakened in current BAAQMD regulations. attachment# 16
14
• •
2. The 1.4 gasoline loading factor was politically set and the District knew it
should have been 2.4 lbs (per 1000 gallons loaded) based on the existing
AP-42.
Emissions are based on those included in Shell's application and the
number of shipping trips appear to have been created to match.
• The 1984 BAAQMD permit modification to the 1980 permit includes 16 pages of
reconstructed daily baseline emission profiles for NOx emissions, hydrocarbon
emissions, SOx emissions and particulate47 (only the hydrocarbon record is
attached). 1977 Shipping statistics, recorded by the SF Marine Exchange (attached)
report dates and names of ships that visited Shell's wharf. None of the days that
ships visited Shell's wharf register a hydrocarbon increase of 7823 pounds, the
hydrocarbon release reported in Steve Hill's calculation for each of the forty ships
reported to have been loaded with gasoline at Shell's wharf in 1977.
THREE SHELUBAAQMD EMISSION REPORTING AVOIDANCE:
I. No benzene emissions were reported from Shell's wharf(as required by law),
even though the BAAQMD Marine Rule Workbook estimated Shell's wharf
benzene releases as 7.84 tons/year48 :
1. The 1989 BAAQMD Marine Rule Report states that Shell's marine loading
organic emissions totaled 415.7 tons/year in 1986 and 522.6 tons/year in
198749, and uncontrolled benzene emission from Shell's marine loading
averaged 7.84 tons/yearSO attached
2. Shell/BAAQMD did not report wharf benzene emissions to the EPA s
required by law. A copy of Shell's 1987-91 EPA benzene record is attached:
EPA TOXIC RELEASE INVENTORY SYSTEM, Year-To-Year.
Release/Transfer Comparison Report, Chemical : Benzene, 1987, 1988,
1989, 1990 and 1991 attached
46 Tables 3 and 4, Calculated Hydrocarbon Emissions From Loadinq attachment# 18
47 Shell WOR Permit Conditions November 5, 1984 attachment#22
48 Page 11, MARINE VESSEL LOADING TERMINALS RULE STAFF REPORT, January 3,
1989 attachment# 1
49 page 7, MARINE VESSEL LOADING TERMINALS RULE STAFF REPORT, 1/3/1989
attachment# 1
50 page 11
15
• i, YO
3. The BAAQMD did not record Shell's benzene emissions in the AIR TOXICS
EMISSION INVENTORY FOR THE SAN FRANCISCO BAY AREA, STATUS
REPORT, MARCH 1, 1989. The only benzene releases attributed by Shell
include 6800 lbs/yr from the refinery and 960 lbs/yr from product distribution.
attached
4. A 1992 benzene outfall study by J. Phyllis Fox, Ph.D.'s determined that the
wharf loading benzene emissions outfall was directed to an area on the
other side of the refinery, by Las Juntas elementary school. Dr. Fox's study
only addressed crude loading. (I was, not aware that gasoline loading was
significant at that time.) This report dated May 9, 1992 and stamped
"DRAFT"is attached.
2. The BAAQMD required all marine loading activity with emissions over two ,
pounds per 1000/gallons loaded install vapor recovery equipment. Shell's
operating permit, the 1984 modification, undervalued all loading emissions as less
than 2 lbs per 1000 gallons. Shell installed a 260,000 BTU/HR incinerator likely in
anticipation of loading more gasoline for transfer to Los Angeles.
3. Shell hydrocarbon baseline included 244 tons/year of wharf hydrocarbon
emissions. The 1980 Engineering Evaluation forecast wharf hydrocarbon
emissions would reach 391 tons/year after modification. In 1992 Shell installed a
marine vapor incinerator and reduced their hydrocarbon account by only 226
tons. Apparently the 325 tons/year of sulfur oxides, 22 tons/year of particulate and
115 tons/year of nitrogen oxides wharf emission contributions to Shell's baseline
were not adjusted. Could these emissions be covering some of the 1000 additional
tons/year of Clean Fuels Project emissions?
• In 1992, more than ten years after marine loading started, a 260,000,000 BTU/HR
marine vapor thermal oxidizer began destroying wharf loading emissions. BAAQMD
permit51 conditions dictate that:
"5. Shell shall reduce the baseline VOC emissions under the Emission CAP, permit
#26786, for wharf activity for gasoline components, crude oil...by 95%, by weight"
• The BAAQMD continued the undervalued loading emissions established in the
1984 condition modifications:
"6. .:.tracking...wharf emissions..as specified in Permit#26786..."
• In 1993 the City of Martinez hired Gary Rubenstein of Sierra Research to determine
whether marine loading was properly permitted and to advise them whether the
thermal oxidizer would facilitate expanded marine loading. Mr. Rubenstein's report
claimed the wharf was properly permitted and that the thermal oxidizer would not
facilitate expanded marine loading. He stated that Shell's hydrocarbon emission
51 August 10, 1992 letter to Shell from John Swanson, Permit Services Chief to Mark Kosliki,
Shell. stating that the permit to operate is approved and Conditions#4288 are included.
16
O
baseline was reduced by 155 tons as of 1991 and that he had found an error and
"In a letter dated February 17, 1993, the BAAQMD corrected this initial error, and
the Shell baseline has now been reduced by 226 tons/year.i52 .
• Mr Rubenstein does not question why the emission baseline was established with
244 tons of hydrocarbons, offsets provided to expand the wharf hydrocarbon
account to 391 tons/year and then only reduced by 226 tons/year--even though
the BAAQMD Marine Rule staff report estimated Shell's wharf hydrocarbon
emissions as 415.7 tons/year in 1986 and 522.6 tons/year in 1987, before extensive
gasoline loading started.
• Mr. Rubenstein's report makes no mention of whether the other pollutants attributed
to the wharf and included in the emission baseline were reduced: 325 tons/year of
sulfur oxides, 22 tons/year of particulate or 115 tons/year of nitrogen oxides. If
these emissions continued in Shell's emission bank, are they being used to offset
the Clean Fuels Project?
52 Page 23, Review of Air Quality Issues Related to the Shell Oil Company Marine Vapor
Recovery Unit, prepared for: City of Martinez Community Development Department, 2/19/93,
Sierra Research, Inc. 1521 1 Street, Sacramento Attachment#26
17
A
PVUVU'0&0 yNUOUO
TRPS 11 '95 �t5 44PM U EPR F"'E t7 G 1 44-1073
Develop JuneP�*,,
Agency Washington DG 20460 Externa!Review Draft
EPA Esfimating Review
Exposure to graft
Dioxine-Like (Do No.t
CompoundsCite or
Quote)
Volume ll :
Properties, Sources ,
Occurrence and
_.. .. .. .Background Exposures
/FORM 88(7.80)'
/,/yTRANSMITTAL #of pages A.
"!Y`Kf!' Prom
D®Pt./Agency Phone#
F Fax�
NSN 754`04111-319-7368 5059-101 GENERAL SERVICES ROMINIS fRA71ON
_..._ _,. —.._.. Natio
This document is a preliminary draft, It has not been formally
released by EPA and should not at this stage be construed to
represent Agency policy. It is being circulated for comment on its
technical accuracy and policy implications.
4µs REEVED
.IAN
CONfRADCOSTA CO.I'
JAH 11 '95 05:48PM LPS EPA RE 9 (DRA 415 744-1f o MEN --'
DRAFT--DO NOT QUOTE OR CITE
Tashiro, C.; Clement, R.E.; Stocks, S.J.; Radke, L.; Cofer, W.R.; Ward, P, 1990.
Preliminary report: dioxins and furans in prescribed burns. Chemosphere 20:11533-
1536.
0:1533-1536.
Thoma, H.; Hutzinger, 0. (1989) Content and formation of toxic products in flame.
retardants. Presented at: Workshop on Brominated Aromatic Flame Retardants.
1
Slokloster, Sweden; October 24-26, 1989,
Thompson, T.S.; Clement, R.E.; Thornton, N.; Luty, J. (1990) Formation and emission of
PCDDs/PCDFs in the petroleum refining industry. Chemosphere 2000-
;, 12):1525-1532,
Tong, H.G.; Monson, S.J.; Gross, M.L.; Bopp, R.F., Simpson, H.J.; Deck, B.L.; Moser,
F.C. (1990) Analysis of dated sediment samples from the Newark Bay area for
selected PCDD/CDFs. Chemosphere 20(10-12):1497.1502.
Tosine, H.; Clement, R.; Osvacic, V.; Osborne, J.; Wong, C. (1983). Levels of chlorinated
organics in a municipal incinerator. Presented before the Division of Environmental
Chemistry, American Chemical Society 186th National Meeting, September, 1 ,
s. 1983.
Travis, C.C.; Hattemer-Frey, H.A. (1991) Human exposure to dioxin. Science of the
Total Environment 104:97-127.
.a
Tysklind, M.; S6derstr6m; Rappe, C.; Hagerstedt, L-E.; Burstrom, E. (1989) PCDD and
PCDF emissions from scrap metal melting processes at a steel mill. Chemosphere
19(1-6):705-710.
i° U.S. Department of Commerce (1990a) 1987 Census of manufactures. Smelting and
a; refining of nonferrous metals and alloys. Washington, DC: Bureau of the Census.
r' Report No. 33C-18.
U.S. Department of Commerce (1990b) 1987 Census of transportation, Truck inventory
and use survey. Washington, DC: Bureau of the Census. Report No. TC87-T-52.
t�
-U.S. Department of Commerce (1990c) 1987 Census of manufactures. Industrial
inorganic chemicals. Washington, DC: Bureau of the Census. Report No. MC87-1-
28A.
ty U.S. Department of Commerce (1992) Statistical abstract of the United States, 1992.
1 12th ed.
U.S. Environmental Protection Agency; Environment Canada. (199 1) The environmental
characterization of RDF combustion technology. Mid-Connecticut facility,
Y, Hartford,CT. Test program and results, volume II., June 1991 .
3-189 6194
05:47PM US EPA REG 9 CERA 41
c ' DRAFT--DO NOT QUOTE OR CITE
ap
Battelle (1992b) Determination of polybrominated dibenzo-p-dioxins and polybrominated
dibenzofurans by HRGC/MRMs in octabromodiphenyloxide (sponsored by Great
Lakes Chemial Corporation). f=inal Report.
V?, Battelle (1993) Determination of polybrominated dibenzo-p-dioxins and polybrominated
dibenzofurans by high resolution gas chromatography/medium/high resolution mass
spectrometry in octabromodiphenyloxide (sponsored by Ameribrom, Inc.).
Amended Final Report.
Beard, A.; Krishnat, P.N.; Karasek, F.W. (1993) Formation of polychlorinated
dibenzofurans by chlorination and de novo reactions with FeCI3 in petroleum refining
processes. Environ. Sci, Technol. 27(8):1505-1511.
Berenyi, E.R.; Gould, R.N.0993) Municipal waste combustion in 1993. Waste Age
24:51-56.
i, Berenyi, E.B. (1993) A decade of municipal waste combustion in the United States:
prospects and problems. In. Municipal waste combustion, proceedings of an
international specialty conference of the Air and Waste Management Association.
Williamsburg, Va; March 1993. pp. 51-66.
is Berry, R.M.; Lutke, C.E.; Voss, R.H. (1993) Ubiquitous nature of dioxins: a comparison
of the dioxins content of common everyday materials with that of pulps and papers.
% { Environ. Sci. Technol. 27(8):1164-1168.
Bingham, A.G.; Edmunds, C.J.; Graham, 8.W.; .Tones, M.T. (1989) Determination of
PCDDs and PCOFs in car exhaust. Chemosphere 19(1-6):669-673. '
Boschi, G.; Cocheo, V.; Giannandrea, G.; Magagni, A. (19.92) Hospital and municipal
solid waste incinerators: Correlation between PVC present in waste feed and
emitted organic micropoilutants. Presented at: Dioxin '92, 12th international
Symposium on Chlorinated Dioxins and Relaxed Compounds; Tampere, Finland;
August 1992.
Branscome, M., at al. 1984. Evaluation of waste combustion in a dry-process cement kiln
at Lone Star industries, Oglesby, Illinois. EPA Contract No, 69-02-3149.,
December 1984,
Branscome, M, at al. 1985. Evaluation of waste combustion in a wet-process cement kiln
at General Portland, Inc., Paulding, OH. EPA Contract No 68-02-3149.
February 1985.
f
3-1746/94
JA�d 12 '95 a5:47PM U8 EPA PEG 9 op j y�
- r
tA
5 �
DRAFT--D4 NOT QUOTE OR CITE
Liebl, K.; Birchen, M.; Ott, W., Fricke,
W. (1993) Polychlorinated dibenzo-p-dioxins and
dibenzofurans in ambient air; concentration and deposition measurements in
Hessen, Germany. Presented at: Dioxin '93, 13th International Symposium on
Chlorinated Dioxins and Related Compounds; Vienna, Austria; September 1993,
Ligon, W.V.; Dorn, S.B.; May, R.J.; Allison, M.J, (1989) Chlorodibenzofuran and
chlorodibenzo-p-dioxin levels in Chilean mummies dated to about 2800 years before
the present. Environ, Sci, Technol. 23:1286-1290.
Y, Luijk, R.; Govers, H,A,; Nellssen, L. (1992) Formation of polybrominated dibenzofurans
during extrusion of high impact polystyrene/decabromodiphanyl ether/antimony (111)
oxide. Environ. Sc). Tachnol. 26(11):2191-2198.
4 Lustenhouwer, J.A.; 011e, K; Hutzinger, O. (1980) Chlorinated dibenzo-p-dioxins and
related compounds in incinerator effluents. A review of measurements and
} mechanisms of formation. Chemosphere 9:501-522.
1 Lykins, B.W.; Clark, R.; Cleverly, D.H,. (1987) Polychlorinated dioxin and furan discharge
i
during carbon.. reactivation. Journal of Environmental Engineering 114(2): 330-316.
l ,
McCormack, J.E. (1990) ARB evaluation test conducted on a hospital waste incinerator at
Los Angeles County, USC Medical Center, Los Angeles, CA. California Air
Resources Board, Sacramento, CA. January 1990.
Mahle, N.H.; Whitting, L.F. (1980) The formation of chlorodibenzo-p-dioxins by air
1 oxidation and chlorination of bituminous coal. Chemosphere 9:693-699,
Maniff, K,; Lewis, M. (1988) MISA monitoring discovers dioxins and furans in wastewater
stream of petroleum refinery. Ministry of the Environment Communique,
December 5, 1988.
Marklund, S. (1990) Dioxin emissions and environmental emissions. Ph.D. thesis,
University of Umea, Sweden.
Marklund, S.; Kjeller, L.O.; Hasson, M.; Tyskiund, M.; Rappe, C.; Ryon, C.; Collazo, H.;
Dougherty, R. (1986) Determination of PCODs and PCDFs in incineration samples
and pyroiytic products. In; Rappe, C.; Choudhary, G.; Kerth, L.H., ads. Chlorinated
a dioxins and dibenzofurans in perspective. Lewis Publishers Inc., Michigan. pp.
79-94.
Marklund, S.; Rappe, C.; Tysklind, M.; Egeback, K.E. (1987) Identification of
polychlorinated dibenzofurans and dioxins in exhausts from cars run on leaded
1 gasoine. Chemosphere 16(1):29-36.
I j
3-182 619
JAhJ 21 '95 05:46 M US EPA REG 9 ORA 41 74A
t.
+'11
.a�
1 j DRAFT--DO NOT QUOTE OR CITE
maximum,concentration of 128 ppb Waniff and Lewis, 1988). The concentration of
CDD/CDFs in the final combined refinery plant effluent was below the detection limits.
!1" insufficient data are available to evaluate CDD/CDF releases from these sources in
the United States, However, Beard et al. (1993) conducted a series of benchtop
experiments to investigate the mechanisms) of CDD/CDF formation in the catalytic
reforming process. A possible pathway for the formation of CDFs was found, but the
results could not explain the formation of CDDs. Analyses of the flue gas from burning
coked catalysts revealed the presence of unchlorinated dibenzofuran (DBF) produced in
quantities of up to 22.0 ng/g of catalyst. Chlorination. experiments indicated that
i dibenzofuran and possibly biphenyl and similar hydrocarbons act as CDF precursors and
can become chlorinated in the catalyst regeneration process. Corrosion products on the
steel piping of the process plant seem to be the most likely chlorinating agent.
Furthermore, CDFs can form by de novo synthesis from chlorinated hydrocarbons like
trichloroethylene, methylene chloride, and carbon tetrachloride in the presence of FeCl3
d! and HC! or C12.
�r
p 3.4.6. Additional Chemical Manufacturing and Processing Sources
Rappe et al. (1989) reported the formation of CDFs (tetra- through octa-chlorinated
Y '
CDFs) when tap water and double-distilled water were chlorinated using chlorine gas. The
�} GDF levels found in the single samples of tap water and double-distilled water were 35 and
f'. 7 pg TEO/L, respectively. The water samples were chlorinated at a dosage rate of.340 mg
of chlorine per liter of water which is considerably higher (by a factor of one to two orders
of magnitude) than the range of dosage rates typically used to disinfect drinking water.
Rappe et al. (1989) hypothesized that the CDFs or their precursors are present in chlorine
gas. it should be noted, however, that although few surveys of finished drinking water for
CDD/CDF levels have been conducted, the few that have been published only rarely report
the presence of any CDD/CDF even at low pg/L detection limits and in those cases the
CDD/CDFs were also present in the untreated water. (See Section 4.3.)
1
i
3-62 6/94
JAN 1 '95 055:44PM US EPA REG 9 ORA 415 744-1073 P.2.'R-
DRAFT-00 NOT QUOTE OR CITE
conversation between L. Phillips, Versar, Inc., and T. Fielding, U.S. EPA, Office of Water,
February 1993). Although the use of graphite electrodes has been eliminated, the
potential for CDD/CDF releases from dump sites containing contaminated sludges may still
exist (Svensson et al., 1992; Rappe, 1992a).
