ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF ENFORCEMENT
EPA 330/2-76-016
REPORT ON
State Implementation Plan
Air Pollution Inspection
Texaco Incorporated
LOS ANGELES COUNTY, CALIFORNIA
NATIONAL ENFORCEMENT INVESTIGATIONS CENTER
DENVER, COLORADO
AND
REGION IX, SAN FRANCISCO, CALIFORNIA
FEBRUARY 1976
2 £2 \
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ENVIRONMENTAL PROTECTION AGENCY
Office of Enforcement
STATE IMPLEMENTATION PLAN
INSPECTION OF
TEXACO, INC.
Los Angeles Refinery
2101 E. Pacific Coast Highway
Wilmington, California 90744
213/835-8261
October 30-31, 1975
February 1976
NATIONAL ENFORCEMENT INVESTIGATIONS CENTER - Denver, Colorado
and
Region IX - San Francisco, California
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CONTENTS
Introduction 1
Process Description 3
Potential Sources of Air
Pollution Emissions and
Related Control Equipment .... 5
Emissions Data 14
Summary of Violations 18
Inspection Summary 19
Appendix
A NEIC Request Letter
B LAAPCD Rules
C Process Heater and Steam Boiler Listing
D Internal Combustion Engine Listing
E Storage Tank Listing
F Sulfur Plant Details
G Summary of Past Violations
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INTRODUCTION
Background
Texaco, Inc. operates an integrated petroleum refinery at this
location with a rated capacity of 11,900 m3 (75,000 bbl)/day. Major
products from this refinery include jet fuels, diesel fuels, gasoline,
fuel oils, and petroleum coke.
Texaco employs about 900 people at this refinery and operates
three 8-hour shifts, 7 days per week, year around.
On October 30-31, 1975, a process inspection was conducted at this
facility by NEIC personnel at the request of Region IX, EPA. The inspec-
tion was preceded by a letter to the Company [Appendix A] on September
8, 1975, announcing NEIC's intention to inspect the facility and request-
ing substantial amounts of process and source information.
During the inspection, an examination was made of the refining
equipment, potential air pollution sources, and air pollution control
equipment. The purpose of this inspection was to evaluate the degree
of compliance of this facility with the requirements of the Federally
approved State Implementation Plan as required by Section 110 of the
Clean Air Act, as amended.
Company personnel were cooperative throughout this inspection.
They supplied all information EPA requested during the inspection in-
terview or by subsequent letter.
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2
Inspection Participants
Mr. Lee Townsend-Asst. Plant Manger, Texaco
Mr. Herb Morgan-Supervisor, Air & Water Conservation, Texaco
Mr. Nathan L. Zlasney-Los Angeles County Air Pollution Control
District (LAAPCD)
Mr. Thomas P. Gallagher-USEPA, NEIC
Dr. Wayne C. Smith-USEPA, NEIC
Mr. David L. Brooman-USEPA, NEIC
Appl icable Regulations
The following rules contained in the Rules and Regulations of the
Los Angeles County Air Pollution Control District- (LAAPCD) [detailed in
Appendix B], are applicable to this facility:
Rule 50. Ringelmann Chart
Rule 51. Nuisance
Rule 52. Particulate Matter - Concentration
Rule 53. Sulfur Compounds - Concentration
Rule 53.2. Sulfur Recovery Units
Rule 54. Solid Particulate Matter - Weight
Rule 56. Storage of Petroleum Products
Rule 59. Effluent Oil/Water Separators
Rule 61. Organic Liquid Loading
Rule 62. Sulfur Content of Fuels
Rule 67. Fuel Burning Equipment
Rule 68.1. Fuel Burning Equipment - Combustion Contaminants
Rule 69. Vacuum Producing Devices or Systems
Rule 71. Carbon Monoxide
Rule 72. Pumps and Compressors
Rule 73. Safety Pressure Relief Valves
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3
PROCESS DESCRIPTION
Texaco processes California and Indonesian crude oils. All crude
is delivered to the refinery by pipeline. Primary products include
jet fuels, diesel fuels, gasoline, fuel oils, and petroleum coke.
Major processes at this refinery include crude desalting, atmos-
pheric distillation, vacuum distillation, delayed coking, catalytic
cracking, hydrotreating, hydrorefining, hydrocracking, alkylation,
catalytic reforming, hydrogen production and sulfur recovery. A very
simplified process block flow diagram for the facility is shown in
Figure 1. Table 1 lists the unit capacities for each of the major processes.
Table 1
PROCESSES AND RATED CAPACITIES
TEXACOj INC.j Los Angeles Refinery
Process
Total Rated
Capaci ty+
(m3/SD)++
(barrels/SD)++
Crude Distillation
ll,900/CD+t+
75,000/CD+++
Delayed Coking
7,600
48,000
1,500 m. tons/SD
1,650 tons/SD
Fluid Catalytic Cracking
4,500
28,000
Catalytic Reforming
5,600
35,000
Catalytic Hydrocracking
3,200
20,000
Catalytic Hydrorefining
2,100
13,000
Catalytic Hydrotreating
3,200
20,000
A1kylation
700
4,400
Sulfur Plant
tttt
t+tt
t All capacity values obtained from the Oil and Gas Journal> April 7} 1975.
++ SD = Stream Day; all values in table given as m /SD or barrels/SD
unless noted.
t+t CD = Calendar Day.
+tt+ Sulfur plant processes sour gases from other sources in addition to
Texaco. Texaco considers sulfur plant production figures confidential.
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Refinery Fuel Gas
Alkylate
Fuel Oil
r\
Gasoline
Distillates
Gasoline
o
c_>
Hydrogen
Plant
60
Alkylation
Catalytic
Reforming
Amine
Scrubbing
> a a
< a
Petroleum Coke
FIGURE 1
SIMPLIFIED PROCESS DIAGRAM - TEXACO, LOS ANGELES, CA, REFINERY
js.
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5
POTENTIAL SOURCES OF AIR POLLUTION EMISSIONS AND RELATED CONTROL EQUIPMENT
Although the Texaco refinery is a complex facility, there are rela-
tively few large discrete potential sources of air pollutant emissions.
With the exception of the fluid catalytic cracking (FCC) unit, the major
unit processes at the refinery are closed systems and release of ma-
terials to the atmosphere is discouraged because such releases would re-
sult in loss of product. The process heaters attendant to these units
constitute the main emissions sources.
There are also a large number of relatively small potential sources
of emissions related to the operation of the refinery. Such sources in-
clude leaks from valve seals, pump seals and pipe flanges, and evapora-
tive losses from storage tanks and process wastewater drains. Potential
sources of emissions and their related control equipment are discussed
below.
Process Heaters and Boilers
There are forty-seven process heaters and eighteen steam boilers
ranging in size from 1.2 x 10^ to 75.6 x 10^ kg cal (4.8 x 10^ to 300 x 10^
Btu)/hr heat input. A complete listing of these units is presented in
Appendix C.
Approximately half of these units use a mixture of refinery fuel gas
and natural gas as fuel. The remainder can be fueled with refinery fuel
gas, natural gas or fuel oil.
None of the process heaters or boilers are equipped with emission
control devices. The fresh feed heater at the delayed coker, the carbon
monoxide boiler, and the main steam boilers are equipped with stack gas
opacity detectors as noted in Appendix C.
Sulfur oxide emissions from these units are controlled by limiting
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6
the sulfur content of the fuels burned. Refinery gas must be desulfur-
3 ?
lzed to less than 1.1 gm/m (50 grains per 100 ft ) of sulfur compounds.
Fuel oil used in stationary fuel burning equipment is produced in the
refinery from low sulfur crude. Its sulfur content is less than 0.5% by
weight.
Internal Combustion Engines
Thirteen stationary internal combustion engines are in use at this
refinery to drive compressor units. All of the engines are fueled on
natural gas and have a total gas consumption of 3.7 x 104 m3 (1.32 x 106
ft ) per day. Appendix D summarizes the information available on these
engines. None of the units have emission control devices.
Storage Tanks
The 252 storage tanks at this facility, ranging in size from 0.5 to
22, 700 m (3 to 143,000 bbl), are used to store a wide variety of
materials. Since some of these compounds are volatile, hydrocarbon
vapors may escape from these tanks. Where this potential exists, the
materials are stored in specially constructed tanks such as pressure
vessels and floating roof tanks, or in tanks which are hard piped by
manifolds to the plant vapor recovery system.
The plant vapor recovery system consists of manifold piping and
compressors which maintain a vacuum on the tanks. Vapors collected by
this system are scrubbed in di-ethanolamine (DEA) scrubbers and then
introduced into the refinery fuel gas system.
A summary of the storage tanks at this refinery, their configu-
ration, and the materials stored within is presented in Appendix E.
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Blowdown Systems
The majority of the process units have emergency relief valves
which are connected to a manifolded header system. If it becomes neces-
sary to rapidly release quantities of liquids and gases from a unit,
they are routed by the mainfold system to liquid knock-out pots and
ultimately combusted in a flare.
There are three flares at this refinery. The two main flares, con-
nected to a common manifold system, are at the main refinery area. The
third flare is at the sulfur recovery plant.
The two main area flares are each 76.2 m (250 ft) high and have an
exit diameter of 0.8 in (2.5 ft). Each is rated at 448 x 106 kg cal
(1,778 x 10^ Btu)/hr and can handle 38 m. tons (38 long tons)/hr of
hydrocarbon materials. Both units are John Zink Smokeless field flares
(model STF-S-30) with three John Zink pilots, model STF-2, coupled with
John Zink flame front generators. These two flares receive blowdown
materials via the common manifold system from alkylation units 1 and 2,
catalytic reforming units 1, 2, and 3, the fluid catalytic cracking
unit, the hydrocracker unit, hydrotreating units 1, 2 and 3, the hydrogen
generation unit, the gas treating unit, and the delayed coking units.
With the exception of the delayed coking units, gaseous blowdowns from
these operations occur intermittently on an as needed basis. Blowdown
from the delayed coker is continuous.
The flare at the sulfur recovery plant is a John Zink smokeless
field flare (model STF-S-8) with three John Zink STF-2 pilots coupled to
a John Zink flame front generator. It is 15.2 m (50 ft) high and
has an exit diameter of 0.2 m (0.67 ft). It has a rated capacity of
148 x 10^ kg cal (586 x 10^ Btu)/hr and can handle 12.5 m. tons
(12.5 long tons)/hr of materials. It receives off-gases from the
sour water stripper, hydrocarbon flash drums, and rich amine surge
tanks located at the sulfur recovery plant.
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8
Texaco uses closed circuit TV cameras to monitor the flare operations.
Steam rate to the flares is adjusted manually by the operators while
they observe the flare on the TV to maintain smoke-free operation.
Not all of the pressure relief valves on the process units are
connected to the flare manifold system. As the valves are routinely
replaced they are being tied into the flare system. The older valves
are maintained by an inspection program in compliance with LAAPCD
Rule 73.
Delayed Coking and Coke Handling
Steam is introduced into the coke drums for 45 minutes after the
charge is completely coked. Off-gases from this operation are routed
to a blowdown contactor where they are sprayed with sponge oil. From
the contactor they are sent to coolers, a sour water knockout accumu-
lator, and ultimately combusted in the plant flare system.
After the steaming operation, the coke drum is water flooded, a
process which takes approximately 5 hours. Off-gases from this op-
eration are treated by the method described above.