3.4.6. Petroleum Refining Catalyst Regeneration
Catalyst regeneration in the petroleum refinery reforming process has been
identified as a source of CE)Ds and CDFs based on testing conducted in Canada
(Thompson et al.,. 1990), According to Thompson et al. (1990), "catalytic reforming is a
refinery process which is used to produce high octane gasoline. The reforming pr-ocess
occurs at high temperature and pressure and requires the use of a catalyst. During the
catalytic process, a complex mixture of aromatic compounds known as coke is formed and
deposited onto the catalyst. As coke deposits onto the catalyst, its activity is decreased.
The high cost of the catalyst necessitates its regeneration. Catalyst regeneration is
achieved by removing the coke deposits via burning and activating the catalyst using
chlorinated compounds. Burning of the coke produce:9 flue gases which contain CODs and
CDFs along with other combustion products.' Thompson et al. (1990) reported total CDD
and CDF concentrations of 8.9 ng/m3 and 210 ng/m3, respectively, in stack gas samples
from petroleum refinery reforming operations (Table 3-19), It was also found that the CDD
and CDF congener distribution patterns observed were similar to those found in municipal,
waste incinerator ash and stack samples. Because flue gases may be scrubbed with
water, internal effluents may also be contaminated with CDD/CDFs. Thompson et al.
(1990) observed CDDs and CDFs in the internal wash water from a scrubber of a
periodic/cyclic regenerator (Table 3-20).
The Canadian Ministry of the Environment detected concentrations of CODs in an
internal wastestream of spent caustic in a petroleum refinery that ranged from 1.8 to 22.2
ppb, and CDFs ranging from 4.4 to 27.6 ppb. The highest concentration of 2,3,7,8-TCDD
was 0.0054 ppb (Maniff and Lewis, 1988). CODs were also observed in the refinery's
biological sludge at a maximum concentration of 74.5 ppb, and CDFs were observed at a
3-59 6194
�. yo
TAN 11 195 05:45PM US EPA REG 'D CERA 41t , UT
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Table 3-19. CDDs(CDFs in Petroleum Ref,thout Scrubber ack Gas from
a Continuous Regenerator W
:
6'
`b
:... ... .... .. .. 46 01)
1.6 (7)
TCD 120 (10)
3.4 (g)
PeCD (4E 31 (9)
1 ,9
HXCD 12 (4)
1 .2 (2)
HpCD 0.8 1 .7
OCD 8.9 210
TOTAL r4
Numbers in brackets indicate
a Values represent average doncen
trations for three tests. `+y
number of isomers detected.
Source: Thompson at al. (1990).
6194
JA" 11 ''�S C15:45PM US EPA RE6 9 ORA 415 -44-1 73
P.4/8
DRAFT--DO NOT QUOTE OR CITE
Table 3-20. CDDs/CDFs in the Scrubber Wash Water from a Petroleum
Refinery Periodic/Cyclic Regenerator
'Cohcantrati.�r� Rang@;(RGa} No. of Congeners:
Hi
Group=;: Qccur$nces
TCDD 7 44' 110 7 11
PeCDD 7 15 90 2 13
HxCDD 6 NDO 7) 160 0 6
HpCDD 1 ND(20) 64 0 2
OCDD 1 ND(22) 56 0 1
TCDF 7 150 660 14 14
PeCDF 7 40 330 5 10
HxCDF 7 20 260 3 12
HpCDF 7 10 160 1 4
ACDF 7 23 93 1 1
a Number of positive occurences based on seven samples analyzed.
b Numbers in parentheses are detection limits.
Source: Thompson at al. (1690).
3.61 6/94
PO Box 1086 11RECEIVED
Martinez 94553
r, ,� 3 �
January 3, 1995
To: Dan Lundgren, Attorney General
Gary Yancey, District Attorney
1995 Chair, Contra Costa County Board of Supervisors
Clyde Parkhurst, Foreman, Contra Costa County Grand Jury
Felicia Marcus, Region 9 Administrator, U.S. Environmental Protection Agency
James M. Strock, Secretary, California Environmental Protection Agency
James,D. Boyd, Executive Officer, Air Resources Board
Since 1982 1 have several times informed your offices of Shell's illegal marine loading
operation in Martinez. This terminal operated as the single worst toxic emission source
in the Bay Area between 1982 and 1992. It emitted more than seven tons of benzene
annually, with outfall centered around the Las Juntas Elementary School in Martinez.
Thus far you have chosen to believe the Air District, who failed to disclose to the public
that it was Shell's intent to load 10.9 million barrels of gasoline per year at its Martinez
wharf facility. This activity was not mentioned in the 1979 EIR, but was included in
Shell's BAAQMD application upon which the 1979 EIR was based. That EIR
addressed major wharf modifications that would be used to facilitate the import of
Alaskan crude oil. Although the equipment was installed, Alaskan crude was never
imported. Instead the facilities were used to export gasoline and crude oil, hazardous
activities not addressed in the EIR.
I'm now informing you that Shell, aided by the BAAQMD, has proposed and received
permits for a modification project that includes a residual coking complex, ostensibly to
replace gasoline volume lost to their 1993 Clean Fuels Proiect. Based on clues
peppered within the 1993 EIR, Shell anticipates using this project to double gasoline
production. Attached documentation references expansion indicators.
Shell's 1979 Martinez Manufacturing Complex Modernization was also presented as a
modification project. It proposed to increase gasoline production by 11,000 barrels/day
and aviation fuel by 4,000 barrels/day without increasing the overall level of production.
Although Shell's recorded production capacity was only 108,000 barrels/day, the 1979
EIR claimed existing production as 128,000 barrels/day. Even though the Air District
permit limits production to 128,000 barrels, production increased to 150,000 barrel/day
by 1992. The risk and environmental consequences of this 42,000 barrel expansion
were never addressed.
Contra Costa County residents have well documented lung cancer, breast cancer and
respiratory problems. it's time to stop refineries from using our air to dispose of their
carcinogenic wastes.
kv
\h 1• L4 C)
- January 3, 1994
In my opinion, Shell's failure to disclose its true intent amounts to fraud and the Air
District officials who abuse the authority of their office are similarly guilty.
I encourage your investigation to confirm the above allegations. Subsequent firm
action will require Shell to operate lawfully, reemphasize the public's right to be
informed and return confidence that its regulators represent the public and not the
business they are assigned to oversee.
What happens next is up to you.
erely,
Diana L. Patrick
enc: Documentation
Referenced material attached
cc: Senator Barbara Boxer
Congressman George Miller
State Senator Dan Boatwright
Assemblyman Bob Campbell
Mike Menesini, .Mayor, Martinez City Council
Ret. Supervisor Nancy Fanden
Citizens For A Better Environment
Citizens For a Safe Environment
area newspapers
ATTACHMENTS:
BENZENE - wharf benzene emission documentation and reporting agencies reports
that should but do not include wharf benzene emissions:
1. BAAQMD MARINE VESSELS LOADING TERMINALS RULE STAFF REPORT
1/3/89 - Cover page, page 7 marine loading emissions and page 11 - Benzene
Emissions- Bay Area (Tons/Year) Lists Shell's wharf benzene as 7.84 tonslyear
2. BAAQMD AIR TOXICS INVENTORY FOR THE SAN FRANCISCO BAY AREA
STATUS REPORT MARCH 1, 1989 - Cover pages and pages C-44 & C-45, lists
less benzene for the entire refinery than was emitted at Shell's wharf
3. USEPA TOXIC RELEASE INVENTORY SYSTEM, Year-to-year Benzene Report -
Page one lists less benzene from the entire refinery than was released from
Shell's wharf
4: 519/92 Report: Benzene Emissions From the Shell Wharf, by J. Phyllis Fox, Ph.D.
3 pages, reports benzene fallout is near elementary school (only addresses
crude, not gasoline loading)
Pages from the 1993 SHELL OIL COMPANY CLEAN FUELS PROJECT DEiR and
RESPONSE TO COMMENTS documents - reveal Shell's capability and impacts
from doubling gasoline production
5. Page 3-49 Delayed Coker Unit Description Lists imported coker feedstock
6. TABLE 8-16 (can't) Criteria Pollutant Emission Summary by Source 1993 -
Response to Comments
7. TABLE 11-4 Additional Quantities of Products or Hazardous Materials Following
Completion of Project
GASOLINE TANK# 12467 should have been considered in the `93 E/R
8. Leonard R. Clayton, retired BAAQMD Environmental Engineer, May 10, 1994
review of gasoline storage tank#12467-advised requiring an EIR
9. BAAQMD ADDENDUM TO EVALUATION REPORT, Request to extend permit for
Two Years - Requires BACT but doesn't update undervalued emissions
10. BAAQMD Office Memo, dated August 2, 1991 from Hon-Ting Man to Steve Hill,
Subject: Risk Screen (tank# 12467) "Risk Assessment Analysis: Request
For Information form has not been filled in because the proposed tank
does not have a stack nor locate within a building." - no
consideration given to the adjacent street or hillside homes.
11. STORAGE TANKS (20,000 GALLONS OR GREATER) - Cover Page and
Risk Screen at the back- eliminates all tanks from risk screening
l,qD
12. 1991 BAAQMD Risk Screening Analysis form:
Risk Screening Analysis dated October 23, 1991 Would have required all
gas tanks to complete risk screening.
13. AIR RESOURCES BOARD, March 22, 1944, Executive Order G-70-1261
Allows Shell to expand bulk gasoline loading by 20% Should have been
addressed in 1993 EIR
1979 SHELL OIL COMPANY MARTINEZ MANUFACTURING COMPLEX DEIR&
APPENDICIES
14. Pages 12 & 13 Project Goals No mention of loading gasoline or diesel or
expanding production by 45%
15. STATE LANDS COMMISSION Barrel tax data Aug, Sept. & Oct. 1979 Shows
Shell didn't load gasoline until 1980 and didn't load crude oil,
28. U.S. Army Corps. of Engineers, Waterborne Commerce Division, 1977 Carquinez
Strait freight traffic total petroleum movement for five refinery wharves. Shell
claims to have loaded more gasoline than loaded in total at all five wharves.
BAAQMD SHELL PERMITS and two sheets from Shell's 1979 Application, Memos
worksheets, and Regulation 2-1-404 that has been dropped:
16. Regulation 2-1-404 (as of January 7, 1987)
17. TABLE 2 SUMMARY OF ESTIMATED MARTINEZ WHARF EMISSIONS
18. TABLES 3 and 4 CALCULATED HYDROCARBON EMISSIONS FROM
LOADING
19. 10/9/81 BAAQMD Internal Memo from Steve Hill to Milton Feldstein via Peter
Hess
20. 3/21/83 Loading Hydrocarbon Emission likely from Steve Hill hand written
27. 3/19/80 SHELL OIL COMPANY ENGINEERING EVALUATION APPLICATION
#26786
21. 5/8/80 AUTHORITY TO CONSTRUCT
22. 11/5/84 SHELL WOR PERMIT CONDITIONS (With notice and 11/30 letter
from P. Hess to J. Moorad)
other:
23. 3/20178 OIL AND GAS JOURNAL page 116 1977 Crude Oil Processing
Statistics
24. 12121192 page 52 & 85
25. 4/17179 Shell request to BAAQMD to covert jet fuel storage tank 1046 to
gasoline
26. 2/19/93 Review of Air Quality Issues Related to the Shell Oil Company Marine
Vapor Recovery Unit Gary Rubenstein, Sierra Research claims Shell's wharf
emission banking is just fine!
olpit-
5
BAYAREA AIR QUALITY MANAGEMENT DISTRICT
939 Ellis Street
San Francisco, CA 94109
MARINE VESSEL LOADING TERMINALS RULE
STAFF REPORT
a
S
BY
Jim Karas, Air Quality Engineering Manager
Bob Nishimura, Senior Air Quality Engineer
Donald Van Buren, Air Quality Engineer/l
Revised January 3, 1989
�L
�► ! /ria
Table I
1986
BAYAREA MARINE VESSEL LOADING EMISSION ESTIMATES
Gasoline And Crude Oil Loading Organic Emissions, Tons/Year
Company Barge Tanker TOtal
Shell 164.0 251.7 415.7
Tosco 54.8 , 195.6 250.4
Chevron 48.2 147.0 195.2
Landsea Terminal 29.9 152.3 182.2
Unocal 0 170.3 170.3
Texaco 160.8 2.1 162.9
Exxon 37.1 44.0 81.1
Wickland 0 43.1 43.1**
Pacific Refining 19.3 20.6 39.9
Time Oil 27.8 11.2 39.0
Arco 10.7 0 az
Subtotal 1591
* 318*
District Total 1909
****************************
Table 2
1987
SAYARE4 MARINE VESSEL LOADING EMISSION ESTIMATES
Gasoline And Crude Oil Loading Organic Emissions, Tons/Year
Company Barge Tanker Total
Shell 221.2 301.2 522.6
Tosco 60.4 285.2 345.6***
Chevron . 60.9 154.3 215.2
Unocal 0 178.0 178.0
Texaco 95.6 64.4 160.0
Landsea Terminal 100.4 40.3 140.7
Eason 10.5 84.2 94.7
Wickland 0 45.5 45.5**
Pacific Refining 31.9 27.3 59.2
Time Oil 25.2 17.0 42.2
Arco 8.6 0
Subtotal 1812
* 362*
District Total 2174
*Emission estimates for switch loading.
**The above tables do not take into account any gas freeing or tank cleaning prior
to loading.
***Tosco started to control a portion of these emissions after June 1987. The above
estimates are based on all loadings being uncontrolled
7
FIGURE 2
Benzene Emissions -Say Area (Tons/Year)
Marine Loading Terminals
CompnY Uncontro Contro11
Shell 7.84 0.4
Tosco 5.18 0.26
Chevron 3.23 0.16
Unocal 1.42 0.07
Texaco 2.67 0.13
Landseal Terminal 2.40 0.12
Exxon 2.11 0.11
Wickland 0.65 0.03
Pacific Refining 0.89 0.04
Time Oil 0.63 0.03
Arco Qij 0.007
Total 27.1 1.4
�P-e)lVr v6s�zs
Tom)/VALS /Z
3 �g
AIR TOXICS EMISSION INVENTORY
FOR THE SAN FRANCISCO BAY AREA '
STATUS REPORT
MARCH 1, 1989
PREPARED BY:
BAY AREA AIR QUALITY MANAGEMENT DISTRICT
TOXICS EVALUATION SECTION
STEVE HILI.
JAMES TOMICH
HARI DOSS
RANDY FRA23ER
PATRICIA HOLMES
TIMOTHY SMITH
EUGENE WILLNER
JAY WITHERSPOON
r70hTQA COSTA ?LINTY
EsttTated
.missions
Comoary Name Pollutant ( lbs/vr)
------ ---------
RMC Lonestar (P4 928)
Senzene <1
Etnvlere Jibromile <1
Ethylene dichloride <1
Radiant Coll)- (Ps 9Q)
Fenzene <1
Reddina Petroleum, Inc (Ps 945)
?enzene 95
Fthylene dibromirle <1
Ethvlene dichloride 2
Ree4wooA Painttn:T (PN 3173)
Trichloroethane (i , i , i-) 98
Xvlene 140
Reynol-ls Iniustries Systers, inc (Ps 2403)
Xvlere 1A
Safe Cleenerss (Ps 2615)
Percnloroethylene (PFRC) 1400
Safeway Stores Inc, Fakery plant (PA 93)
Benzene <1
Formaldehyde i
SaKai Frotners Qose Co, Inc (PS 1563)
Benzene <1
Formaldenvde 2
San Ramon Body Shoo US 1181)
Xylene 72
Sciarrori Auto 'ony (Ps 367Q)
Xvlene 21
Scott Lanro Comoany (Pt 2614)
aenzene <1
Scotto's Auto Aody (Pt 3800)
Xylene 120
Shell Oil Comoanv (PA 11)
Arsenic (all) <1
Benzene 6800
Nervllium (all) <1
Putadiene ( 1 ,3-) 1300
Cadmium <1
Chromium (hexavalent) <1
Cresol 270
Ethylene dibromide 8
Ethylene dichloride 210
Formaldehyde 350
/ C-44 BAAOMO Toxic inventory 3/1/89
CONTRA cOSTVCOUr4T7 /, 0
�stl^'ate +
siors
COMngnV ^-ame ' pollutant w^�is
{islvr)
teal (all ) <t
"ancanese <1
Merc;zry (all) <1
Mickol 7
PAH'S <t
Xylene 9909
Shell (til rroauct Oistribvtion (P• 3b94)
Renzene 960
FthV] ene libromide <1
Ethylene dichloride 16
Sinnoce Suoolv corcoration (Ps 641 )
Benzene <1
Cellosolve 3t00
Cellosolve acetate �1n
Southern Pacific !'ioe Lines Fartnershir, 1, P (Pr "22)
Benzene 420
Fthvlene dibromiie <1
Fthvlene dicnloride 7
Sparklino Cleaners (Ps 1773)
Perchloroethylene (PFRC) 680
soarkiizinc Cleaners (Ps 750)
Perchloroethylene (PFRC) 490 ;
St Josepr Cleaners (Ps 2214)
perchloroethvlene (PERC) 1400
Stauffer Chemical Comoanv (Ps 20)
Benzene <1
Formaldehyde <1
PAF+'s 0
Sucirara nursery, Tnc (Ps 1552)
Benzene <1
Formaldehyde <1
Sunny Brite Cleaners (Ps 958)
Perchloroethylene (PERC) 350n
Sunshine Cleaners & Coin Laundry (Ps 2178)
Perchloroethylene (PERC) 610
Texaco r&M ,Inc (P# 78)
Benzene 2800
Ethylene dibromide 2
Fthvlene dichloride 47
Formaldehyde <1
The Ouriron Co (Ps 3488)
Styrene 11
311/99 BAAomn Toxic Inventory C-45
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May 9, 1992 /t ' FTD. RA
Diana Patrick
1310 Marina Vista
Martinez, CA 94553
RE: BENZENE EMISSIONS FROM THE SHELL WHARF
Dear Ms. Patrick:
As you requested, I have evaluated the etr.issions of benzene
from the loading of San Joaquin Valley crude at the Shell Wharf.