After the vessel is water flooded, the access port at the top of
the drum is opened, the coke drill is inserted, and the water drained.
The access port is open to the atmosphere during the water draining
and coke cutting operation, a period of approximately 3 hours.
Some steam and organic vapors do escape to the atmosphere during this
period.
The coke which is cut from the drums is transported via open con-
veyor to a covered coke shed. Here it is screened to size and stored.
The coke screening operation is vented to a spray type scrubber system.
There are also spray systems within the coke shed to maintain coke
moisture content and minimize dust problems.
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9
Vacuum Jets
Vacuum jets are used at a vacuum distillation tower located near
the delayed coking unit. Exhaust gases from the vacuum jet system are
routed through a di-ethanolamine gas treating tower for sulfide removal
and then to a process heater firebox or, alternately, to the plant flare
system.
All vacuum jet condensate is collected in accumulators. Sour water
from the accumulators is contained in closed systems or in storage tanks
connected to the plant vapor recovery system. Sour water is ultimately
processed in the sour water strippers, which are discussed later.
There are no barometric condensers at this plant.
Fluid Catalytic Cracking Unit
Spent catalyst from the fluid catalytic cracking (FCC) unit is
continuously removed from the reactor portion and introduced through
piping into the catalyst regeneration unit. Here the petroleum coke,
tars, and other residual deposits which form on the catalyst surface are
burned off the catalyst fines. The recovered catalyst is then recycled
to the reactor. Catalyst particles which are entrained in the exhaust
gases are partially captured by a series of cyclone separators internal
to the regenerator unit. Catalyst captured by these cyclones is re-
turned to the regenerator.
The regenerator unit exhaust gases contain considerable amounts of
carbon monoxide, particulate matter, aldehydes, sulfur oxides, ammonia,
and oxides of nitrogen. To minimize the emission of carbon monoxide
(CO) and to recover the fuel value of this material, the regenerator
exhaust gases are combusted in a waste heat boiler.
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10
After exiting the regenerator cyclone units and before entering the
CO boiler, the exhaust gases are routed through two sets of electro-
static precipitator (ESP) units in series. ESP No. 1 is a Cottrell unit
consisting of two parallel banks of four stages each. From the No. 1
ESP the exhaust gases pass through the No. 2 ESP, a Research Cottrell
unit. This unit also has two parallel banks of four stages each. No. 1
ESP was installed in 1942-1943; No. 2 unit was installed in 1974.
Exhaust gases pass from the No. 2 ESP into the CO boiler. There is
a bypass stack immediately before the CO boiler which has a water seal
pot. During those periods when the CO boiler is down for State inspec-
tion (1 or 2 weeks every year) or maintenance, exhaust gases from No. 2
ESP can be discharged directly to the atmosphere through this bypass.
The plate rapping cycle on ESP unit No. 1 is synchronized with the
CO boiler tube lancing cycle. The plates of ESP unit No. 2 are rapped
continuously. Approximately 25% of the CO boiler tubes are lanced every
hour for approximately two minutes. This frequency has been established
to ensure compliance with LAAPCD Rule 50.
Dust collected in the first two stages of ESP No. 1 are recycled
back to the FCC catalyst regeneration unit. Dust collected in the other
ESP stages is collected in hoppers and hauled to landfill by contractors.
The hoppers are emptied about once a week.
Exhaust gases from the CO boiler discharge through a 2.7 m (9 ft)
diameter stack, 55 m (181 ft) high. This stack is equipped with a
Bailey stack gas opacity detector and recorder. The CO boiler bypass
stack also has a Bailey opacity detector and recorder.
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11
Product Loading Racks
Butanes, propane, isobutane, butylenes, spent sulfuric acid from
the alkylation process, and molten sulfur are shipped from loading racks
equipped with vapor collection systems.
Butanes are loaded into rail tank cars. The loading spigots are
tied into the plant vapor recovery system.
Propane, isobutane, normal butane and butylenes are loaded into
tank trucks at another loading rack. During truck loading operations,
the off-vapors are vented to the storage tank from which the product is
being transferred. After a truck is finished loading, the loading hoses
are evacuated using the plant vapor recovery system.
Spent sulfuric acid is loaded into tank trucks for transport to
an acid reclaiming contractor. A centrifugal compressor is used to pull
a vacuum on the truck during the loading operations. The collected gases
are discharged to the plant vapor recovery system.
The molten sulfur truck loading racks at the sulfur recovery plant
are equipped with vacuum hoses which attach to the truck. Vapors col-
lected by these hoses are discharged to the sulfur plant flare system.
Wastewater Treatment Facilities
Total wastewater flow from this refinery averaged approximately
7.6 x 103 m3 (2 x 10^ gal)/day during fiscal year 1974-75. Of this
o O C
total, approximately 5.3 x 10 m (1.4 x 10 gal)/day went to the
Dominguez channel and 2.3 x 10 m (0.6 x 10 gal )/day were discharged
to the Los Angeles County Sanitation District sewers. Cooling tower
blowdown, boiler blowdown, steam condensate, washdown water, and rainfall
are passed through API oil/water separators, air flotation and chemical
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12
coagulation systems, and settling ponds before being discharged to the
Dominguez channel. Sour water, process water, and ballast water are
passed through API oil/water separators, sour gas stripping units, and
sour water oxidizing units before being discharged to the County sewer
system.
Off-gases from the sour water stripper are processed at the sulfur
recovery plant. Oil skimmings from the API separators are sent to the
slop storage and ultimately reprocessed. The API separators have covered
forebays or floating pontoon covers on the forebays in accordance with
LAAPCD Rule 59.
Sulfur Recovery and Disposal
Mercaptan gases from the alkylation plant are incinerated in the
fireboxes of steam boilers No. 1, 3, and 5. Off-gases from the three
wastewater oxidizer units are incinerated in boilers No. 2 and 4, in No.