This crude can contain from 23 to 400 parts per million
("ppm") of benzene in the liquid',2 and 156 ppm in the vapor at
71 F. For a typical tanker load of 200, 000 barrels, about 39
pounds of benzene would be released to the atmosphere.3 Thi - it
quite low compared to measured benzene emissions from the
of Alaskan crude, which range from 112 to 416 pounds per P00, 000
barrels.4 The low benzene emission value is due in part to the
- - low temperature (71 F) that was used in the headspace analysis. �
Crude temperatures during loading are typically closer to 100 F.
A loading temperature of 100 F could increase the benzene
emissions from San Joaquin Valley crude by about a factor of tjo
to 78 pounds per 200, 000 barrel loads and would double the
health risk.
A. D. Little, Inc. , Physica and Chemical Characterization
of San Joaquin Valley Crude Oiii a Study Element of the Pilot
and Reconnaissan a Study for the Shell Oil Spill-Assessment and
Recovery Monitoring Environmental Effects Program, Final Report
to ENTRIX, Inc. , April 1989, Table 30.
2 Bay Area Air Quality Management District ("BAAQMD") Report
of Laboratory Analysis, KLM Kern Los Medanos Crude Stored at 71
F, December 12, 1990.
3 Benzene emissions = (200, 000 bb1s) (42 gal/bbl) (cf/7 . 48
gal),(156 Cf/106 cf) (mole/379 cf) (84 lb/mole)
4 Alyeska Pipeline Service Co. , Report on Valdez Dnker
Loading vapor Emission Testinj and Evaluation, October 22, 1990,
Table 6.
s Alyeska Pipeline Service Company, October 22, 1990, F 4ure
4.
Benzene Emissions Shell Wharf
May 9, 1992
Page 2
The maximum annual average benzene concentration resulting
from the loading of 200, 000 barrels per day of crude at the Shell
Wharf was estimated using the health risk assessment prepared
under the Air Toxic Hot Spots Act (AS 2588)6 and is 0. 14
micrograms of benzene per cubic meter of air ("ug/m") .T The
location where this maximum annual average concentration would be
experienced is shown in Figure' l. The cancer risk associated
this benzene concentration is 4 in one million or an individual
cancer risk of 4 x 10'6.9 The actual cancer risk could be up to
two times larger if the benzene emissions are underestimated due
to the low temperature used in the headspace analysis used to
calculate the benzene emission rate.
This cancer risk assumes an annual average crude loading
rate of 200, 000 barrels per day. The cancer risk can be adjusted
for another loading rate by multiplying the cancer risk by the
ratio of the new loading rate to the old loading rate (i.e. ,
new/of or new/200, 000 barrels) ,.
Sincerely,
D A F T
J. Phyllis Fox, Ph.D.
6 Radian Corp. , Air Toxic -"Hot Spots" - AS 2588 Health Risk
Assessment, March 28, 1991.
t Marine loading emissions are split between sources 20025
and 20028 [Radian 1991, Volume II, Table B-I] . The maximum
normalized annual average concentration for the sum of these two
sources is 0. 694 ug/m3 per g/sec and occurs at location 66
(x-579700, y-4207500) (id. , Volume II, Appendix C-21 . Assuming
200,000 barrels/day of crude are loaded, the benzene emission
rate is (39 lb/day) (454 g/ib)/(24hr/day) (60 min/hr) (60
sec/min)-0. 20 g/sec. The' ambient benzene concentration is (0. 694
ug/mj per g/sec) (0. 20 g/sec) - 0. 14 ug m3 .
e The cancer risk is (0. 14 ug/m3) (2.9 x 10'5)-4 . 1 x 10'6. The
cancer unit risk factor is taken from CAPCOA, Air Toxics
S12ots" -Program: Risk Assesrnrent Guidelines, January 1991, Table
I1I-6.
Benzone ' Emisstionsti ;hell wharf
May 9, 1992
Page 3
577000 `.ram57UM s7woo Y7e'Too 5000w
4 0,�`�►` ' \ ,e!/, " + t x 104 Total RISK Isopleth
Shell
1! +T `>�� .�': FFP .� 1. 'S � ,�.�i� � i)i .p R� ��'.•J.
4 �/� � �1 � - ai s r,r� r �—+ i MBI � � �•
4 3b
✓ 1` .4N
7 1
1207000-� ' �` T}" scot
0 1000 2000 • o ' + ' f:, ^� •C �d:.1V/ '�r• i ` � '
SCALE IN FEET
1. Location of Maximum Benzene Concentr, ,n From Loading
Crude at the Shell Wharf (At Center G.. ross) .
llqc)
Shell OU Clean Fuels Project t"' Draft BIR
3. Project Description
Page 3-49
12. Delayed Coker Unit
The u of the new Dela Coker Unit is to upgrade Vacuum Flasher
purpose Y� PBT
bottoms (pitch or equivalent) and recycled byproduct streams to produce coke
and lighter fuels,such as gasoline,jet fuel, and diesel. As can be seen in
��)t ? Figure 3-7, the new Delayed Coker Unit would become a cornerstone in the
U v processing of heavy, high-sulfur, petroleum compounds to higher value
products. This unit is in keeping with Shell's objective of upgrading heavy
fuels and thus maintaining coasting gasoline production levels while producing
j►� � � reformulated gasoline. A simplified flow diagram of this unit is given in Figure
3-19.
The Delayed Coker Unit would be the most prominent new facility in the
proposed project. The Delayed Coker Unit would have two significant
features —the coke drums with an associated drilling structure, and the coke
barn. The first feature would consist of six vertical drums in a single row
surrounded by a support structure approximately 120 feet tall with a combined
length o feet and width of 30 feet. Located on to of the drums would
i ng f 180 n p
be a structure to support hydraulic drilling equipment required for decoking
operations. The drilling equipment would be approuimateiy 130 feet tall,
making the combined height of the drums and drilling structure approximately
250 feet.
To the west of the Delayed Coker Unit would be the coke barn,which would
accumulate coke product for shipment. The coke barn_wauldjwthe largest
structure associated with the Clean Fuels __Project. The barn would be similar
CAWF[g ere 3.19. Delayed Coker Unit
PITCH (CRUDE BOTTOMS) FROM
EXISTING CRUDE UNIT PETROLEUM COKE
BOTTOMS FROM EXISTING NEW
CATACYTIC CRACKING UNIT DELAYED COKER
} UNIT LIGHTER FUEL INTERMEDIATES
RESIaU/ IRHM r
LUBE AND IMPORTED
PURP S
UPGRADE BOTTOMS STREAMS TO PRODUCE
PETROLEUM COKE AND INTERMEDIATES OF
LIGHTER FUELS SUCH AS GASOLINE, JET — -
FUEL AND DIESEL
(Site Plan Reference #4)
Responses to Comments
Letter 3
TABLE 8-16 (can't)
—, Criteria Pollutant Emission Summary by Sonrce
EMISSIONS (tons per pear)
SOURCE PMte ` VtJC': NO, CO Sflx
SUBTOTALS
Combustion Sources X133 1Z2{i
39 469: 4-49 464 .9
Fugitives 0.0 iii 0.0 0.0 0.0
3e4s
Process Units
M4 4;4:9 444.4 a" �6
Ancillary Facilities 3&4, I I= W4 tib
33.4 4443 88.3 43;4 44-4
TOTAL EMISSIONS ' + :illi $ 317:4 U1.0
6" 40" 49" 466,;
Source. BAAQMD, Mutt 1993.
92220 3-11
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7 VIRONM
ENTAL ENGI.*NiEER
Ma.7 10 , 19794
Beverly Dutra
Marvin Dutra
Diana Patrick-
My name is Leonard R. Clayton. I am a retiree Enz.`neer . I
was emplc,-ed with the 3a'v Area A.' : QLlal-' t,'.- Manazemen,,:
District for .35 .ears Llnr.il 19-93 . 1 dealt pr1.ma,-:-, ,-, with
petrOleUM -re.-'-nery and chem-- cal plant issues .
As �-ou requested , r. nave reviewed the gasoline szjrag? tank
7 proposem for Sheil Oil adjacent to Mar-' ra Vista. This
tank noses 14
Sig n.4cant env4ronmentai impacts tna-- have not
. .
been identif:oea. 1 have estimated routine
tine hydroc-irbca
emissions to the atmcsphere usii-, standarc EPA enlissi;n
estimating techniques as over 2-1 , 000 'Pounds per A
small leak of 1% of the product could resuiz in emlss:ons of
over 35 , 000 Younis in a matter of minutes.
7n addition, - be` 4e, e this tank poses significant fire and
explosion risks that must be addressed. A number of fire and
related hazards are posed if a simple leak finds an ignition
source . "Liquid pool fire" and fireballs can result from
Boiling Liquid Expanding Vapor Explosions ( BLE-EVE-si . 3L---":-s
are among the most feared events when sealed tanks are
exposed to fire. Although they are called explosions , -.i-ey
are not associated with strong blast waves. The;- involve the
violent rupture of a container and rapid vaporization of the
gasoline. A large rising fireball will form depending on the
amount of gasoline present . Although the fireball is
generally of short duration, the intense heat generated can
cause severe and even 2fatal burns to those exposed over a
considerable distance.
I used the Automated Resource for Chemical Hazard Incident
Evaluation computer program, (better known as "ARCHIE" ) to
estimate the potential area that would be affected should
this tank BLEVE. This is the most widely used program of its
kind. It is routinely used through out the U.S in training,
emergency planning, hazard analysis and reference. The
output attached, shows that a fire ball of about 40 seconds
duration and one mile in diameter could result. Fatalities
IUS Environmental Protection Agency, AP-42 , Supplement E,
JO/92 , Chapter 12
Handbook of Chemical Hazard Analysis Procedures, Federal
Emergency Management Agency, ( FEMA) , U.S . Department of
Transportation, ( DOT ) , U. S . Environmental Protection
Agency, ( EPA) , 1989 page 4-8
2
would be expected within a radius of abot.it 4 . 4 miles and
injuries within a radius of 6 . 7 miles .
Although tank fires and explosions are rare , It could be
inexcusable to faii to plan- for one or to fail to identify
safe separatwon distance between tan.!-:s and neignbors . A
number of measures to reduce risks must be eval:!ated -
Continuous mcnitorinz must be used to fine leaks before a
disaster occ!lrs -
Sheli has "at.4 a number of tank fires , in: close
calls in the recent past . A Shell tank on 4/*.1 /9-'
Mew its top, 'A-noc;'%-ed o:iz power to about 1,000 homes and
businesses and ianf::e(-4 on rail tracks disrupting rail traffic
for hours . 3 on 10/8/9 arior,"er tank literall-,- "r�c:kceted"
into the air, dente-i ario-her dank. blackened a :hra zan�-
7.
and lit up .the sky for mi-es . On 6;13/86 a piz.:?, tank
caug;it fire s-zetied fl..-ime ilUndreds of feet in to :.ie air and
ccuid be seen -F.s far awa�- as Sari Francisco . U"ri 26/86 a
gasoline tank s-pillefi_ 8 ,000 grallons of gasoline :,,%-er 7he
top. Ma4-4. It was next to
I Karina Vista where neighbors were
barbecuing. Children playing first discovered t.',.e le::tk, they
no: ' 04ed a ne- g"bor who notifi -d - police . The po-- , -,e were the
first irsr_ to notif-.- Shel-' , 40 people were evacuated. ` Or,
8/23/85 a 3 million gallon external ficatIng roc: _ rank
ignited when vapors escaping around the seals f-:1,nd an
ignition source at a heater belonging to a neiz-:)orin-.Y
asphalt plant, Genstar. -Bepicia residents descr-- oed it as
resembling a nuclear bomb- 0 On September 1982 a corrcced
pipe led to a violent explosion that was felt in 1."aiiej-o and
Lafayette. On July 22 , 198-1 a 300 foot fireball e%-.acuated
employees and rocked the neighborhood.
In February o" 1986 Shell barely averted a "real disaster"
when "fumes escaping from seals and valves in a ;asoiine
tank at a storage yard near San Francisco International
Airport ignited, exploding and sending flames hundreds of
feet into the air. Airport firefighters brought heavy-duty
foam equipment believing a plane had crashed. T"e entire
tank farm could have been lost. Shell 's Gene Munger was
quoted as saying "We were fortunate" . "We were blessed
Chief Ray Landi said if a tank that was scorched exploded
" . . it surely would have ignited 7 the other tanks. There would
have been a chain reaction. . . " One must not simply rely on
good luck to protect life and property.
The proposed additional storage gapacty will promote the
shipment of additional gasoline.
iA 20% increase in gasoline
throughput at the bulk plant at Marina Vista is equivalent
34/2/93 Contra Costa Times, By Kathleen Maclay
410/10/93 Contra Costa Times, By Andy Jokelson
56/30/86 Contra Costa Times
68/24/85 Contra Costa Times
79/12/86 San Jose Mercury News
8-
3/22/94 letter ARB to Shell increasing daily th7011'5`hPUt
/1V0
3
to over 30 additional truck loads a day. A single truck
accident can have severe consequences. For example, a Shell
tanker truck flipped over on 5/6/34 shutting down Highway
101 in both directions for hours. On 5/12/94 police and an
. incident response team was spraying water on a Shell leaking
rail car. A loading valve failed releasing isobutane ,
material that is typically blended in gasoline. in
explosions of :ail cars of this type, pieces0of these tanks.
have been known to travel up to 5 ,000 feet .
Leaks , spills , fires and explosions will inevitaol�- occur as
clearly documented by Shells past performance. These
possibilities must be carefully evaluated and options
selected that minimize the risks.
This tank noses significant risks that have not been
identified . an ETR must be prepared to iaent.ify and mitigate
each risk.
Please do not hesitate to call me, if you would like to
discuss this Further
Sincerely,
Leonard R.
1
98/7/94 Contra Costa Times
Handbook of Chemical Hazard Analysis Procedures, Federal
J� Emergency Management Agency, (FEMA) , U.S. Department of
V Transportation, ( DOT ) , U. S . Environmental Protection
ADDENDUM TO EVALUATION REPORT
SHELL OIL COMPANY
APPLICATION NUMBER 7015
Request to Extend A/C for Two Years
Introduction:
In their letter of August 18, 1993, Shell requested an extension of the Authority to
Construct for S-2013, External Floating Roof Tank. The A/C for this tank was issued
December 27, 1991. Because this permit application was received on 5/23/91 (prior to
the adoption of amended Reg. 2-2), this tank was not subject to the current NSR rule.
Per Reg. 2-1-407, an A/C may be extend for an additional two years, subject to meeting
the current BACT and offset requirements of Reg. 2-2-301 and 302. The above POC
emissions exceed the current trigger levels for BACT and offsets. Therefore, this
application must comply with current BACT and offset requirements before an extension
can be granted. Offsets were provided for the POC emissions identified below as part
of the subsequent permit application number 7562.
From the original evaluation report for this application, annual average POC emissions
from S-2013 will be:
6.9 lb/day
BACT:
The District has publicly noticed our Preliminary Decision to issue an A/C for Shell's
Clean Fuels Project (app. No. 8407). This project includes several storage tanks. The
BACT determination for the Clean Fuels Project (CFP) storage tanks includes vapor
recovery for three new tanks, and external floating roofs for the remaining 16 new and
modified tanks that will be subject to Reg. 8-5.
BACT for the CFP external floating roof tanks includes the following:
a. liquid-mounted primary seal;
b. zero-gap secondary seal;
C. no ungasketed roof penetrations;
d. no slotted guide poles;
e. every roof fitting shall be of the design which yields the minimum roof
fitting losses, per AP-42, Supplement E, Section 12.3.2, Table 12.3-11;
and
f. adjustable roof legs with vapor seal boots.
The above BACT requirements will be included in the permit conditions for S•2013.
• � • � 1,yo
OFFICE MEMORANDUM
August 2, 1991 '
TO: Steve Hill
FROM: Hon-Ting Man
SUBJECT: Risk Screen
Shell Oil Company
Permit Application Number 7015
Please provide the risk screen results for the following
source:
Source External Floating Roof Tank, Unleaded
Gasoline, 140 Thousand Barrels
Emissions: 0.36 lb/day of benzene (annual average)
Risk Assessment Analysis: Request For Information form has
not been filled in because the proposed tank does not have a
stack nor locate within a building. In stead, this memo is
�j attached with a drawn to scale map, which demonstrates the
locations of the proposed tank and the nearby tanks and
their dimensions. If more information is needed please call
me at 4712 .
�O
i► /, yo
STORAGE TANKS (20,000 GALLONS OR GREATER)
1. DESCRIPTION
This chapter covers the permitting of organic liquid storage tanks with a capacity
greater than or equal to 75 m3 (approximately 20,000 gallons).
2. APPLICATION CONTENTS
A. Data Forms
The following forms must be completed by the person submitting a permit
application (these forms are used by the District to characterize the type of
process, size,fiowrates, abatement devices,and exhaust stacks of the system):
Form P-10113: Application for Authority to Construct and Permit to Operate
Industrial Sources
Form P-201: Plant Data, if new facility
Form T: Organic Liquid Evaporation (Tankage, Loading and Handling)
Form A: Abatement Device (only needed if applicant chooses to control
emissions with abatement equipment other than a pressure-
vacuum valve or floating roof)
Form P: Emission Point (only used in conjunction with abatement equipment
having a defined emission point).
P-105, Samali Business Form, if applicable
Examples of completed forms are attached.
a. Additional Information/Forms
Narrative description of the operation.
Copies of Material Safety Data Sheets (MSDS) for each material stored.
Site plan and plot plan, with dimensions.
Concentration of all liquid components if the tank contains a mixture of
chemical compounds.(note that common petroleum products
such as gasoline or jet fuel need not be separated into their
multiple components.
Equipment specifications for any pressure-vacuum valves .or abatement
equipment.
Information on whether the punt is located within 1000 feet of a school.
"Risk Assessment Analysis: Request for Information" form if any toxic materials
are stored in the tank.
3. COMPLETENESS
The following information is needed to make this determination:
A. All Authority to Construct and;or Permit to Operate fees must be paid.
e. All data forms listed in section 2.A. must be fully completed by the applicant. In
addition, the other information requested in 2.B. must be submitted if
applicable.