1 charge heater at crude unit No. 4, heaters HC-100 and HC-101 at the
delayed coking unit, and the hot oil circulation heater at the No. 2
fractionation unit.
The majority of the sulfur bearing gases are processed for sulfur
recovery. All refinery fuel gas from the various refinery operations is
passed through di-ethanolamine scrubbing towers before being introduced
into the fuel gas system. Off-gases from the sour water stripper units
are routed directly to the sulfur recovery plant.
The DEA solution absorbs hydrogen sulfide from the sour gases.
This "rich" DEA is then pumped to storage tanks at the Texaco sulfur
recovery plant located about 1.2 km (3/4 mi) from the main refinery.
Rich DEA is also received at this location from other sources in the
area. The rich DEA is held in storage tanks which are vented to the
sulfur recovery plant flare.
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13
The rich DEA is steam stripped to remove the H^S. The resulting
"lean" DEA is recycled to the sour gas treating facilities. The re-
sulting concentrated H^S stream is used as feed to the sulfur plant.
Texaco operates four 2-stage Claus sulfur recovery units. Texaco
considers the rated capacities of these units and the yearly sulfur pro-
duction figures to be confidential. A schematic diagram of a typical
2-stage Claus plant is shown in Appendix F.
In the Claus process, hydrogen sulfide (l^S) is burned to form sulfur
dioxide (SO^). The SC^ and H^S react in the presence of a bauxite cata-
lyst to form elemental sulfur and water vapor. Typical sulfur recovery
efficiencies for Claus plants are 85% for one catalytic stage, 94% for
two stages, and 97% for three stages.
Each of the Claus units has its own tail gas incinerator unit. Prior
to the installation of the Beavon-Parsons tail gas treatment unit, exhaust
gases from the Claus units were burned in these incinerators. Currently,
they are not used except when malfunctions in the Beavon-Parsons system
necessitate an alternate method of tail gas disposal. Details on these
incinerators are presented in Appendix F.
In 1974, Texaco completed the installation and start-up of a
Beavon-Parsons tail gas treatment unit at the sulfur recovery plant.
The unit, rated at 17.3 m. tons (19 tons)/day of elemental sulfur, re-
ceives tail gases directly from the four Claus units.
A schematic diagram of the Beavon-Parsons unit is presented in
Appendix F. In the first stage of this process, all sulfur compounds in
the Claus tail gas are converted to H^S by reaction with fuel gas in a
reducing atmosphere and in the presence of catalyst. The sulfur com-
pounds are converted to H^S by hydrogenation and hydrolysis. The re-
sulting hydrogenated gas stream is cooled by direct contact with a
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slightly alkaline buffer solution before entering the Stretford Process
which follows.
In the Stretford Process, the hydrogenated tail gas is contacted
with an oxidizing alkaline solution containing sodium vanadate. The
absorbed I^S is oxidized to elemental sulfur by the oxidizing solution.
The resulting colloidal sulfur is removed by froth flotation and de-
watered on vacuum filters. The oxidizing agents in the Stretford so-
lution are regenerated by air oxidation. The regenerated solution is
recycled back to the Stretford absorption tower.
Off-gases from the Streford absorption tower are discharged di-
rectly to the atmosphere. In an emergency they can be routed to
the Claus incinerators for combustion.
There are no continuous stack gas monitors on the Stretford tower
exhaust stack.
EMISSIONS DATA
Source Test Data
NEIC personnel requested that Texaco supply copies of all stack
tests conducted at this facility since 1972. The LAAPCD was requested
to do likewise. The data obtained is summarized below.
FCC Unit Emissions. On May 22, 1974, LAAPCD Test C-2158 was con-
ducted on the exhaust gases from the CO boiler attendant to the FCC
unit. The test results indicated particulate emissions of 6.3 kg (13.9
lb)/hr., sulfur dioxide emissions of 94.5 kg (208 lb)/hr and 223 ppmv
concentration, nitrogen oxide emissions of 20 kg (44 lb)/hr and carbon
monoxide emissions of less than 10 ppmv. The unit was found to be in
compliance with all applicable LAAPCD rules.
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15
Sulfur Plant Tail Gas Unit. Exhaust gases from the Beavon-Parsons
tail gas treatment unit were tested on September 19, 1974 by the LAAPCD
(Test C-2195) and again on November 10, 1974 (Test C-2226). Total
sulfur as S02 was 1,332 ppmv and 15 ppmv, respectively, for the two
tests corresponding to 46.8 kg (103 lb)/hr and 0.8 kg (1.7 lb)/hr as
S02, respectively. No H2S was detected in either of these tests.
The 1,332 ppmv of sulfur as S02 found in Test C-2195 was in excess
of the 500 ppmv allowed under Rule 53.2. The subsequent Test C-2226
showed the unit in compliance with this rule. It is not known what
process changes were made between the two tests to account for the dif-
ferences in S02 concentrations experienced.
Heaters and Boilers. Texaco participated in a comprehensive study
of oxides of nitrogen (NO ) emissions from stationary sources in the
South Coast Air Basin. KVB Engineering, Inc. conducted the study during
1972-73 for the State of California Air Resources Board. The results of
emission tests on several Texaco heaters and boilers are coded in Table
3C-III of the KVB report. Texaco declined to identify their units in
this coded list, stating that they considered the information con-
fidential .
Computed Emission Rates
Theoretical emission factors for various emission sources found at
petroleum refineries are listed in Table 9.1-1 of the EPA publication
AP-42 Compilation of Air Pollutant Emission Factors, Second Edition
(second printing with Supplements 1-4). These emission factors were
used to compute the following emission rates. Emissions from hydro-
carbon storage tanks have not been calculated for this report; rather,
they will be included in a separate report being prepared by NEIC
which will summarize storage tank emissions from all refineries in Los
Angeles County.