1 r
(07,15)91) 21 1
7. Vapor Recovery Systems must have a recovery efficiency of at least
95% by weight. Storage tanks with vapor recovery must be gas tight
with properly cberating pressure-vacuum valves. The only two
acceptable vapor recovery methods are Carbon Adsorption and
Incineration.
B. Toxics
Storage tanks containing toxic materials must comply with the District's Risk
Management Procedure.
7. EMISSIONS
A. Emission Factors
Emission factors and equations for internal and external floating roof tanks are
based on AP-42 section 4.3 (4th ed., 9/85). The following equations should be
used to calculate the emissions from tanks with floating roofs.
1. Rim Seal Losses:
LR KSVnP*DMvKc
Where:
Liq = Rim Seal Loss (Ib/yr)
Kj = seal factor (lb-mole/(ft(mi/hr)nyr))
V - average wind speed at tank site (mi/hr)
n,= seal related wind speed exponent (dimensionless)
P - vapor pressure function (dimensionless)
2. Withdrawal Losses:
Lw _ (0.943)OCWL(1 + (NcFc/D))/D
Where:
Lw withdrawal loss (Ib/yr)
O throughput (bbl/yr) (tank capacity [bb() times annual turnover
rate)
C = shell clingage factor (bbl/1,000 ftp
Wi = average organic liquid density (ib/gal)
0 = tank diameter (ft)
No - number of columns (dimensionless)
Fc - effective column diameter (ft)
3. Deck Fitting Loss:
* .
LF = FFP MvKc
Where:
LF = the fitting loss in pounds per year
FF - total deck fitting loss factor (lb-mole/yr)
_ {(NF1 KF1) + (NF2KF2) + ... + (NFnKFn)
NFi = number of deck fittings of a particular type (i 0,1,2,...,n)
(dimensionless)
KFi = deck fitting loss factor for a particular type fitting (i = 0,1,2,...,n)
(lb-mole/yr)
n = total number of different types of fittings (dimensionless)
STti' K_ >CS ( 'Za Q Q 4 D 6 ft-C ry S
(0715.91) 21-4 � i �,,�
REQUEST FOR INFORMATION;
RISK SCREENING ANALYSIS
NOTE. You must fill out one of these forms for each source in the permit
application that requires a risk screen. These may be discrete sources such as
stacks, or area sources such as surface area fugitive emissions.
Plant name
Source description
SECTION A
1 , is the source a clearly refined emission point. i.e.. a stack? YES
NO
(if NO. go on to section B)
2. Does the stack stand alone or is it located on the roof of a building?
ALONE ON ROOF
3. What is the stack height? meters or feet
(Note; stack height o ly,, whethe�ee-standing or on rooftop)
4. What is the combined stack height and building height (if applicable)?
meters or feet
5. What is the stack diameter? meters or feet
6. What is the stack flowrate? cfm or m3/sec
7. What is the stack exit temperature? degrees
Fahrenheit or Centigrace
8. If the stack is located on a rooftop, what are the dimensions of the
building?
height = meters or feet
width = meters or feet
length meters or feet
0
Risk Screening Analysis
9. Are there any buildings, wails or other structures located near this
source ?
YES NO
if YES, what are their dimensions?
height = meters or feet
width = meters or feet
length = meters or feet
distance from source meters or feet
(GO ON TO SECTION C)
SECTION 8
1. Is the source located within a building? YES NO
(If NO. please provide a description of the source. For example,
fugitive emissions that must be evaluated as an area source. If an
area source, provide the dimensions of the area in question. Then
go on to section C.)
(If YES, proceed to #2, below)
2. Does the source exhaust through the building ventilation system?
YES NO
a. If NO, can we assume that emissions from the source escape via the
building's doors and windows? YES NO
(If your answer here is also NO, please explain where the
emissions are going)
Risk Screening Anaiysis
3. Please provide the building dimensions:
height = meters or feet
width = meters or feet
Length = meters or feet
4. Are there any buildings, walls or other structures located near this
source ?
YES NO
If YES, what are their dimensions?
height = meters or feet
width = meters or feet
length = meters or feet
distance from source meters or feet
(GO ON TO SECTION C)
i
l I�
3
/Vo
risk Screening Analysis
SECTION C
1 Describe the area where the source is located (select one):
a) zoned for commercial use
b) zoned for residential use
2. Distance from source (stack or building) to property line
meters or feet
2. Distance from property line to nearest receptor" =
meters or feet
You must provide a plot plan or a map, drawn toscale. which clearly
demonstrates the location of your site, the property lines and any
surrounding residences and/or businesses.
�* Receptors are defined as individual dwellings where persons are assumed to
be in continuous residence.
j 4
REQUEST FOR INFORMATION;
RISK SCREENING ANALYSIS
NOTE: You must fill out one of these forms for each source in the permit
application that requires a risk screen, unless all sources exhaust through a
single stack. These may be discrete sources such as stacks or area sources
such as-surface area fugitive emissions.
Plant name
Source description
Source # Emission point
(if known) (if known
SECTION A
1. Is the source a clearly defined emission point, i.e., a stack?
YES NO (If NO, go on to section B)
2. Ooes the stack stand alone or is it located on the roof of a building?
ALONE ON ROOF
3. What is the stack height? meters or feet
(Note: stack heightnlr , whether free-standing or on rooftop)
a. What is the combined stack height and building height (if applicable)?
meters or feet
5. What is the stack diameter? meters or feet
6. What is the stack gas flowrate? cfm or m3/sec
7. What is the stack gas exit temperature? degrees
FaFf—e—n67t or Centigrade
8. If the stack is located on a rooftop, what are the dimensions of the
building?
height = meters or feet
width = meters or feet
length = meters or feet
Risk Screening Analysis
Octccer 23. 1991
9. Are there any buildings, walls or other structures located near this
source ?
YES NO
If YES, what are their dimensions?
height = meters or feet
width meters or feet
length = meters or feet
distance from source meters or feet
(GO ON TO SECTION C)
SECTION 8
t. Is the source located within a building? YES NO
(If NO, please provide a description of the source. For example,
fugitive emissions that must be evaluated as an area source. If an
area source, provide the dimensions of the area in question. Then
go on to section C.)
(if YES, proceed to #2, below)
2. Does the source exhaust through the building ventilation system?
YES NO
a. If NO, ,can we assume that emissions from the source escape via the
building's doors and windows? YES NO
(If your answer here is also NO, please explain where the
emissions are going)
12 .
2
• • 1 u0
Risk Screening.Analysis
October 23, 1991
3. Please provide the building dimensions:
height = meters or feet
width = meters or feet
Length = meters or feet
4. Are there any buildings, walls or other structures located near this
source ?
YES NO
If YES, what are their dimensions?
height = meters or feet
width = meters or feet
length = meters or feet
distance from source meters or feet
(GO ON TO SECTION C)
SECTION 8
1. Describe the area where the source is located (select one):
a) zoned for commercial use
b) zoned for residential use
c) zoned for mixed commercial and residential use
2. Distance from source (stack or building) to property line =
meters or feet
9 (continued on p. a)
3
Risk Screening Analysis
October 23. 1991
3. Distance from source to nearest receptor" _
meters or feet
You must provide a plot plan or a map, drawn to scale, which clearly
demonstrates the location of your site, the property lines and any
surrounding residences and/or businesses. The plot plan or map should
also show the location of the source(s) at the site and their relationship to
the property line.
** Receptors are defined as individual dwellings where persons are assumed to
be in continuous residence.
I � .
4
• i 1 ,qo
STATE OF CALIFORNIA
PETE IIILSON, Governor
AIR RESOURCES BOARD
2020 L STREET
P.O. BOX 2815 y
SACRAMENTO, CA 95812 '
March 22, 1994
Lisa A. Stensgard
Senior Environmental Analyst
Shell Oil Company
Western Distribution Region
P.O. Box 4848
Anaheim, CA 91406
Dear Ms. Stensgard:
Executive Order G-70-126I
As I informed you in my letter dated January 11 , 1994, the daily
throughput limits for six Shell Oil Company Bulk Terminals have been
increased 20% over the actual throughput demonstrated during testing. The
Bulk Terminals of concern include West Sacramento, San Jose, Signal Hill ,
San Francisco, Stockton, and Martinez.
Enclosed you will find a copy of Air Resources Board Executive Order
G-70-126I. The Executive Order lists the new daily throughput limits in
Exhibit 1.
If you have any questions concerning the Executive Order please contact
Gary Zimmerman at (916) 322-2886.
Sincer ly,
James J. Morgester, Chief
Compliance Division
enclosure
cc: Yolo-Solano AQMD
Bay Area AQMD
South Coast AQMD
San Joaquin Valley Unified APCD
State of California
AIR RESOURCES BOARD
Executive Order G-70-126I
Vapor Recovery Systems Installed on Gasoline Bulk Terminals
WHEREAS, pursuant to California Heath and Safety Code sections 39600, 39601,
and 41964, the Air Resources Board (the "Board") has adopted Title 17,
California Code of Regulations section 94003, which provides that gasoline
vapor recovery systems at gasoline terminals shall be certified in
accordance with the Board's "Certification and Test Procedures for Vapor
Recovery Systems at Gasoline Terminals" adopted April 18, 1977, as last
amended September 12, 1990 (the "Certification and Test Procedures");
WHEREAS, the companies listed in Exhibit 1 (attached) have applied for
certification of their gasoline bulk terminal vapor recovery systems (the
"Systems");
WHEREAS, Section VILA of the Certification and Test Procedures provides
that the Executive Officer shall issue an order of certification if he or
she determines that a vapor recovery system conforms to all of the
requirements set forth in paragraphs I through VI; and
WHEREAS, the Systems have been evaluated pursuant to the Certification and
Test Procedures;
WHEREAS, I find that the Systems conform with all of the requirements set
forth in paragraphs I through VI of the Certification and Test Procedures.
NOW, THEREFORE, IT IS ORDERED that the Systems are hereby certified to meet
the applicable certification performance standards.
BE IT FURTHER ORDERED that compliance with the applicable certification
requirements and rules and regulations of the Division of Measurement
Standards, the State Fire Marshal's Office and the Division of Occupational
Safety and Health is made a condition of this certification.
BE IT FURTHER ORDERED that compliance with the applicable rules and
regulations of the applicable air pollution control district is made a
condition of this certification. J
Executive Order G-70-1261 -2-
BE IT FURTHER ORDERED that the Systems certified hereby shall operate at a
terminal gasoline throughput and emission limits not to exceed those listed
in Exhibit 1. During delivery tank filling operations, the vapor recovery
system shall not cause the pressure in the delivery tank to reach 18 inches
of water. Gasoline throughput computer printouts or copies of delivery tank
fueling receipts shall be available to the Air Resources Board and local air
pollution control district upon request. The Systems in actual use shall
perform as during the certification test. Compliance with these criteria
and any special conditions listed on Exhibit 1 shall be conditions of this
certification.
IT IS FURTHER ORDERED that any alteration in the equipment, parts, design or
operation of the Systems certified hereby is prohibited, and deemed
inconsistent with this certification, unless the alteration has been
approved by the Air Resources Board Executive Officer or his or her
designee.
IT IS FURTHER ORDERED this Executive Order shall supersede Executive Order
G-70-126H dated September 17, 1992.
Executed at Sacramento, California this !Z day of March, 1994.
James D. Boyd
Executive Officer
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Catalytic Reforming: Reforming converts one type of hydrocarbon molecule into a
new Eype. I he products of reforming have nearly the same molecular weight as the
feed material.
This process boosts octane numbers of gasoline components significantly. Platinum
catalysts are required. This process produces a gasoline blending component called
"Platformate" for gasoline.
Alkylation: Most processes in the refinery take long heavy hydrocarbon chains and
crack or reform them into lighter products. Alkylation does the opposite. This
process takes light gaseous materials (e.g. isobutane and butylene, 4-carbon (C4)
molecules) and joins them together to make a longer chain (i.e. iso-octane, a C8
molecule). Certain C8 molecules, such as iso-octane, have very high octane ratings.
This process increases the octane number of gasoline,significantly.
A simplified flow diagram of the existing and proposed LOP facility is shown in Appendix
B-3, for review by the interested technical reader.
Shell Oil Company has proposed numerous separate but related activities to make the
modernization project fulfill the goals the company has set (Section III, preceding). For
ease of understanding, the proposed modifications and construction are described in
relation to the goals of the modernization project. The Glossary contains definitions of
technical terms.
Goal 1: Increase the refinery's capability to process heavier crude oils found
predominantly on the West Coast and reduce the refinery's demand for lighter
foreign crude oil.
To achieve this goal, the company proposei to modify the crude distillation process and
vacuum flasher. These modifications would consist of energy conservation measures and
hydraulic debottlenecking. Since the crude gravity would be about 220 API gravity, an*
additional desalter would be required for the brine/oil separation. The revisions would-
expand crude oil distilling capacity by approximately 20,000 B/D. (API gravity: a
measure of the specific gravity of oil: the higher the number, the lighter the oil. An API
gravity of 400 indicates very light oil, a gravity of 100 very heavy oil. A gravity of 10o
is equivalent to the density of water. Almost all oils are lighter than water. This
concept is important because it roughly indicates the percentage of desirable light
products, gasoline and aviation turbine fuel, in the crude oil. Oil used in Martinez.with a
gravity of 150 has about 20% light products while oil with a gravity of 270 has about 40%
light products.)
The modifications to the crude unit would increase the energy efficiency of the facility
by adding heat exchangers and by transferring products at higher temperatures to
succeeding processing units. Such transfer would reduce the heat requirements at those
following process units.
In addition to modifying the crude unit, Shell proposes to increase its hydrotreating and
sulfur-removal capacity. The hydrotreating would reduce the quantity of sulfur in the
products. Shell proposes to use a Claus plant with a Shell Claus Off-Gas Treating
Process (SCOT) tail unit to recover and dispose of additional sulfur from the products.
The increased hydrotreating capacity would require the construction of a new hydrogen
plant to supply the needed hydrogen.
Because the proposed operating mode with heavier crude would produce more residual oil
than the current operating mode the company would have an excess supply of residual
oils and pitch. Shell proposes to eliminate this excess supply with a new process unit
141
12
called a Flexicoker. The Flexicoker would be sized at 22,000 B/D ("stream day", i.e., at
maximum rated capacity) and would process vacuum flasher pitch and clarified oil from
the catalytic cracking unit. The Flexicoker would perform a coking function. Coking
drives off light volatile hydrocarbons and thermally cracks longer, heavy hydrocarbon
chains into lighter products. The Flexicoker would produce a low-BTU gas (a gas with
about 100-150 BTU's per standard cubic foot; natural gas has about 1000 BTU's per
standard cubic foot) which would be scrubbed to 125 parts per million (ppm) sulfur prior
to being burned with refinery gas (primarily methane, ethane and hydrogen from refinery
processes) in selected refinery furnaces and boilers. The secondary products of the
coking process are called conversion feeds. Coking also has other benefits which are
discussed below.
The Alaskan oil is shipped in special tankers designed for that purpose. These tankers are
189,000 ton very large crude carriers (VLCC). In order to accommodate the tankers,
Shell would have to modify its wharf prior to the start-up of its new process equipment.
Goal 2: Reduce inter-refinery movement of unfinished oils (conversion feeds) between
Los Angeles and San Francisco areas.
The Martinez facility sends its vacuum-flasher pitch to its Los Angeles area facility
where it is caked. The resulting conversion feed is then shipped back to Martinez for
further processing. Construction of the Flexicoker would reduce the need for these
inter-refinery shipments.
Goal 3: Improve refinery energy utilization.
In addition to saving the energy required to ship materials to Los Angeles and back again,
Shell proposes a variety of steps to improve energy utilization. The first would be the
installation of numerous heat exchangers to capture heat lost to the atmosphere, thus
reducing the amount of heat required from fuel combustion. The second would be to
transfer products more efficiently within the refinery. The third involves the installation
of a computer for furnace combustion control with oxygen
ygen analyzers in all proposed and
existing furnaces. In addition Shell plans to improve its distillation processes and to
generate process steam in waste heat boilers.
Goal 4: Convert high-sulfur residual products into clean fuels for transportation uses
and reduce the supply of high-sulfur residual products, which have limited use
in the western United States.
The supply of high-sulfur residual products exceeds .the demand. This is because
environmental restrictions limit the use of high-sulfur oils. The only use for these oils is
for bunker fuel; numerous ships call on Los Angeles and San Francisco ports for the
purpose of obtaining the high-sulfur oil at prices substantially lower than world market
prices.
The Flexicoker would reduce the supply of high-sulfur fuel oil by the processes described
above. The sulfur would be removed from the Flexicoker low-BTU gas by the Stretford
process (a proprietary process used to remove sulfur from gas streams). The sulfur in the
hydrocarbon gases produced in the Flexicoker would be removed by a new treatment
system.
Goal 5: Increase the, supply of aviation turbine fuel and gasoline while maintaining
existing octane capability.
The facilities required to reduce the manufacture of residual oils at Shell's Martinez
refinery (i.e. the Flexicoker and Hydrogen Plant) increase the yields of gasoline and
turbine fuel. Gasoline production would increase by 11,000 barrels per day and aviation
turbine fuel production would increase by 4,000 barrels per day. To maintain
13
AUGUST, SEPTEMBER AND OCTOBER 1979 STATE LANDS SHELL SHIPPING STAT.
EMISSIONS -
PER 1000 BARRELS POUNDS BARRELS
GALLONS PRODUCT LOADED EMISSIONS UNLOADED
LOADED
.00004 ASPHALT 297, 942 .5 00
1 . 4 AVIATION GASOLINES 00 - 38, 497
. 00004 BASE/POLE TREATING OILS 45, 488 . 08 0.0
. 005 CATALYTIC CRACKING FEED 165, 847 35 . 879, 567
1. 7 CRUDE OIL unknown - 2, 436, 706'
. 005 DISTILLATES 47, 222 10 . 319, 365
05 DOMESTIC JET FUEL 00 - 22, 471
. 115 HEAVY-INTERNED. PROC.STK 10, 000 2 . 1 1, 659, 715
. 00004 LUBE OIL COMPONENTS 305, 118 . 5 49, 470
1.4 MIDDLE GRADE GASOLINES 40, 2442 2, 366 . 00
1.4 MOTOR GASOLINE COMPONENTS 654, 963 38, 512 . 00 .
. 002 PROCESS OILS (?) 4, 430 . 37 00
. 002 RESIDUAL PROCESS STOCKS 137, 215 12 . 10, 595
. 00004 RESIDUALS 1, 114, 978 2 . 319, 070
. . 002 SPECIAL PRODUCTS 76, 599 6. 00
2, 900, 046 20 . 5 tons 5, 735,458
Notes:
1984 BAAQMD permit conditions modification loading
-able does not include ballasting. Steve Hills March 21,
_.-..sheet upon which the 184 modifications are supposed to be
.:��u, aoes list ballast at 1. 6 lb/1000 gallons loaded.
q0
401.1 On or before July 1, 1977, any person who operates a facility causing
emissions in excess of 450 metric tons (500 7) per year of any air
contaminant for which there is a national or California ambient air quality
standard.
401.2 On or before July 1, 1978, any person who operates a facility causing
emissions in excess of 90 metric tons (100 T) per year of such air
contaminants.
401.3 On or before July 1, 1979, persons who operate a facility causing emissions
in excess of 22.5 metric tons (25 T) per year or more of such air
contaminants.
401.4 On or before July 1, 1980, persons who operate a facility causing emissions
of 2.3 metric tons (2.5 1) per year or more of such a'ir contaminants.
401.5 On or before July 1, 1980, persons who operate gasoline terminals, bulk
plants and facilities that dispense gasoline for sale or dispense more than
60,000 gallons of gasoline per year. (Amended April 16, 1986)
40,11.6 Persons who operate coating equipment at any facility whose coating or
laminating operations consume greater than 20 gallons of coating per year
on a facility-wide basis. (Adopted January 7, 1987)
401.7 Persons who operate surface preparation and cleaning equipment or
operations which use unheated solvent and which contain more than 1
ga2llon (3.785 liters) of sol ent or have a liquid surface area of more than 1
ft. (144 in 2 or 929 P) including pipe cleaning operations using more
than 5 gallons per year of solvent. (Adopted January 7, 1987)
2.1-402 Applications: Every application for an authority to construct or a permit to operate
shall be submitted to the APCO on the forms specified, and shall contain all of the
information required. Sufficient information must be received to enable the APCO
to make a decision or a preliminary decision on the application and/or on any
exemptions authorized by this Regulation. The APCO may consult with appropriate
local and regional agencies to determine whether the application conforms with
adopted plans and with local permit requirements.
2-1-403 Permit Conditions: The APCO may impose any permit condition that he deems
reasonably necessary to insure compliance with federal or California law or District
regulations. The APCO may require the installation of devices for measurement or
analysis of source emissions or ground-level concentrations of air contaminants.
2.1-404 Changes In Throughput and Hours of Operation: After a permit to operate has
been issued, changes in hours of operation, fuels, process materials or throughput
are allowed only if emissions resulting from such changes are not of such quantity
as would cause denial of an authority to construct after an air quality permit
analysis made pursuant to the provisions of Rule 2 of this Regulation. "Change" is
the use of a process or fuel not used in the prior 12 months, or a throughput level
higher than the highest level in the prior 12 months or total monthly operating hours
higher than any month in the prior 12 months.
404.1 The holder of a permit to operate shall advise the APCO not more than 30
days after any changes in hours of operation, fuels, process materials or
throughput which might increase emissions.
404.2 The APCO shall act to revoke the permit to operate of any person who fails
to comply with the requirements of this Section.
2-1-405 Posting of Permit to Operate: Every permit to operate, or approved designation
thereof, shall be posted on or near the equipment for which the permit has been
issued in such manner as to be clearly visible and accessible, or shall otherwise be
available for inspection at all times.
2-1-406 Transfer: An authority to construct or a permit to operate shall not be transferable
from one facility to another. An authority to construct or a permit to operate shall
not be transferable from one person to another without obtaining written permission
of the APCO.
2-1-12 January 7, 1987
TABLE 2
SM2 ARY OF ESTMATED MARTINEZ i.'HARF EMISSIONS'/
1977 POST
BASE MODERNIZATION
Hydrocarbons From Loading - Lbs./Yr. 473,419 (3). 767,086 (3)
Hydrocarbons From Operations - Lbs./Yr. 17,368 (5A) 16,801 (7)
Total Hydrocarbons - Lbs./Yr. 490,787 783,887
SOX - Lbs./Yr. 717,091 (5A) 541,098 (7)
NOa - Lbs./Yr. 256,409 (5A) 246,271 (7)
Particulates - Lbs../Yr. 47,358 (5A) 39,506 (7)
1/ Calculated .from shipments in Table 1, emission factors in Tables 3, 4, 9-14,
and vessel operations in Tables 6A and 8. Based on 2`l. S fuel in all vessels ,
300,000 bbl. diesel driven gasoline ships loaded at 14,000 B/Hr, average rat.
,
~ ,
'
EMISSIONS POST
0
�
Gasoline 1.42/-!L 223,511 3I2,915 459,900 643^8'
' un�]/
Turbine Fuel .°"�-� 25,448 127 76,650 3E
Diesel .0053/ 13,337 67 '12,724 6
�
Conversion Feed ,OO54�/
I1,498 57 45,990 23'
]
Residual Fuel .000043/ 284,983 lI 105,010 �
. �
'
'
Ballast I/= l.6-��5/
91^367 146,187 27,248 43,597
' ,6/
` Lightera6 Crude l. /-' 7,972 13,552 46,144 78,445
Y ..~7/ -
.`
Solvents � ,uu�-' I3,950 70 I3,950 70
�`
Lubes .0O-,4/_ 46,450 232 46,450 232
���
Asphalts ' .uu5-' 40,165 201 48,165 201
"1
Total Hydrocarbon Emissions-lbs/yr. 473,419 767,086
Average Hydrocarbon Emissions-lbs/day 1,297 2,102
!
l/ 25"'. of the cargo volume of vessels not listing segregated ballast in CIarkson's
Tanker 8eQiaccr.
� Average cargo tank condition, Table 4.4-2 of AP-42, 4/77.
` -- Table 4.4-3 of AP-42~ 4/77.
ZI Assumed, actual emission is probably lcss,
5 Ararago of test data submictoJ to EPA in 1978 by 8-31 Committee for Industry
Study of Eoissinns.
Loading barges, Table 4.4-3 of AP-42° 4/77.
il Distillation range similar to turbine fuel.
8/ From Table I.
'
qo
C)t:
Cc'ober 9 1981 4A '1ri
it rr!
T0: is .. P . HESS
I
A
trL1i: 5 . t:ILL '
Y
SiJBI Z T : S;iELL IMIIDD UI'.:Z.tiT!ON WHARF EM,1SS:ON FACTORS
aackzroun
When She11 ' s modernization project was approved, the District agreed
to use an organic emission factor of 1. 4 lb/mgal for loading gasp-
line . This factor comes from AP-42 , and is an average value for
loading gasoline into clean ships (emission factor 1.0) , ballasted
ships (1. 6) and uncleared dedicated ships (2 .4) . This does not
inc:ude loading gasoline into barges. Use of the average emission
factor assumes that dean ships will be used almost exclusively.
,— > Shell :.ow proposes alterations to their original proposal . These
consist of 'Loading ships with materials not previously discussed.
17T,ese .include an unknown quantity of heavy San Joaquin Valley crude ,
brought in ria the Getty pipeline , for export to other facilities .
Shell :as Drz:aosed emission factors for all of these materials based
upon equation (1) on page 4. 4--4 of AP-42. (See attached table) .
These emission factors are 'Low due to low vapor pressures .
Reco.zrte:ndations
�---� in evaluating the A/C issued , I have corse to believe that 1.4 lb/gal
is an unrealistically low factor Tor Shell' s operation (using AD-42
eruation;,) fin ished gasoline em ssion factors range from 1. 3 to 3. '
ib/algal) . I realize that we are, however, cormitted to it. 2 pro-
po=e t::at we class F ► the heati.f gasoline components in Table I as
gasoline for the pu-poses of emission calculations . This will tend
to co=ensats for the lcw Prission factor, used for high vapor pres-
sure finished gasolines .
---�► =or Alaskan North Slope and Labuan crudes we should use the emission
*actor o: l. -r used by Shell in their original application for light-
ering these _ruder . For hea-:*y Sart Joaquin ;Talley crude we have
calculated an emission factor o; 0 .1. he have no problem with the
other fact,,rs as prcpose_i by S;zell.
Conclusion
ol;t that our "'cp osed ficto s, are a compromise betwe^r,
She:i ` s fac—:.irs and %he , crsL rigo7ocis approach used with Chevron ar,�i
..:e .r higher fzctor•: for hcairf ,grasoi ine components may in
Tart :,,m.pen! _.e for low `.actors used for finished
i
gas„li-=s ,
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IrLD
A �
BAY AREA AIR QUALITY MANAGEME IS ICT '
ALAMCOA COUNTY May 9, 1990
Fray F COOOar 1 4.
t N "J,aqs'Landis
Frans N.Oga.a
Vrrar,a A Raymond Shell Oil comp3ny
:ONTAA COSTA COUNTY P.O. Box 711
[r,t., mosbon.ne Martinez, CA 94553
Varna L 110001ts
MAXIM COUNT, Application tb. 26795
6:•Oa,a 4...•
Attention: 4r. R. M. 1hump3on
NAVA
sa^ 4.,a1-- .� Gentlemen :
.AN FpANCtSCO C:.,,4'.''
a,,,+,.-N This is your coalitional Authority to Construct the following
Ca'2.R_:-�... new and modified prc`cess ',nits aryl new and modified tankag(a at
SA•l vl,-c. c.u . your 4-irtinez Manuf3=taring, complex:
"'=•C A. @few Process Units
5ANTa C:xa. ... ` 1. FlexicoOr - StretfurJ Unit, 22,00" Sarrels/
dto . - Stream Day Opacity.
pato.
„so' � it%s'"
parr 4. 2. Flexicuk!r 'team Superheater, 75 WSTU/HR
-naxiiiLm haat rele3sa.
`a `.' 3. Fl exico•ker Pitch Heater, 10 AM RTU/HR maximus _
heat release.
4. Hydrogen Plant and Steam Methane Reformer, 774 4
M`! STU/HR maximum heat release.
S. Catalytic Rsforner Tnterhpater, 90 MM BTU/KR
maxi-num heat release.
6. Crude Unit Feed Heater, 150 MM M/HR maximvn
heat release.
7. IFP Dimerization Unit
S. 65 Luna Ton Claus Plant abated by SCOT Tail Gas
Treater.
9. Claus Plant Incinerator
Z 10. Coke Storage Bins A and B abated by Bagtvusss.
11. Purge Coke Silo abated by Baghouse.
12. C3/C4 Splitter
13. Flexiccker Flare, 150,(M SUM.
14. Hydrocarbon Flare for New Steam Methane Refor-ner
aad Dimerization Unit.
15. Cooling Tower-LCF; 13,MO gpn.
H. New Tanks
1. Crude Tank, 315,000 bbl Caps:ity, with District
Aporovel Wubl a Seal .
2. Tufo N3ptha Tanks, 135,000 bbl Capacity each;
abated by Vapor Recovery System.
3. Heavy Cat Cra.ked Gasoline Tank, 135,000 b51
Capacity; abatwi by Vapor Recovery System.
4. Two Gasoline Tanks, 195,000 bbl each; abated by
Vapor R-tcvvery Systen.
5. Ballast Water Tank, 70,000 bbl Capacity; with
District Approved Double Seal .
6. Two Gasoline Tanks, 83,000 bbl each with District
Aoprovei Double Seal.
C. Modified Tanks
1. New Vapor Recovery System for Crude String. 53R
serving Tanks 11W. 493, 484, 530. 531. 532. and
539.
2. Tanks No. 14,18.20.534. 1139. 1140 and 1141 vented
to Existing Vapor Recovery System. A-26.
3. Installation of District Approved Secondary Seals
on Tanks 1046. 1051 , 1067, 1072 and 1076.
q0
D. Mudified Process !hits '
I. Modifications to the fbtlowing existing process units as
specified in Volume II of permit application.
a. Crude Unit/Vacuuyt Flasher
b. Catalytic Cracking Cas Plant
c. Hydrocraker and Saturates Gas Plant
d. Catalytic Refor-ner Unit
e. Hantha And Cas 011 Hvdrotreaters
f. Catalytic Feed Rydrotreater
R. Catalytic Gasoline Hydrotreater
h. Distillates Saturation Unit
2. Modification of the following heaters to burn Low-BTU
Flexicoker gas ;i.e. installation of 'tri-Fuel Burners)
F-40, F-41A, F-41B. F-49, F-50. F-51.
F-59. F-53. F-71
Please notify us by letter about three days before yuu are reviy to
operate su that we stay observe your equipnent in operation before we
issue a Permit to Operate. This authority to construct is valid
during the start up p:riod and trail it is either suspended or a
Permit to Operate is issued.
Your Per-tit to Operate, when issued. will contain the following
conditions:
PERMIT CONDITIONS
The following are the proposed conditions for the permit
W operate.
The purpose of those conditions is to guarantee that:
1. a net air Quality benefit is achieved.
2. all Mission redue-tions required fbr offsets
are prov id ed.
A. Refinery ,Conditions
1. Total fuel usage shall not exceed 14730 VVE (Net
Liquid Fuel Equivalent) Barrels/Calendar Day. (One
NLFE Barrel has a heating value of 5.96 V4 BTU. A
calendar day basis is an average value determined
by dividing the yearly total by 355.) This total
shall include all natural Ras, refinery Ras, propane,
flexigas, flexicoker coke, cat cracker low4M Ras
(CO), cat cracker coke and low-sulfur fuel oil burned
In refinery process units, heRters and boilers. Shell
will report daily usage of each type of fuel to the
District on a monthly basis.
2. Fuel oil usage and allowable sulfur content.
a. lbtal low-sulfur liquid fuel used in refinery
process heaters and boilers shall not exceed 4000
NVE Barrel s/Cal end or Day or 50M NLFE Barrels/
Stresam Day. A stream day is defined ss the actual
daily rate.
b. If liquid fuel usage is between 0 and 1,000 NVE Bar-
rels/Calen-lar Day the allowable annual average sulfur
content of this, fuel is not to exceed 0.491% by 'weight.
If liquid fuel usage is between 1,0(X1 and 4,000 NVE
Barrels/Calendar Day the allow:ablo annual average
sulfur content of this fuel is to be found using the
following equation:
Weight % Sulfur -_ (434)/(NLF'E 9arrels/C3lendar Day)
If t" emissions of sulfur dioxide from the catalytic
cracking unit (CCU) are shoran to be less than 4.43
Tons/S*.ream Day, Shell may request the APCO to reeva-
lu3te the above equation. 1h13 condition is dependent
upon the installation of a District approved CEM monitor
for 302 in the No. 3 CO Boiler Stack.
c. In the event that the Flex icoker Unit is down, liquid
fuel consumption can be increased to a maxtium of
9.000 NVE Barrela/Stream Day. If liquid fuel con-
sumption is betty-en 4.000 and 5.0x}0 NLFE Barrels/Stream
day during Flexicoker shut dorm, the t3xitmus content of
this fuel shall not exceed 4.125 by weiSht. If liquid
fuel conwnotion exceeds 5.000 NLFE Barrela/Stream 03y,
d u-i ng Fl ex icoker shut down, the m ax i aum sulfur content
of this liquid fuel shall not exceed 0. 15 by weight.
Shell shall determine the average sulfur content of
this liquid fuel on a weekly basis unless commnp►.ion
exceeds 4,600 NNE Barrels/Stream Day in which case
sulfur content will be determined daily. Shell shall
report these data to the District on a monthly basis.
3. 'fie net sulfur content of the coke burners in the
regenerator of the Catalytic Cracking Unit (CCU) shall
not exceed an annual average of 0.38% by weight. Shell
will draw equal size spent and regenerated catalyst
samples from the CCU daily and analyze a weekly composite
of each for sulfur and coke content. fie net sulfur con-
tent of the coke will be determinei from these samples by
a method approved by the PAAQMD. Shell shall report weekly
net coke yield and weekly net sulfur content of the coke
/ burned in the regenerator on a monthly basis.
4. Shell will install and maintain continuous monitors
to measure H25 concentration in the flexigas system
qD
and the refinery gas system. The annual average H2S
concentration shall not exceed 60 We fbr refinery
gas and 17 ppm fbr flexigas. 'fie average daily H2S
concentration for each system will be reported to
the District on a monthly basis. In arMition, Sill
shall report hourly averages in order to show com-
pliance with the MSPS liotit.
5. The computer control system fbr controlling firnace
combustion will be demonstrated to tho 3at13faCtion
of the APCO.to be capable of achieving a fuel savings
of at least 200 KLFE Barrels/Calendar Day before the
new process units covered by this permit shall be star-
to-ad up.
6. Sh,!�l l will determine base-line IN?x emissions from all
furnaces which will be modified to fire flexigas. All
testing may be observed as required for approval by a
representative of the BAAQMD.
7. after start-up of the Flexicoker, Shell will determine
WN emissions from new and modified furnaces firing
flexigas. All testing may be observers as required for'
approval by a representative of the AAAQMD.
S. Liquid raw material intake (crude oil plus other petroleum
liquids) is not to exceei 129,000 Barrels/Calendar Day.
Shell will report to the District the total intake over
the wharf and through the pipeline on a monthly basis.
9. The Flex icoker Pitch Heater will be equipped with a low-
NOx burner approved by the APM. See SACT discussion
Section II.A.3 of the permit evaluation report.
10. Catalytic cracking capacity sh-ill not exceed 65,000 Barrels/
Stream Day, or emissions equivalent to 55,000 Barrels/Stream
Day.
11. Flex icoker capacity shall not exceed 22,000 Barrels/
Stream Day, or emissions equivalent to 22,000 Barrels/
Stream Ny.