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Boilers and Process Heaters. As can be seen from the listing of
process heaters and steam boilers shown in Appendix C, a substantial
number of these units can be fired with both fuel gas and fuel oil.
Theoretical emissions from these units are calculated using different
factors for each fuel type used. Therefore, it can be seen that a range
of emissions can exist depending on the available fuel situation. Table
2 summarizes the theoretical emissions for two possible situations: 1)
all units in the refinery are being operated at rated capacity and all
units are being fired with a mixture of refinery fuel gas and natural
gas, and 2) all units are being operated at rated capacity, and the
natural gas supply is curtailed. All units which can be fired with fuel
oil are being operated on oil with any heat input deficit being made up
with refinery fuel gas. All other units are being operated on refinery
fuel gas.
The process heaters and boilers are major contributors of nitrogen
oxides. Depending on the fuel use pattern at the refinery, calculated
nitrogen dioxide emissions for these units range from 360 to 588 kg (790
to 1,293 lb)/hr as N02- If the refinery is on natural gas curtailment,
these units are also potential large sources of particulate matter, 127
kg (281 1b)/hr and sulfur oxides, 238 kg (523 lb)/hr as S02.
Fluid Catalytic Cracking Unit. Table 2 summarizes the calculated
theoretical emissions from this unit. These figures were calculated
using AP-42 emission factors for FCC units with attendant CO boilers and
electrostatic precipitators. The calculated value for particulate
emissions using the average emission factor value listed in AP-42 is 24
kg (52 1b)/hr. This value is in excess of the maximum allowable emis-
sion rate under the LAAPCD Rule 54 which is 13.6 kg (30 lb)/hr. How-
ever, it should be emphasized that the AP-42 emission factor is an
average value for the industry and that the Texaco precipitators may be
more efficient than the average unit. It should be remembered that Texaco
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Emission Source
Particulates
(kg/hr)(1b/hr)
Process Heaters &
Steam Boilers
t
Condition
Condition
tt
31.2
127
63.7
281
52
Fluid Catalytic
Cracking Unit 24
Compressor Internal
Combustion Engines Neg.
Blowdown Systems to
Vapor Recov. or Flares Neg.
Wastewater Treatment Neg.
Pipeline Valves and
Flanges Neg.
Vessel Relief Valves Neg.
Pump Seals Neg.
Compressor Seals Neg.
Totals+++ 151 333
Table 2
CALCULATED EMISSION RATES FROM VARIOUS UNIT OPERATIONS
Texaco} Inc. - Los Angeles, California Refinery
Calculated Emissions
Sulfur Oxides
(so2)
(kg/hr)(1b/hr)
4.4
238
261
9.6
523
575
499
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
1,098
Carbon Monoxide
(CO)
(kg/hr)(lb/hr)
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
Hydrocarbons
(kg/hr)(1 b/hr)
Nitrogen Oxides
(no2)
{kg/hr)(1b/hr)
47
46
117
30
7
7
40
15
24
14
307
103
101
257
66
16
16
88
34
53
31
678
360
588
38
23
790
1,293
83
50
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
649 1,426
Aldehydes Ammonia
(kg/hr) (lb/ hr) (kg/hr) (1 b/hr)
4.7
6.0
10
2.5
10.3
13.2
22
5.5
18.5
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
40.7
Neg.
Neg.
29
63
11
Neg.
Neg.
Neg.
Neg.
Neg.
Neg.
34
74
t Condition 1. All units operating at rated capacity and all fired with, refinery fuel gas or natural gas. ^
tt Condition 2. All units operating at rated capacity and natural gas curtailed. Units which can use fuel oil are being operated
on oil with heat input deficit made up with refinery gas. All other unite operating on refinery fuel gas.
ttt Totals include only condition (2) for boilers and process heaters. Considered worst operating mode.
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18
is operating two ESP units in series. The LAAPCD Test C-2158 of May 22,
1974 indicated that the particulate emission rate was 6.3 kg (13.9
lb)/hr from this unit, well below the allowable emission rate. It is
not known whether this test was conducted at normal operating conditions,
or at start-of-run conditions which would favor lower emission rates.
The calculated emission rates for other pollutants from the FCC
unit indicate that substantial amounts of sulfur dioxide, hydrocarbon,
and nitrogen dioxide are emitted from this unit. The calculated theo-
retical values are 261 kg (575 lb)/hr, 117 kg (257 lb)/hr and 38 kg (83
lb)/hr, respectively.
Other Sources. Table 2 summarizes the calculated theoretical emis-
sion rates from other sources within the refinery. In general, AP-42
gives only hydrocarbon emission factors for these sources. The major
sources are leakage from pipeline valves and flanges which amount to 40
kg (88 1b)/hr of hydrocarbon.
SUMMARY OF PAST VIOLATIONS
The LAAPCD was requested to submit copies of violation notices
issued to Texaco. Copies of the violations issued since 1962 (6 total)
are presented in Appendix G. The most recent violation notices, May 11
and May 24, 1975, were issued due to malfunction of the sulfur recovery
plant. In all six situations, the Company pleaded nolo contendre or
guilty and paid fines ranging from $105 to $625.
All units at this refinery are operating under a valid LAAPCD
permit.
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INSPECTION SUMMARY
At the time of this inspection, all major process units were in
operation. All process units, storage vessels, potential pollution
emission points and pollution control devices in use at the refinery
were observed during this inspection.
Upon arriving at the refinery on October 31, 1975, and while waiting
for the pre-inspection interview to begin, NEIC personnel noted black
emissions with opacity of 80-100% emanating from a stack marked TEXACO,
south of the Pacific Coast Highway from the administration building.