12. Crude distillation shall not exceed 124,000 Barrels/
Stream Day.
13. Within 90 days of startup of the SCOT unit on the exis-
ting sulfur plants, Shell will demonstrate that the
required CO emission reduction is being achieved. All
testing may be observed as required fbr approval by. a
representative of the BAAQ4D.
15. The new process heaters will be 11111ted to a maximum
total heat release of 699 ` M BTU/HR. Shell will advise
the District if the maximum heat release design values
for the new heaters listed below are charged during the
authority to construct period.
Max imum bleat 11•lea3e
(MM BTU/HR)
a. Gude Unit Feed Neater 150
b. Catalytic Reformer Inter-Heater 90
c. 94R 2 Rx Heater 374
d. Flexicoker Stem Superheater 75
e. Flexicoker Fitch Heater 10
Total
B. Tankage CoM it tons
1. True- vapor pressure of all liquids stored in the
following tanks: T-14, T42O, T-11390 T-1140 & T-1141
shall not equal or excevi 1.5 psia under actual sto-
rage conditions.
2. 'fie following existing tanks will be controlled by a
vapor recovery systea capable of controlling hydro-
carbon emissions to « lb/day/tank: T-483, T-4849
t-530r T-5319 T-532, T-5399 T-149 T-?09 T-113910
T-1140, T-1141, T-18.
3. rie following new tanks will be controlled by a vapor
recovery syteim capable of controlling hydrocarbon
emission to <5 lb/dsy/tank:
a. 2 New Ilaptha Tanks (135,WO barrels each)
b. 1 New Heavy Cat Gasoline Tank (135,000 barrels)
c. 2 Yew Gasoline Tanks (195,O04 barrels each)
4. Tank T-1076 is to remain in ATF (aircraft turbine
fuel) service and will be subject to the double seal
requirements of the District.
C. Marine Operations - Conditions
1. the following marine operations shall be. limited to
those volumes listed in Tables 3 and 4 - Whsrf/Vuluoe I
of the Permit Application, namely:
a. Gasoline loading 10,950 M barrels/year
b. Turbine fuel loscding 19$25 y barrels/year
c. Ballast for crude tankers
without s.grated ballast 549 y barrels/year
d. Lightering of crude within
S.F. Bay 1,099 M barrels/year
To provide for changing market needs anl availability of
tankers for charter, the vuluees of thea operations may
be interchanged on a hydrocarbon emission equivalent basis.
2. The total number of voyages for tankers delivering crude
and taking out products will be limited to the shipping
schedule as d13playwf in the Per-nit Application-Wharf
E-nissions - Table 9, na•nely:
Vessel Site
MDWT Type Voyages/Year
30/45/70 M 49
30/Tn S 33
120/135/150 S&M 3
170/200 S 34
To provide flexibility to meet changing patterns of market
requirements, crude supply, and availability of tankers for
charter, Shell -nay exchange tanker voyages according to the
following Mission equivalency table Nowever, if vessel _
substitutions result in additional emission profile excesses
not considered in the permit evaluation, Shell shall provide
offsets st a 2:1 ratio) .
Gontrollinx Vessel
Vessel Site Equivalency Factor
MDW T Type 2.0% 3 1.5% S 0.5% S
30/45/70 v 1.0 1.0 1.0
120/135 4 0.9 0.9 0.9
30!70 S 0.6 0.8 2.5
120/150 S 0.7 0.9 2.8
170/200 S 1.0 1.2 2.3
Reportin; of all vessel exchanges will be included with
marine activities as provided in Coalition 5 below.
3. Silftar content of fuel oil used by tankers larger
than 170 ' DWT will not exceed 0.55 (by weight) chile
discharging crude oil.
r
4. Shell oil Company shall amens its emergency episode
plan to prohibit the unloading of large crude oil
tankers (greater than 170 NDdT) rhenevar an Advi-
awy/Alert is declared by the APCO of the District.
5. Simultaneous offloading of cargo ve31ilar at the wharf
Shall not be permitted while offloaling large cargo
! vessels (170 MDWT or greater) .
6. Reporting: Shell will report all marine operation
within District waters on a monthly basis. This
report will detail the number and class of all vessels
entering District Waters and will include all infbma-
tion 'on lightering, ballasting, offloaling, loading
etc. required to determine WDissiona.
D. With prior to approval of the APCO Shell may replace all
or any of the permit conditions listed above with a system for
continuously auditing and reporting to the BAAC'ND evission
rates from the modified refinery as a running annual average
on a pound/hour basis.
This continuous audit must demonstrate compliance with the emis-
sion limitations including profile exceedences and Off-30t
requirements specified by the District. Emissions are to be
determined using emission factors and/or continuous emission
monitoring (CN) data use by the District in its evaluation
of Shell's Permit Application No. 267R5, as. such data are -
appliei to ship 'Movements, wharf activities, fuel. usage, and
fugitive emissions. Prior to the substitution of the con-
tinuous and itin; system fbr any or all of the conditions t istel
in Sections A,B, 1k C above, Shell shall develop a-A demonstrate
the reporting system in 4 manner a.ceptahle to LM APCO, which
acceptance shall not be unreasonably withhold.
Source testing may be requires upon request to assure that all
equipment covered by this p-r-ait is in compliance with District
emission re%ulations. If the above equipment is operated Without
a valid permit (except during the start-up period) , penalty action
may result. Please keep this letter available at the construction
site su that it can be reviewed on request.
This ducLnent does not authorize violations of any of the regulations
of the BnQiD or other governmental agencies. If you have any
questions, call Permit Services at (415) 771-b"M, extension 213.
Very truly yours,
411 ton Faldstein
Air Pollution Control Officer
' BAY AREA AIR QUALITY MANAGEMENT DISTRIC-
t.. x
939 ELLIS STREET • SAN FRANCISCO, CALIFORNIA 94109 • (415) 771.600
L 0 ,L
NOTICE OF PERMIT MODIFICATION
Notice is hereby given that the Air Pollution Control officer has
modified a Conditional Permit to Operate for equipment at Shell
Oil Company' s Martinez Manufacturing Complex. The modification
establishes an emissions "bubble" for most of the refinery;
emissions from sources included in the bubble will be tracked by
computer. Compliance with emissions limitations will be
determined on a daily basis.
A summary of the proposed modifications is available for public
inspection at the District Headquarters, 939 Ellis Street, San
Francisco, California 94109 , in the Public Information and
Education Office, 5th Floor.
Dated at San Francisco, the 30th day of November, 1984.
Milton Feldstein
Air Pollution Control Officer
Hay Area Air Quality Management District
� ,qo
4
BAY AREA T i QUALITY MA GE 1' ICT
939 ELLIS STREET • SAN FRANCISC , CA IF NIA 94109
(415) 771.b000
November 30 , 1984
Shell Oil Coupaay '
P. O. Box 711 �.
Martinez, CA 94553
Attention: Judy Moorad \
Application Number: 26786
Dear Judy:
This is to inform you of the Air Pollution Control Officer' s
decision to modify the conditions of your Permit to Operate the
Martinez Manufacturing Complex. These modifications place most
of the refinery under a "bubble"; for all pollutants except for
hydrocarbons, this bubble will serve as a baseline for future
refinery modifications. For hydrocarbons, the bubble will
provide Shell with greater operating flexibility while ensuring -
Shell' s compliance with the existing permit.
The attached permit conditions, dated November 5, 1984, supercede
all conditions which were contained in the previously issued
Authority to Construct for the WOR project.
If you have any further questions regarding this matter, please
contact Mr. Steve Hill, Senior Air Quality Engineer, in the
Permit Services Division at (415) 771-6000, extension 212.
Very truly yours,
Milton Feldstein
R
Air Pollution Control Officer
BAY AREA AIR QUALITY MANACEMEW DISTRIC
,
939 ELLIS STREET • SAN FRANCISCO, CALIFORNIA 94109 • (415) 771.6W
NOTICE OF PERMIT MODIFICATION
Notice is hereby given that the Air Pollution Control Officer has
modified a Conditional Permit to Operate for equipment at Shell
oil Company' s Martinez Manufacturing Complex. The modification
establishes an emissions 'bubble' for most of the refinery;
emissions from sources included in the bubble will be tracked by
computer. Compliance with emissions limitations will be '
determined on a daily basis.
A summary of the proposed modifications is available for public
inspection at the District Headquarters, 939 Ellis Street, San
Francisco, California 94109, in the Public Information and
Education office, 5th Floor.
Dated at San Francisco, the 30th day of November, 1984.
Milton Feldstein
Air Pollution Control officer
Bay Area Air quality Management District
i
R
- Shell WUR Permit Conditions November 5, 1984
A: -.Shell shall operate the units listeu in Table I in such a way tnat
any, daily emission increases over the oaselxne protile are offset by
• reductions below the profile at a ratio of at least 2.0:1. Compliance
shall be demonstrated on a daily basis in the following manner:
1: For each pollutant, actual daily emissions for the previous
364 days plus the day in question shall be ranked in
descending order by quantity. The calculation of actual daily
emissions shall not be affected by the granting of a variance
by the nearing Board of the District unless such variance
specifically includes a variance from Paragrapa A (1) of these
conditions. In the event of failure or range exceecance of a
monitor upon which emissions are based, emissions shall be
calculated to be the maximum possible under the prevailing
operating conditions in the plant during the event; emission
calculations will be based upon theoretical or historical
emission factors or other information which demonstrates
emission levels to the satisfaction of the APCO
2, The resulting profile will be compared clay by day witn the
baseline profile.
3 . The emissions on each day of the current profile will be
subtracted from the corresponding day of the baseline prof ile.
Positive values are "profile decreases. " The acsolute value
of negative values are "profile increases."
4 . Profuse increases will be totalled; profile decreases will be
totalled. Profile increases will be doubled, and the decreases
will be subtracted from this total. If the result (the
profile excess) is positive, Shell is out of compliance.
Profile Excess = 2.0 X (Prof-, le increases) - (Prof.ie uecceases)
8 . Emission Profiles and emission factors
1. Tables Ii through VI list the baseline prorises for each
pollutant. The baselines reflect actual emissions during the
baseline period, less reductions required by regulation of
sources under the "cap" , and increased by offsets and
increases providea by reductions at operations no; under the
"cap' (i.e. , tankage) .
The baseline profiles were calculated as follows (this
condition contains a summary of the steps used to arrive at
the values in Tables II through VI , and should be updated
every time the baseline profile is adjusted) :
a. Actual refinery emissions for the baseline period 197o-
1978 were calculated using the usage rates contained in 1
Shell' s application 26786 and the emission tactors
contained in these conditions.
b. Actual refinery baseline emissions were averaged over 365
days.
c. Actual refinery baseline emissions were reduces by any
amounts required by District regulations. (Reductions so
far applied: SO2 emissions from sulfur recovery units;
r
t particulate emissions from CO boilers) .
d. Tne hydrocarcon baseline profile nas been increasea by
2300 lb/day uue to abatement on tankage (tankage is not
included under the cap) .
e. The hydrocarbon baseline profile has been decreased by
1543 lb/day due to increases -in fugitive emissions from
process units.
f . The hydrocarbon baseline profile has been increased by 243
.-,�. lb/day due to shutdown of chemical plants not under the
cap (application 29376) .
g. The actual emissions due to shipping in the -base year 1977
were added to the ad3usted refinery baseline.
The baseline daily emissions were ranked in . descending
order by quantity. The results ( the baseline profiles)
are shown in Tables II through VI.
2. Table VII lists the emission factors to be used for aarine
activities. Any changes or additions will be incorporated
into these conditions, and must be approved in writing by the
APC O.
3. Table VIII lists the emission factors to be used for
combustion. Shell may summarize fuel consumption for those
furnaces whicn have identical emission factors. These factor
are subject to annual review and may be changed to reflect
source test results and CEM data. Shell shall determine
average sulfur content for each gaseous fuel on- a daily basis,
anc for each liquid or solid fuel on a weekly basis,
4 . FCC: unit emission factors will be reviewed annually and wild
oe based on source test results and CEM data.
5 . Sulfur plant emissions will be based on the actual measured
sulfur emissions. All emissions will ce included in the
total. Shell will operate the in-stack monitors in such a way
as to provide an accurate measurement uncer all operating +
conditions.
6. Baseline profiles for particulates, NO., S02, and CO may be
modified in the future in the following ways:
i. Shell may increase the baseline profile by provision of
additional offsets by abating or shutting down sources
not included in the cap. The amount of offset credited
snail be the actual emission reduction (as defined in tre
uistrict' s NSR rule at the time of offset) resulting froa
abatement or shutdown of the offsetting sources, reduced
by the offset ratios prevailing at the time of offset.
ii. Shell may increase the baseline profile by buying credits
from the Emissions Bank or reduce the profile by making
deposits in the bank. Offset ratios shall be those
prevailing at the time of offset. The baseline profile
shall be ad3usted to reflect current RACT emission levels
for baseline operations prior to any deposits going into
the bank.
iii. Tne baseline profile will be permanently lowerea to
7 correspond to reductions required by any future
regulations promulgated by the District.
iv. The baseline profile will be permanently lowered by the
ditf erence oetween baseline emissions ana RAC"r for any
source under the cap which is permanently shut down or-
` removea Crow the cap. Tne baseline period uses for
determination of emissions shall be the sauce as was usec
in the evaluation of Permit 26786 (baseline operations
shall be as described in Shell' s Application No. 26786) ,
unless emissions at the affected source were increased as
a result of this or otner permits; in whicn case the
baseline period shall be the two year perioc immediately
preceding the date of application.
V.- If a new source is aodea to those under tae cap, the
profile will be permanently lowered by the amount of
excess offsets required for onsite offsets under the
prevailing NSR rule (I.e. applicable offset ratios and
XACT ad]ustmen ts) .
vi. If a source already under the cap is modified with a
resulting increase in emissions, the baseline profile
will be permanen uy lowered by the amount of excess
offsets required for onsite offsets under the prevailing
NSR rule ( i.e. applicable offset ratios and RACT
ad3 ustmen ts) .
vii. The baseline profile may be adjusted to reflect more
accurate emission factors which may become available,
providing:
---, a. Sufficient data are available to apply the revisea
emission factor to the baseline period.
b. The revised emission factor is approvea by tae APCD,
^---� incorporated into this permit, and is applied to all
future emission calculations.
viiia Notwithstanding any of the above, the relaxation of any
I.;.mu:ts t at increase the potential to emit may require a
full PSOINSR review of the source as though construction
had not yet commenced on tae source.
7 . The baseline profile for hydrocarbons may be mcdified in the
ruture in the following ways:
i. The baseline profile will be permanently lowered to.
correspona to reductions required by any future
regulations promulgated by the District.
ii. The baseline profile will be permanently lowerea oy the.
difference between baseline emissions and RACT for any
source under the cap which is shut down or removed from
the cap. The baseline period used for determination of
emissions shall be the same as was used in the evaluation
of Permit 26786 (baseline operations shall be as
I in Shell' s Application 26786) unless emissions _I
at the affected source were increased as a result of this
or other permits; in which case the baseline period sham
be the two year period immediately preceding the slate of
application.
qD
6 r.e L may r, iz,�. u Q.i I Czi V =.it I z Q L 6
s imp( lowering
tne nyurocaroon 1p. 'Vae hydrocarz),in cap
does not meet the requirement or 2-2.-606_1 (0) . Tne
calculation of baseline for the purposes of banking or
new source review for any nyorocarcon source under the
cap snall be determined pursuant to the provisions of
Regulation 2-2-606 . 2 or the equivalent regulation in
effect at tne time of application.
iv. If a new source is added to nose under the cap, the
profile will be permanently lowered by the amount of
excess offsets required for onsite ottsets under tne
prevailing NSR rule (i.e. applicable offset ratios and
RACT adjustments) ; the entire emission increase shall be
offset by actual emission reductions from specific
identifiable sources subject to enforceable permit
conditions.
V. If a source already under the cap is modified, the
profile will be permanently lowered by the amount of
excess o'ffsets required for onsite offsets under the
prevailing NSR rule (i. e. applicable offset ratios and
AACT adjustments) ; the entire emission increase shall be
offset by actual emission reductions from specific
sources ources subject to eniorceabie permit
conditions.
C. ' cion-compliance will result in the following actions:
Number of Non-complying days Action
for any one pollutant
(per 365 day period)
More than 0 Shell shall notify the District witnin 15
working days of any non-complying day. One
V/N will be issued per day of non-
compliance for violation of permit condi-
tions.
vlore than 5 if the previous 365 days include more than
5 non-complying days, the refinery opera-
tions shall be limited in the ways iisted
below. Shell may submit alternative ac-
tions providing equivalent corrective con-
trol for consideration by the APCO. Upon
APCU approval, the alternative actions may
replace the limitations listed below.
These limitations shall remain in effect
following any day of non-compliance until
Snell has demonstrated compliance for three
consecutive days.
i. The refinery shall not process more than
124,000 barrels of crude oil per stream
day.
ii. The refinery shall not process more than
22,000 barrels of Flexicpkec' feed pit
stream day.
iii. The refinery snail not process more than
r 65,000 barrels of catalytic cracker feea
per stream day.
iv. Total fuel usage at sources unser the cap
shall not exceea 14730 NLFE (Net Liquid
Fuel Equivalent) barrels per stream day.
V. Total sulfur content of liquid fuels snail
not exceea 1.0 tons/daya. In the event that
the Flexicoker Unit is down, the total
sulfur content of liquid fuels may not
exceed 1.3 tons/day.
� vi. Large cargo vessels (170 MDWr or greater)
shall not be offloaded while any other
vessel is being off loadea.
Violation of this condition may result in
the revocation of all permits.
li. Storage Conditions
1. For Tanks T-14, .T-20 , T-1139 , T-1140 , T-1141, T-483 , T-484 , T-
530 , T-531, T-532, T-5381 T-1330 , T-1331, T-1332, T-1333 , T-
1336 , T-1337 :
a) Liquid witz a true vapor pressure of 1.5 psia or greater
snail not be stored in more than 12 of the above tanks at
any one time.
b) The above tanks will be controlled by a vapor recovery
system, or equivalent control equipment, capable of
controling nydrocarbon emissions to Icess than 8 lb/day.
2 . Liquid with a true vapor pressure of 1.5 ps_4a cc greater snail
not be storea in Tank 1076 .
3 . Coke Storage Sins and Purge Silos shall be ,Vontrolled by _
oaghouses capable of reducing mass emissions of particulate
mat`.e= . by a minimum of 994,
E. Fuel Conciticns
x
1. Sulfur content of any liquid fuel burned in furnaces subject
to the cap shall not exceed 0 .54 by weight.
2. While the refinery is processing more than 50 4 San Joaquin
Valley (SJV) crudes, the H2S , concentration of Flexigas shall
not exceed 80 ppmv on a aaily. average, nor 60 ppmv on an
annual average. At all other times, the H2S concentration of
the Flexigas shall not exceed 35 ppmv. If Shell can
aemonstrate. that the Stretford Unit cannot achieve the 35 ppmv
H S concentration on the Flexigas while processing less than
5�4 SJV crudes, Shell may apply to the APCO for re-evaluation _
and possible revision of this permit condition.
3. Sulfur content of fuel oil used by tankers larger than 170
biDWT will not exceed 0.54 (by weight) while discharging crude
oil at a rate greater than 35,000 Bbl/hr. .
q
F. Rep4Cting
1. Shell snall report the following an a monthly basis:
a. Daily compliance/non-compliance for each pollutant.
b. Daily total emissions for each potiutan t.
G. Records
1, Snell shall make available to the District, upon request, all
records relating to the operation of the equipment covered by
this permit.
r
Tabie I.
Units and Operations to be Includea in Audit
Ali refinery combustion devices (including flexigas burred in flares)
Uimersol Unit
Hydrogen Plants
Crude Units
FCC unit
Sulfur Plants and Tail Gas Units
oiharf Operations
Lightering and Ballasting while within District bounaaries
r
TABLIll,111.
SHELZ• BASELINE PROFIIWHYDROCARBOb EMISSIONS (L&Y)
No. of days pounds per day �f
1 13842.4
2 13688.8
3 12284.4
4 12114. 4 - -
5 11761.6
6 11591.2
7 11101.6
8 11024.8
9 10614.4
10 10552.0
11 10530.4
12 10477.6
13 _ 10446.4
14 10427.2
15 10141.6
16 9829.6
17 9673.6
18 9416.8
19 8600.8
20- 8598. 4
21 8548.0
22 8543.2
23 8320.0
24 8226.4
25 8185.6
26 8140.0
27 8089.6
28 7679.2
29 7638.4 -
30 7595.2
31 7549.6
32 7429.6
33 7391.2
34 7146.4
35 6860.8
36 6812.8
37 6752.8
38 6671.2
39 6620.8
40 6.479.2
41 6385.6
42 6313.6
43 5857.6
44 5855.2
45 5831.2
46 . 5754.4
47 5749.6
48 5744.8
49 to. 50 5740.0
51 to 52 5732.8 ,L
;:, Z
' , ' • � Page•
TABLE III. .
No. of days pounds per day
106 2020.0
107 2015.2
108 - 2008.0
i09 1969. 6
110 1950. 4
111 1945.6
lit 1933.6
113 1928.8
114 to 115 z- 1926.4
116 1919.2
117 1912.0
118 to li9', 1909. 6
120 to 11,11- 1907.2
122 1904.8
123 1895.2
124 1883.2
125 1880.8
126 1878.4
127 1871.2
128 1868.8
129 to 1313 1861.6
132 to 1337. 1859. 2
134 to 1351 1856.8
136 to 139 1854.4
140 1852. 0
141 1842. 4
142 to 144 1840. 0
145 to 146 2 1837. 6 -
147 to 148 2 1835.2
149 to 150 'y 1832.8
151 1830.4
152 1828.0
153 1823.2
154 to 157 '� 1820.8
158 to 159 Z 1818.4
160 to 162 '3 1816.0
163 to 164 Z 1813.6
165 to 1661 1811.2
167 to 1695 1808.8
170 1804.0
171 to 172 L 1801.6
173 1787.2
174 to 1751, 1782.4
176 1777.6
177 to 179 3 1765.6
180 1763.2
181 1760.8
182 1753.6
183 1751.2
184 1748.8
�Z
• � Page
TABLE III.
No. of days pounds per day I
185 to 1873 1746. 4
188 to 1903 1744.0 2i *�t714lt L3}
192 1741.6
1.92 to 19514 1739.2
195 to 197. 7- 1734.4
198 to 20811 1732.0
209 to 214 (o 1729.6
215 to 22511 1727.2
226 to 233 8 1724.8
234 to 24512. 1722.4
246 to 255 (o 1720.0
256 to 267 11 1717.6
26a to 302 3'{ 1715.2
302 to 311 (o 1712.8
312 to 325 ti-{ 1710.4
326 to 365 ` 0 1708.0
.�
t Emission tactors -- Wharf operations
Material Emission Factor, lb/1000 gal ' q0
Finished Gasolines 1.4
Light Gasoline Components
Alkylate 1.4
HT C5/100. St Run 1.4
C5/240 Cat Crk 1.4
CS/180 Hydrocrackate 1.4
Dis• Light Naphtha 1.4
Heavy Gasoiine Components
ReFormate, 1.4 O��
240/450 Cat Crk 1.4
Dist Heavy Naphtha 1.4
Cat Reformer Feed 1.4
Shell Je►t A .05
Shell Mineral Spirits .05
DSU Mineral spirits .05
Shell 1300 Solvent .05 �--
Crudes
oc
Alaskan North Slope 1.7
Labuan _ 1.7
• alb �� n C--�L�`' •` ��'
t ..i
Ile—
. othe s —I.7 �L
Heavy Feed Stocks ' t
Coker Heavy Gas Oil .016
Cat Cracker Feed .005
Vacuum Flashed Dist .005
Heavy Flashed Dist .005
Coker Feed .016
Fuel Oils '
Shell Dieseline .005 -We
Marine Diesel .005
Snell Thin Fuel Oil 30 .005
Shell Thin Fuel Oil 40 .005t
Snell Thin Fuel Oil 60 .005
Shell Thin Fuel. Oil 80 .005 — 1
Shell Thin Fuel Oil 100 .005
Unfin Cracked Gas Oil .002 ( jl .•„
Shell Light Fuel Oil .002 / C
Shell Steam Ship Fuel Oil .002
Shell Marine International Grade .002
Shell Industrial Fuel Oil .002
Shell Thin P.O. 120 .002
Shell Thin F.O. 150 .002 � �L►"9t���.J
Shell Thin F.O. 180 .002
Shell Thin F.O. 240 .002
Shell Thin F.O. 280 .002
Shell Thin F.O. 320 .002
Shell Thin F.O. 380 002 rr
Shell Thin F.O. MV 240/11.4 .002 - QQQ
J
,IJP ,
M �
v�;
Shell Thin F.O. it 280/11.4 .00 �
Shell Thin F.O. 320/11.4 .0016
• . •Snell Thin F.O. KV 3130/11.4 .002
lSisc Cutter Stock .002
Shell Special Industrial Fuel Oil .002
Shell UMF Grade C .002
Shell Med. Treating Aromatic Oil .002
Shellflex 371 .002
Lube Oils
HVI 100 Neut TQ .00004
HVI 250 Neut MQ .00004
HVI 65/210 .00004
MVI 150 art Stk .00004
HVI 100 Neut My .00004
LVI 60 Neut MQ .00Q04
LVI 100 Neut MQ .00004
100 Base Stk 80 UR .00004
LVI 450 Neut .00004
LVI 90/210 Neut .00004
60 Spray Base .00004
100 Spray Base 92 UR .00004
MVI 400 Neut .00004
MVI 80/210 Neut RQ .00004
Diala A .00004
Diala AX .00004
35 Base Stock .00004
Asphalts
AR 2000 Asphalt .00004
AR 4000 Asphalt .00004
AR 8000 Asphalt .00004
WOR Flex .00004
80 Vis Blend Stock .00004
• Shipping Combustion Eaission Factors
(W1000 gallon fuel) 0 '
Organic S02 NOx Particulate
0.54 2.04 0.54 2.04
S teamsn ps
do'el ng 3.10 79.77 319.08 20.90 7.03 18.99
other 3.10 79.77 319.08 48.21 7.03 18.99
Internal Coombustion Engines
Res—"a a1 32 . 80 78.78 315.11 339 .60 35.00 35.00
marine Uiesel 32.80 70 .69 -- 367.00 20 .00 --
Diesel (Tugs) 12.99 38.97 -- 57.1.22 24.98 --
Shipping Puel Combustion Rates .
snip Fuei Combustion Rate (gal/hr)
Size Manuevering Hoteling Cargo Discharge Rate (bbl/hr)
3000 7500 11000 20000 50000 85000
Steamshios
30 MDWT Residual 304 39 147 294
45 MDWT Residual 417 47 184 504
60 Mi3WT Residual 567 76 631
70 MDWT Residual 666 93 650
200 MDWT Residual 1057 143 1000 1188 1656
Motorships
30 MDWT Residual 84 147 294 _
uiesel 420 42 42 42
70 MDWT Residual 84 650
Diesel 420 42 42
150 MDWTT Residual 84 759 898
Diesel 588 42 42 42
120/135 Residual 84 759 898
Diesel 588 42 42 42
Tuq s
Diesel 30
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1977
TANKER TRIPS NET AGENT
PERRYVILLE 10666 Thornley & Pitt
12/30 LA
12/15 C C
12/18 PORTLAND C
9/18 LA C
9/4 LA C
8/27 LA C
8/14 LA C
7/9 LA LA
7/4 ANAC C
6/24 WILM C
6/17 PAC NW LA
5/19 LA LA
4/18 ANAC LA
3/30 WILM ANAC
3/22 LA ANAC
AUSTIN 11524 O.F.W.T.A.
12/26 WILM LA
11/10 WILM WILM
11/3 PORTLAND WILM
10/8 WILM HAWAII
10/2 WILM LA
9/26 WILBRIDGE WILMINGTON
9/20 PORTLAND WILBRIDGE
7/27 LA HAWAII
7/22 LA WILM
5/10 PAC NW HAWAII
3/26 LA WILM
1/3 WILM WILBRIDGE
PECOS 10643 Shell
12/25 C
12/19 PORTLAND C
12/2 LA C
11/24 LA C
11/9 LONGVIEW C
11/2 C C
10/24 LA C
10/18 C C
9/24 LA C
• r l , qo
Taffi= TRIPS NET AGENT -
_PECOS (cont. )
9/20 PORTLAND WILBRIDGE
9/13 PAC NW C
9/1 C LA
8/23 LA C
8/19 HOQUTAM C
7/29 SEATTLE C
7/21 LA LONGVIEW
7/4 _ C C
6/27 LA COLUMBIA RIVER
5/7 C C
4/8 WILM C
3/26 PAC NW C
3/3 LA PORTLAND
2/15 LA PORTLAND
2/9 VANC WN C
1/22 PORTLAND PORTLAND.
1/14 LA C
1/2 C C
HOUSTON 11178 Werner
12/20 WILM WILM
12/15 WILM WILM
11/29 PORTLAND C
11/21 LA LONGVIEW
11/16 WILM LA
11/3 WILM ANAC
10/16 WILM ANAC
9/23 "ANAL DRIFT RIVER
9/10 WILM WILM
9/4 WILM WILM
8/30 WILM WILM
.7/26 WILM WILK
7/13 LA PAC NW
6/16 WILM PT SAN LUIS
6/12 WILM WILM
5/16 LA LA
5/6 WILM WILM
4/24 WILM PAC NW
3/11 WILM ANAC
2/25 WILM ANAC
2/17 WILM WILM
2/1 WILM WILM
1/6 WILM ANAC
TANKER TRIPS NET AGENT
_DOSINA 25066 WMS. DIMOND
11/28 SAN CLEM SAN CLEM
10/15 SAN CLEM SAN CLEM
9/21 SAN CLEM SAN CLEM
9/8 SAN CLEM . SAN CLEM
8/23 SAN CLEM SAN CLEM
8/11 SAN CLEM SAN CLEM
6/26 SAN CLEM SAN CLEM
6/18 SAN CLEM SAN CLEM
5/24 SAN CLEM SAN CLEM
5/1 SAN CLEM LA
4/21 SAN CLEM SAN CLEM
3/5 ANAC LA
2/12 SAN CLEM SAN CLEM
1/10 SAN CLEM SAN CLEM
1/3 SAN CLEM SAN CLEM
GRAFTON
11/8 ECUADOR VBC 27004 O.F.W.T.A.
JUDITH PROSPERITY 35976 O.F.W.T.A.
10/30 ANAC SINGAPORE
COASTAL CAL 27004 net O.F.W.T.A.
10/26 C C
TEXACO GEORGIA 7943 net Texaco
8/8 LB C
EAGLE LEADER 16420 net Thornley & Pitt
7/16 MOSS LNDG MOSS LNDG
6/25 MOSS LNDG MOSS LNDG
STAR CRESENT (tug) Olson Towing
7/10 C
5/13 C C (tug w/tow)
MAJESTIC 22515 O.F.W.T.A.
6/9 ANAC MALAYSIA
ATLANTIC TRADER 8959 Hendy
3/16 C C
CHEVRON COLORADO 13700 Chevron
1/15 WILBRIDGE ALASKA
Report No. SR93-02-01
Review of Air Quality Issues
Related to the Shell Oil Company
Marine Vapor Recovery Unit
(Use Permit #91-2; Design Review #91-18)
prepared for:
City of Martinez
Community Development Department
February 19, 1993
prepared by:
Sierra Research, Inc.
1521 I Street
Sacramento, CA 95814 .
(916) 444-6666
CT
CoNU -X) TJ 1� 1 t� -.
Hydrocarbon Emissions Associated wiUJA 5th argo Loading Operations q0
Hydrocarbon emissions associated with cargo loading operations will be
reduced as a result of the operation of the marine vapor recovery unit.
District Regulation 8, Rule 44, requires that the vapor recovery unit
reduce cargo loading emissions by at least 95%, or to a level not
greater than 2.0 pounds of emissions per 1,000 barrels of product
loaded. By comparison, loading emissions without vapor recovery range
from <O.l to over 100 lbs/1000 barrels of product loaded. Sierra
Research estimates that the installation and operation of the marine
vapor recovery unit reduces hydrocarbon emissions from product loading
at the Shell wharf by about 200 tons per year. The remaining 5% of
hydrocarbon emissions associated with cargo loading operations are those
that exit the thermal oxidizer, and are discussed in the earlier
paragraph regarding combustion emissions.
tIndirect Impacts on Refinery and Wharf Operations
Since portions of the Shell Martinez Manufacturing Complex are operating
under an emissions profile (or "cap") permit, a reduction in cargo
loading emissions could theoretically result in indirect increases in
emissions by allowing for increased marine loading activities. However,
the BAAQMD has reduced the allowable hydrocarbon emissions under Shell's
emissions profiles by an amount calculated based on the amount of
loading activity that occurred during the 1977 wharf baseline period.
The details of the calculated reduction are included in Shell's
September 26 , 1991 letter to the BAAQMD. On an annual basis, Shell's
—_� emissions profile was reduced by 155 tons/year under this adjustment:
from 563 tons/year to 408 tons/year.
A review of the procedures used to make this correction suggested that
an error exists. Specifically, there were 18 days during the wharf
baseline period when ballast water was taken onto vessels and placed in
holds that had previously contained volatile cargos. This operation can
generate emissions in much the same way that loading gasoline or crude
oil pushes vapors present in the hold (the "arrival component") into the
air. However, the emissions profile was not adjusted to reflect the
fact that these emissions are subject to control under the BAAQMD's.
marine vapor recovery rule. An initial recalculation of the wharf
baseline indicates that it should have been reduced by approximately 225
I' tons/year, rather than the 155 tons/year adjustment which was actually
made.
In a letter dated February 17, 1993, the BAAQMD corrected this initial
error, and the Shell baseline has now been reduced by 226 tons/year.
The corrected baseline, and a verification that emissions during the
period when the error was in effect did not exceed the correct,
allowable limits, are shown in Figure 4 above.
i Since the emissions profile has been adjusted to reflect the effect of
the installation of the marine vapor recovery system, no change in
• actual loading volumes is anticipated as a result of operation of the
marine vapor recovery unit. While loading operations may increase or
decrease in the future, and while the mix of products being loaded may
3/19 /50
SMELL OIL COMPANY
ENGINEERING EVALUATION
APPLICATION #26786
I. PROJECT SCOPE
Shell Oil Company has applied for an authority to construct
in order that they can make major changes to their Martinez
Refinery. The proposed modifications will not increase the
overall capacity of the refinery, which is presently 128,000
barrels/calendar day (BBL/CD) . However, these modifications
Will significantly increase crude distilling capacity, resul-
ting in increased gasoline and aircraft turbine fuel produc-
tion and a corresponding decrease in heavy fuel oil output.
Shell states that this modernization project is necessary to
enable thew to process heavier, high-sulfur domestic crudes
( primarily Californian and Alaskan) , thus minimizing their
dependance on foreign crudes.
The proposed new process units and the modifications to exis-_
ting process units are listed below:
A. New Process Units (new process heaters in parentheses)
1. Flex icoker ( steam superheater and pitch !water)
2. Dimerization Unit
3. Hydrogen Plant ( steam methane reformer)
4. Sulfur Recovery (Claus/SCOT plant incinerator)
S . C3/C4 Splitter
6 . Cooling Tower , 33,000 gal/min.
B. Modified Process Units (major modifications) in parentheses)
1. Crude Distillation (new crude furnace and desalter)
2. Catalytic Cracking Gas Plant (modification of main
fractionator)
3. Hydrocracking (additional heat exchangers and hydraulic
debottleneck)
4 . Catalytic Reforming (new inter-reactor heater)
5. Straight Run Hydrotreaters
a. Naphtha Hydrotreater (pump and three heat
exchangers)
b. Gas Oil Hydrotreater (pump and heat exchanger)
6. Catalytic Cracking Feed Hydrotreater ( furnace modified
to burn low-BTU flexicoker gas)
7. Cat Gasoline Hydrotreater (operational changes and
increased heat exchange) .
e.