The emissions continued for 15-20 minutes from approximately 7:55 am to
8:15 am. Due to the fact that the interview was about to begin, it was
not possible to conduct an accurate visible emissions observation at
that time. Later, during the plant inspection, it was determined that
the problem had been associated with steam boilers No. 1,3 and 5.
Excessive hydrocarbons had been carried over in the mercaptan waste gas
line from the alkylation units and introduced into the fireboxes of
these boilers. The hydrocarbon had upset the air/fuel ratio in these
units, resulting in the black smoke observed.
No visible emissions were noted from any of the other process
heaters or steam boilers. The flare systems also appeared to be opera-
ting correctly.
The CO boiler stack was observed during the boiler tube lancing/ESP
plate rapping cycle. The visible emissions during this 2-3 minute
period did not exceed 20%. Before and after the lancing/rapping cycle,
no visible emissions could be noted from this stack.
It was noted that severe corrosion had occurred on handrails and
other steel members at the Stretford froth floatation unit of the
Beavon-Parsons tail gas treatment unit. Also, condensed sulfur was
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20
noted at the exhaust port of the Stretford absorption tower. Both of
these situations appear to indicate operational problems with the
sulfur recovery units in the past.
In general, housekeeping at this refinery was very good. The
main process areas were neat with no noticeable spills or leaks.
Moderately strong sulfide/mercaptan odors were noted at the delayed
coking areas on both days. Very strong sulfide/mercaptan odors were
noted at the FCC unit on October 31, 1975. The sources of these odors
were not determined.
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APPENDIX A
NEIC INFORMATION REQUEST LETTER TO TEXACO, INC.
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ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF ENFORCEMENT
NATIONAL FIELD INVESTIGATIONS CENTER-DENVER
BUILDING 53. BOX 25277, DENVER FEDERAL CENTER
DENVER. COLORADO 80225
September 8, 1975
Dear
Pursuant to the authority contained in Section 114 of the Clean Air
Act, as amended, representatives of the EPA will conduct, within the
next year, inspections of the operations to
ascertain compliance with the Federally approved California State
Implementation Plan.
Representatives from the Environmental Protection Agency will
observe the facility's process operations, inspect monitoring and
laboratory equipment and analytical methods, review source test data,
examine appropriate records, etc. A process and air pollution flow
diagram or a blueprint of the facility and production information should
be available for the EPA personnel at the start of the inspections.
Detailed information about air pollution sources will be discussed
during these inspections. Attached is a partial list of the information
that will be needed in order to complete these inspections. We would
appreciate it if you could inform the appropriate company personnel
about the forthcoming inspections so that the necessary information will
be readily available and the inspection can be expedited.
If you have any questions concerning these inspections, please feel
free to contact Arnold Den, Chief, Air Investigations Section, Region
IX, San Francisco, at 415/556-8752.
A representative of the EPA (Dr. Wayne Smith or Mr. David Brooman,
303/234-4658) will contact you within the next 30 days concerning this
visit.
Sincerely,
"7P.
Thomas P. Gallagher
Director
Attachments'
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A. Refinery Capacity in Barrels/Day
B, Furnaces, Boilers and Process Heaters (for each furnace boiler
and heater)
1. Rated capacity in 106 BTU/hr heat input.
2. Maximum capacity as per cent of rated capacity.
3. For oil fired units:
a. Rated capacity in gals/hr or 103 bbl/hr.
b. Heating value in BTU's/gal.
c. Per cent sulfur and ash in oil by wt.
d. Specific gravity of oil.
e. Firing pattern (atomization, etc. for furnaces).
A. For gas fired units:
a. Rated capacity in 10^ SCF/hr.
b. Type of gas burned (list principal constituents in % by
weight).
c. Density lb/SCF.
d. Heating value of gas in BTU's/SCF.
e. Sulfur content of gas in % S by vol and grains/SCF,
5. Type(s) of control equipment and collection efficiency(s)
(design and actual).
6. Pressure drop (inches of water) across collection devices(s).
7. Elevation above grade of stack outlets and other discharge
points.
8. Identification of stacks equipped with recording monitors
for determining opacities of stack effluents.
9. Existing stack test data. The full test reports describing
methods used, test data, calculations, test results and
process weights should be available.
10. Inside diameters of each stack (ft).
11. Temperature of effluent gas stream from each stack (°F).
12. Exit velocity of each stack effluent (ft/sec).
C. Incinerators: (For each incinerator)
1. Rated capacity in 106 BTU's/hr; include auxiliary burners
separately.
2. Auxiliary burner fuels:
oil - 103 bbl/hr and specific gravity,
gas - 10^ SCF/hr and density in lb/SCF.
other - (describe) - lbs/hr (Heating value of each fuel).
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3. Maximum capacity as per cent of rated capacity for auxiliary
burners.
4. Sulfur and ash content of fuel as % by weight for auxiliary
burners.
5. Type of material incinerated.
6. Rated capacity for material incinerated in lb/hr.
7. Sulfur and ash content of material incinerated as % by weight.
8. Heating value of material incinerated.
9. The gas flow rate reported at dry standard conditions (DSCFH).
10. Type(s) of control equipment and collection efficiency(s)
(design and actual).
11. Pressure drop (inches of water) across collection device(s) .
12. Elevation above grade of stack outlets and other discharge
points (ft).
13. Identification of stacks equipped with recording monitors
for determining opacities of stack effluents.
14. Existing stack test data. Data should include the full test
reports describing methods used, test data, calculations,
test results and process weights.
15. Inside diameter of each stack (ft).
JL6. Exit velocity of each stack effluent (ft/sec.).
17. Temperature of effluent gas stream from each stack in °F.
Catalytic Cracking Units, Coker Units: (For each unit)
1. Rated capacity - 10^ BTU/hr and indicate the type of unit such
as PCC, Coker, etc.
2. Maximum capacity as per cent of rated capacity.
3. Type of feed-stock used and barrels of fresh feed used per yr.
•4. Sulfur content of feed-stock (% by weight).
5. Types of control equipment and collection efficiency(s) (design
and actual).
6. Pressure drop (inches of water) across collection devices(s),
7. Elevation above grade of stack outlets and other discharge
points (ft).
8. Identification of stacks equipped with recording monitors
for determining opacities of stack effluents.
9. Existing stack test data. Data should include the full test
reports describing methods used, test data, calculations, test
results and process weights.
10. Inside diameter of each stack (ft).
11. Exit velocity of each stack effluent (ft/sec).
12. Total flow through unit in 10^ bbl/hr and ton/hr.
13. Temperature of effluent gas stream from each stack in °F.
14. Indicate disposition of waste gas stream, i.e., burned in
afterburner, etc.
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-3-
15. Average hours of operation per month and average monthly
catalyst makeup for the catalytic cracking units.
16. Indicate date of installation or latest modification.
E. Blowdown Systems:
1. Indicate type and efficiency of each air pollution control
device.
F. Flares: (For each flare)
1. Type
2. Height and diameter of stack (ft).
3. Velocity of stack effluent (ft/sec).
4. Temperature of gas effluent (°F).
5. Rated capacity 106 BTU/hr and tons/hr (of flared material).
6. Amount of material flared and percent of time material being
flared.
7. Maximum capacity as per cent of rated capacity.
8. Type of flare ignition device at top of stack.
9. Sulfur content of flared input (% by wt).
10. Where material coraes from that is burned in flare.
G. Storage Vessels: (For each vessel)
1. Indicate type of tank (fixed roof, floating roof, vapor recovery,
etc.) -
2. Give storage capacity of each tank in 10 gallons or barrels.
3. Indicate type of material stored in each tank (crude cil, gasoline,
finished petroleum product) and give annual average true vapor
pressure (TVP) and seasonal maximum for actual storage condition
of product stored in lbs/sq. in. absolute.
4. State tank diameter (ft).
5. Indicate if tank is equipped with submerged fill pipe.
6. Indicate if the tank is a pressure tank capable of maintaining
working pressure sufficient at all times to prevent vapor or gas
loss to the atmosphere.
7. State type of air pollution control equipment on each Lank, i.e.,
conservation vent, vapor recovery system, etc.
8. Indicate average and seasonal maximum temperature of each tank.
9. Indicate date of installation or latest modifications.
10. Indicate if tank is used for multiple product storage.
H. Wastewater Treatment Systems:
1. Indicate gallons of waste water discharged daily.
2. Indicate source of such drains (process discharged).
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-4-
3. Indicate type and efficiency of each air pollution control
device and any existing test data indicating actual emissions.
Data should include the full test reports describing methods
used, test data, calculations, test results and process weight.
I. Internal Combustion Engines: (Stationary)
1. Type of engine.
2. Amount of fuel burned per day.
3. Type of fuel.
J. Vacuum Jets and/or Barometric Condensers
1. Indicate type and efficiency of each air pollution control
device.
2. Indicate disposition of exhaust gases (eg. To afterburners,
fireboxes, etc.).
K. Loading Rack Vapor Recovery:
1. Actual product throughput in 10 gallons per day and year.
2. Type of material loaded.
3. Type of vapor recovery system and rated collection efficiency.
4. Existing test data. The full test reports describing methods
used, test data, calculations and test results should be
submitted.
L. Submit schematic diagrams showing stacks and their respective
• process associations and control equipment.
M. List any other significant (25 tons/yr. potential uncontrolled
emission) sources of particulates, sulfur dioxide, carbon monoxide,
oxides of nitrogen, and hydrocarbons not covered by Items B-L.
Include:
1. Type of process and rated capacity.
2. Type of material processed.
3. Types of collection equipment and collection efficiency(s)
(design and actual).
4. Pressure drop (inches of water) across collection devices.
5. Existing stack test data applicable to current operating
conditions. The full test reports describing methods used,
test data, calculations, test results and process weights
should be submitted.
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APPENDIX B
SELECT LAAPCD RULES
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APPENDIX B
County of Los Angeles
Air Pollution Control District
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Prohibitions
-------
Rule 50. Ringelmann Chart.
(Effective January 6, 1972 for any source not completed and put into
service. Effective for all sources on January 1, 1973.)
A person shall not discharge into the atmosphere from any single
source of emission whatsoever any air contaminant for a period or periods
aggregating more than three minutes in any one hour which is
a. As dark or darker in shade as that designated No. 1 on the Ringel-
mann Chart, as published by the United States Bureau of Mines, or
b. Of such opacity as to obscure an observer's view to a degree
equal to or greater than does smoke described in subsection (a) of this
Rule.
This amendment shall be effective on the date of its adoption for any
source of emission not then completed and put into service. As to all other
sources of emission this amendment shall be effective on January 1, 1973.
A person shall not discharge from any source whatsoever such quanti-
ties of air contaminants or other material which cause injury, detriment,
nuisance or annoyance to any considerable number of persons or to the
public or which endanger the comfort, repose, health or safety of any such
persons or the public or which cause or have a natural tendency to cause
injury or damage to business or property.
^yCtule 52.. Particulate Matter - Concentration.
(Effective January 6, 1972 for any equipment not completed and put
into service. Effective for all equipment on January 1, 1973.)
A person shall not discharge into the atmosphere from any source par-
ticulate matter in excess of the concentration shown in the following table:
(See Rule 52 Table)
Where the volume discharged falls between figures listed in the table,
the exact concentration permitted to be discharged shall be determined by
linear interpolation.
The provisions of this rule shall not apply to emissions resulting from
the combustion of liquid or gaseous fuels in steam generators or gas turbines.