0
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8. Distillates Saturation Unit (additional heat exchanger)
9 . Wharf Revision (new unloading facilities for 189, 000
DWT tankers)
For additional details of these new and modified units , including
process descriptions and flow diagrams , please refer to Volumes
I and II of Shell ' s application.
In addition , new tankage will be constructed for the storage
of crude oil -(315;000 `BBL), ' gasoline (961 ,000 BBL) and inter-
mediate feedstocks (856, 000 BBL) . Shell will also control
twelve existing storage tanks with a new vapor recovery
system in order to provide hydrocarbon emission reductions.
The Bay Area Air Quality Management District has imposed a
comprehensive list of conditions to assure compliancy
with all District regulations including:
1 . Best Available Control Technology ( BACT) requirements of
Regulation 2, Rule 2, Section 301 . 2.
2. New Plant Performance and Emission Requirements of
Regulation 10, Rules 8 and 9.
3. New Source Review (HSR) requirements of Section 1309 of
Regulation 2 (old codification) . Tradeoffs will be required
for non-methane hydrocarbons (HC) , sulfur oxides (SOX) and
nitrogen oxides (NOX) , since increases of greater than 250 lb/
day of each pollutant will occur due to worst-day changes
in marine operations.
}' II. BEST AVAILABLE CONTROL TECHNOLOGY (BACT)
Shell will comply with the BACT requirements of Regulation 2,
Rule 2, Section 301 . 2 as follows :
A. Process Heaters - Shell will construct five new process
heaters as part of the refinery modification.
1. The new flexicoker pitch heater will be equipped with
a low-NOx burner approved by the APCO as BACT. Shell
Will supply the necessary documentation before the
permit to operate is granted .
d
2. The Steam Methane Reformer (SMR) furnace in the new
hydrogen plant will be equipped to burn refinery gas
and low-BTU flexicoker gas. These SMR furnaces by design
are inherently low NOx emitters. Source tests by the
District and Shell indicate an emission factor of 0.06 "
lb/MMBTU while burning refinery gas. An even lower
factor should be achieved when burning low-BTU flexico-
ker gas. This is considered BACT. (note : This unit
will not be capable of burning fuel oil) .
, a
3. Three new process heaters will be equipped with tri-
fuel burners capable of burning fuel oil , refinery gas
and low-BTU flexicoker gas. These heaters are listed
below:
a . Crude Unit Feed Heater
b. Catalytic Reformer Inter Heater #1
c. Flexicoker Steam Super Heater .
The furnaces will be low NOx emitters when firing on
low-BTU flexicoker gas. Shell will document to the
APCO that tri-fuel burners are not currently available
that are designed for low NOx generation while firing
fuel oil and refinery gas. Since. the primary fuel for
each of these heaters 070%) will be low-BTU gas , these
tri-fuel burners will be accepted as BACT provided a
low-NOx design is not available.
B. Flexicoker - The flexicoker gasifier will be vented to a
Stretford gas treating system capable of reducing the
H2S content of the gas by 99•,. The Stretford gas treater
is BACT.
C. Coke Storage Bins and Purge Silos - These sources will be
controlled by baghouses capable of reducing mass emissions
of particulate matter by a minimum of 991.
D. Claus/SCOT Sulfur Plant - The new sulfur plant will be a
three-stage clans plant with a SCOT tail-gas treater .
The SCOT Unit will provide overall sulfur removal of
>99% and will assure compliance .with the S02 limits of
Regulation 9 , Rule 1 , Section 306. 2 (i .e . 250 ppm( v) and
4 lb/ton) . The SCOT unit as proposed by Shell is consi-
dered BACT.
E. Storage _Tanks -- Shell will equip all new tanks storing ��---
organic liquids with true 'vapor -pressures >1.5 psis' with
either-�floating "roofs with approved double seals or with
a vapor recovery system demonstrated to provide equivalent
or greater control. This is BACT for tankage.
F. Pumps and Compressors - Al] npw pumps and compressors will
be equipped with mechanical seals or mechanical .packing de-
signed to minimize fugitive emissions of organic gases.
This is BACT.
G. Flares and Marine Vessels - There is no BACT for flares or
marine vessels.
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III. NEW PLANT PERFORMANCE AND EMISSION REQUIREMENTS
Shell will comply with the New Plant Performance and Emission
Requirements of Regulation 10, Rules 8 and 9 as follows :
A. Rule 8 requires that the H2S content of fuel gas
burned in any refinery combustion device not exceed
0. 10 grains/SDCF ( 159 ppm H2S by volume hourly average) .
The three year ( 1976-1978) average H2S content of Shell's
refinery make gas was approximately 60 ppm (<0.04 grains/SDCF)
which -indicates compliance should be attainable with good
maintenance of the existing gas treaters. The anticipated H2S
content of the low-BTU flexicoker gas ( flexigas) will be.
approximately 17 ppm (0. 01 grains/SDCF) or one tenth of the
standard . In order to show compliance with this requirement,
Shell will install and maintain continuous H2S monitors in both
the existing fuel gas system and the new flexigas distribution
system.
B. Rule 9 requires that petroleum liquid with a true
vapor pressure equal toor greater than 1. 5 psia
be stored in a vessel equipped with a floating
roof, a vapor recovery system , or their equivalents .
Shell will comply with this standard by: 1 . equipping
their new crude oil storage tank with a floating roof
with double seals. 2. controlling the two new
naphtha tanks and the three new gasoline tanks with a
vapor recovery system.
C. Shell ' s catalyst regenerator and CO boilers serving the
catalytic cracking unit (CCU) are in compliance with
District regulations which are more restrictive than the
New Plant Performance and Emission Requirements of Regu-
lation 10, Rule R .
IV. OFFSETS (NEW SOURCE -REVIEW)
"Worst-day" emission increases of particulates , SOx , NOx and
hydrocarbons will exceed 250 lb. Therefore, offsets will be
required per Section 1309 (c) of Regulation 2 (old codification) .
The increases are for the most part due to maneuvering , and
unloading , of the 120 to 189,000 dead weight ton vessels
which will visit Shell' s wharf in the future. Use of these
larger vessels will however , reduce the total number of
vessels visiting the wharf from 441 to 170 per year . This
will result in annual emission reductions of particulate ,
SOx and NOx . Only hydrocarbon emissions will increase , due
to increased ship loading of gasoline . Th13 .increa3e will
be offset by additional control of hydrocarbon emissions from
refinery storage tanks .
01 0
Shell elected to calculate baseline refinery emissions on an
annual average basis. Therefore, daily emission averages have
been calculated for the three year period 1976 through 1978
using fuel usage data , source test results, tank storage infor-
mation and approved emission factors. The wharf emission
baseline was established using a summary of marine operations
for the 1977 calendar year .
Shell will offset the worst-day increases with annual average
emission reductions on a 2-lb to 1-lb basis.
See Tables 1 and 2 for emission and offset summaries.
The major emission reductions will be provided by the
following measures:
A. Sulfur Oxides (SOX)
1 . Improved hydrotreating of catalytic cracker feed is
expected to decrease S02 emissions from the cat
cracker regenerator by 25%, or approximately 550
ton/yr .
2. Shell will discontinue burning high-sulfur residual
fuel oil in the process heaters and boilers. This
fuel will be replaced by 0. 12', sulfur fuel oil and
by low-BTU flexicoker gas .
3. Permanent shutdown of the lube oil Compounding Unit
will reduce fuel requirements equivalent to a 44 _
ton/yr reduction of SC2.
4. Overall SOX emissions from wharf operations will be
reduced 127 ton/yr due to decreased vessel traffic
and use of 0. 55 Sulfur fuel oil during discharging
of large tankers (greater than 170 MDWT) .
Note : The District has not given Shell offset credit for
anticipated SOX emission reductions from the two
existing sulfur plants , since these reductions are
mandated by Regulation 9, Rule 1 , Section 306.2.
However, control of these sources will reduce total
refinery emissions of SOX by approximately 4, 000 Ton/yr .
B. Nitrogen Oxides (NOx)
1. Combustion of low-BTU flexicoker gas will provide
a very low NOx generating fuel , thus offsetting
in part NOx emissions which would result from the
combustion of conventional fuels.
2. Computer control of process heaters will assure low
excess oxygen , resulting in low NOx eneration . Shell
will verity by source testing the anticipated NOx
reduction of 66 ton/yr .
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3. Permanent shutdown of the lube oil Compounding Unit
will reduce fuel requirements equivalent to a 53
ton/yr reduction of NOx .
4. Overall NOx. emissions from wharf operations will be
reduced 5 ton/yr due to decreased vessel traffic .
C. Hydrocarbons (HC)
Shell will offset increased HC emissions from wharf and
process units by using vapor recovery or double seals
to control new and existing tankage to a greater degree
than required by District regulations. This net offset
is equivalent to 299 ton/yr .
D. Particulate Matter (TSP)
1 . Combustion of low-BTU flexicoker gas will provide low
TSP emissions compared to all other fuels .
2. Combustion :of low-sulfur fuel oil in place of heavy
residual fuel oil will also result in reduced par-
ticulate emissions. The net reduction due to items
1 and 2 will be approximately 12 ton/yr .
3. Decreased vessel traffic will reduce particulate emis-
sions from wharf operations by u ton/yr .
It is the opinion of the District staff that the emission
reductions provided by Shell Oil Company will result _
in a net air quality benefit in the area affected by
the emissions from the stationary source.
V. RECOMMENDATION
Based on the engineering evaluation of Shell ' s application ,
it is recommended that an Authority to Construct be granted
subject to the conditions listed in the following section .
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DRAFT 3/17/50
VI . PERMIT CONDITIONS
The following are the proposed conditions for the permit
to operate. ,
The purpose of these conditions is to guarantee that:
1 . a net air quality benefit is achieved .
2. all emission reductions required for offsets
are 'prov id ed .
A. Refinery Conditions
1 . Total fuel usage shall not exceed 14730 NLFE {'tet
Liquid Fuel Equivalent) Barrels/Calendar Day. One
NLFE Barrel has a heating value of 5.46 4M BTU. A
calendar day basis is an average value determined
by dividing the yearly total by 365. ) This total
shall include all natural gas , refinery gas , propane ,
flexigas , flexicoker coke , cat cracker low-BTU gas
(CO) , cat cracker coke and low-sulfur fuel oil burned
in refinery process units , heaters and boilers. Shell
will report daily usage of each type of fuel to the
District on a monthly basis.
2. Fuel oil usage and allowable sulfur content.
a . Total low-sulfur liquid fuel used in refinery
process heaters and boilers shall not exceed 4000
NLFE Barrels/Calendar Day or 5000 NLFE Barrels/
Stream Day. A stream day is defined as the actusl
daily rate.
b . If liquid fuel usage is between 0 and 1 ,000 N'LFr_ Bar-
rels/Calendar Day the allowable annual average sulfur
content of this fuel is not to exceed 0.43: by weight .
If liquid fuel usage is between 1 ,000 and 4 ,000 NLFE
Barrels/Calendar Day the allowable annual average
• sulfur content of this fuel is to be found using the
following equation:
Weight 1 Sulfur a (4$0)/(NLFE Barrels/Calendar Day) �
If the emissions of sulfur dioxide from the catalytic
cracking unit ( CCU) are shown to be less than 4 .43
Tons/Stream Day, Shell may request the APCO to reeva-
luate the above equation. This condition is dependent -
upon the installation of a District approved CEM monitor
for S02 in the No . 3 CO Boiler Stack.
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7
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c . In the event that the Flexicoker Unite is down, liqu
fuel consumption can be increased to a maximum of
8,000 NLFE Barrels/Stream Day. If liquid fuel con-
sumption is between 4 ,000 and 59000 NLFE Barrels/Str
day during Flexicoker - shut down , the maximum content
this fuel shall not exceed 0. 121 by weight. If liqui
fuel consumption exceeds 5,000 NLFE Barrels/Stream Da
during Flexicoker shut down , the -maximum sulfur conte
of this liquid fuel shall not exceed O, /S by weight.
Shell shall determine the average sulfur content of
this liquid fuel on a weekly basis unless consumption
exceeds 4,000 NLFE Sarrels/Stream Day in which case
sulfur content will be determined daily. Shell shall
report these data to the District on a monthly basis.
T`i: net 3ul4'ur content of the coke burned in the
regenerator of the Catalytic Cracking Unit (CCU) shall
not exceed an annual average of 0. 38% by weight. Shell
will draw equal size spent and regenerated catalyst
samples from the CCU daily and analyze a weekly composite
of each for sulfur and coke content. The net sulfur con-
tent of the coke will be determined from these samples by
a method approved by the BAAQMD. Shell shall report weekly
net coke yield and wee'tly net sulfur content of the coke
burned in the regenerator on a monthly basis.
4. Shell will install and -maintain continuous monitors
to measure H2S concentration in the flexigas system
and the refinery gas system. The annual average H2S
concentration shall not exceed 50 ppm for refinery
gas and 17 ppm for flexigas . The average daily H2S
concentration for each system will be reported to
the District on a monthly basis. In addition, Shell
V shall report hourly averages in order to show com-
pliance with the HSPS limit .
5. The computer control system for controlling furnace
combustion will be demonstrated to the satisfaction
of the APCO to be capable of achieving a fuel savings
of at least 200 KLFE Barrels/Calendar Day before the
new process units covered by this permit shall be star-
ted up .
6. Shell will determine base-line HOx emissions from all
furnaces which will be modified to fire flexigas. All
testing may be observed as required for approval by a
representative of the BAAQMD.
7. After start-up of the Flexicoker , Shell will determine
NOx emissions from new and -modified furnaces firing
flexigas. All testing may be observed as required for
approval by a representative of the BAAQMD.
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8. Liquid raw material intake (crude oil plus other petroleum
liquids) is not to exceed 1260000 Barrels/Calendar Day.
Shell will report to the District the total intake over
the wharf and through the pipeline on a monthly basis.
9. The Flexicoker Pitch Heater will be equipped with a low-
NOx burner approved by the APCO. See BACT discussion
Section II.A.3 of the permit evaluation report.
10. Catalytic cracking capa_ity shall not exceed $5,000 Barrels/
Stream. Day, or emissions equivalent to 55,000 Barrels/Stream
Day.
11 . Flexicoker capacity shall not exceed 22,000 Barrels/
Stream Day, or emis3i013 equivalent to 22,000 Barrels/
Stre.3m Day.
12. Crude distillation shall not exceed 124 ,000 Barrels!
Stream Day.
13 . Within 90 days of startup of the ,SCOT unit on the exis-
ting sulfur plants , Shell will demonstrate that the
required CO emission reduction is being achieved . All
testin& may be observed as required for approval by a
representative of the BAAOMD.
14 . Mechanical seals will be installed on all new rotary
pumps and compressors. Mechanical packing of best avail-
able design will be installed in new reciprocating
pumps and compressors.
15 . The new process heaters will be limited to a maximum
, total heat release of 6q9 MM BTU/HR. Shell will advise
the District if the maximum heat release design values
for the new heaters listed below are changed during the
authority to construct period.
Maximum Heat Release
(MM BTU/HR)
a. Crude Unit Feed Heater 150
b. Catalytic Reformer Inter-4eater 90
c. SMR 2 Rx Heater 374
d. Flexicoker Steam Superheater 75
e. Flexicoker Pitch Heater 10
Total 699
9. Tankage Conditions _
1 . True vapor pressure of all liquids stored in the
following tanks : T-14 , T-20, T-1139, T-1140 A T-1141
2. The following existing tanks will be controlled by a
vapor recovery system capable of controlling hydro-
carbon emissions to <8 Ib/day/tank: T-483 , T-4R40
t-53G, T-5319 T-532, T-538, T-14, T-20, T-1139,
T-1140, T-1141 , T-11.
3. The following new tanks will be controlled by 3 vapor
recovery sytem capable of controlling hydrocarbon
emission to <8 lb/day/tank:
a . * 2 New Rap tha Tanks ( 135,0}0 barrels each)
b. 1 New Meavy Cat Gasoline Tank ( 135,000 barrels)
c. 2 New Gasoline Tanks ( 195,000 barrels ea.h)
4 . Tank T-1076 is to remain in ATF ( aircraft turbine
fuel) service and will be subject to the double seal
requirements of the District..
C. Marine Operations Conditions
1 . The following marine operations shall be livited to
those volumes listed in Tables 3 and 4 - Wharf/Volume I
of the Permit Application, namely:
a . Gasoline loading 10, 950 M barrels/year
b . Turbine fuel loading 1 , 925 M barrels/year
c . Ballast for crude tankers
without segrated ballast 649 y barrels/year
d . Lightering of crude within
S.F. Bay 1 , 099 M barrels/year
To provide for changing market needs and availability of
tankers for charter, the volumes of these operations :may
be interchanged on a hydrocarbon emission equivalent basis.
2. The total number of voyages for tankers delivering crude
and taking out products will be limited to the shipping
schedule as displayed in the Permit Aoplication-Wharf
Emissions - Table 3, namely:
Vessel Size
MDWT Type Voyages/Year
30/45/70 y 43
30/70 S 38
120/135/150 S&M 3
170/200 S 34
To provide flexibility to meet changing patterns of market _
requirements, crude supply, and availability of tankers for
charter, Shell may exchange tanker voyages according to the
following emission equivalency table (However , if vessel
1 substitutions result in additional emission profile excesses
/ not considered in the permit evaluation, Shell shall provide
TABLE 2: EMISSION OFFSET SUMMARY
REQUIRED OFFSETS W AVAILABLE OFFSETS EXCESS OFFSETS
POLLUTANT (2:1�RATIIOO) TON/YR TON/YR.
(2)
SULFUR OXIDES
sox 61.3 139.4 78 .1
PARTICULATE 5.5 18.4 12. 9
TSP
NITROGEN OXIDES . 11.7 161. 3 150
NOX
HYDROCARBONS 223 408 185
EC
CARBON MONOXIDE
CO NONE REQUIRED 153 153
a
1. Determined from emission profile excesses.
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