For the purposes of this rule "particulate matter" includes any material
which would become particulate matter if cooled to standard conditions.
This amendment shall be effective on the date of its adoption for any
Rule 51. Nuisance.
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(
equipment not then completed and put into service As to all other equip-
ment this amendment shall be effective on January 1, 1973.
Table For Rule 52
Volume Discharged- Maximum Concentra-
Cubic Feet Per Minute tion of Particulate Mat-
Calculated as Dry Gas ter Allowed in Dis-
ot Standard Conditions charged Gas-Grains Per
Cubic Foot of Dry Gas
at Standard Conditions
1000 or less
0.200
20000
0.0635
1200
.187
30000
.0544
1400
.176
40000
.0487
1600
.167
50000
.0447
1800
.160
60000
.0417
2000
.153
70000
.0393
2500
.141
80000
.0374
3000
.131
100000
.0343
3500
.124
200000
.0263
4000
.118
400000
.0202
5000
.108
600000
.0173
6000
.101
800000
.0155
7000
.0949
1000000
.0142
8000
.0902
1500000
.0122
10000
.0828
2000000
.0109
15000
.0709
2500000 or more
.0100
Volume Discharged-
Cubic Feet Per Minute
Calculated as Dry Gas
at Standard Conditions
Maximum Conccntra
tion of Particuljic Mdt-
ter Allowed in Dis
chared Gas Groins Per
Cubic Foot of Dry Gas
at Standard Conditions
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plant, recovering pollutants which would otherwise be emitted to the atmos-
phere, the Air Pollution Control Officer may grant a permit to operate
where the total emission of pollutants is substantially less with the plant in
operation than when closed, even though the concentration exceeds that
permitted by Rule 53(a). The Air Pollution Control Officer shall report
immediately in writing to the Air Pollution Control Board the granting of
any such permit, together with the facts and reasons therefor.
Effective July 1, 1973, this Rule is repealed for sulfur recovery units
Effective January 1, 1974, this Rule is repealed for sulfuric acid units
A person shall not, after June 30, 1973, discharge into the atmosphere
from any sulfur recovery unit producing elemental sulfur, effluent process
gas containing more than:
1. 500 parts per million by volume of sulfur compounds calculated
as sulfur dioxide.
2. 10 parts per million by volume of hydrogen sulfide.
3. 200 pounds per hour of sulfur compounds calculated as sulfui
Any sulfur recovery unit having an effluent process gas discharge con-
taining less than 10 pounds per hour of sulfur compounds calculated as sul-
fur dioxide may dilute to meet the provision of number (1) above.
A person shall not, after December 31, 1973, discharge into the atmos-
phere from any sulfuric acid unit, effluent process gas containing more than.
1. 500 parts per million by volume of sulfur compounds calculated
Rule 53.2. Sulfur Recovery Units.
dioxide.
Rule 53.3. Sulfuric Acid Units.
as sulfur dioxide.
2. 200 pounds per hour of sulfur compounds calculated as sulfur
dioxide.
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ule 54. Solid Particulate Matter - Weight.
(Effective January 6, 1972 for any equipment not completed and put
into service. Effective for all equipment on January 1, 1973 )
A person shall not discharge into the atmosphere from any source
solid particulate matter, including lead and lead compounds, in excess of
the rate shown in the following table* (See Rule 54 Table)
TABLE FOR RULE 54
(Amended January 6, 1972)
Process Weight
Maximum Discharge
Process Weight
Maximum Discharge
Per Hour-
Rate Allowed for Solid
Per Hour-
Rate Allowed for Solid
Pounds Per Hour
Particulate Matter
Pounds Per Hour
Particulate Matter
(Aggregate Discharged
(Aggregate Discharged
From All Points of
From All Points of
Processl-Pounds
Processl-Pounds
Per Hour
Per Hour
250 or less
1.00
12000
10.4
300
1.12
14000
10.8
350
1.23
16000
11.2
400
1.34
18000
11.5
450
1.44
20000
11.8
500
1.54
25000
12.4
600
1.73
30000
13.0
700
1.90
35000
13.5
800
2.07
40000
13.9
900
2.22
45000
14.3
1000
2.38
50000
14.7
1200
2.66
60000
15.3
1400
2.93
70000
15.9
1G00
3.19
80000
16.4
1800
3.43
90000
16.9
2000
3.66
100000
17.3
2500
4.21
120000
18.1
3000
4.72
140000
18.8
3500
5.19
160000
19.4
4000
5.64
180000
19.9
4500
6.07
200000
20.4
5000
6.49
250000
21.6
5500
6.89
300000
22.5
6000
7.27
350000
23.4
6500
7.64
400000
24.1
7000
8.00
450000
24.8
7500
8.36
500000
25.4
8000
8.70
600000
26.6
8500
9.04
700000
27.6
9000
9.36
800000
28.4
9500
9.68
900000
29.3
10000
10.00
1000000 or
more 30.0
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Where the process weight per hour falls between figures listed in the
table, the exact weight of permitted discharge shall be determined by linear
interpolation.
For the purposes of this rule "solid particulate matter" includes any
material which would become solid particulate matter if cooled to standard
conditions.
This amendment shall be effective on the date of its adoption for any
equipment not then completed and put into service. As to all other equip-
ment this amendment shall be effective on January 1, 1973.
The provisions of Rule 50 do not apply to:
a. Smoke from fires set by or permitted by any public officer
if such fire is set or permission given in the performance of the official
duty of such officer, and such fire in the opinion of such officer is
necessary:
b. Smoke from fires set pursuant to permit on property used
for industrial purposes for the purpose of instruction of employees in
methods of fighting fire.
c. Agricultural operations in the growing of crops, or raising of
fowls oranimals.
d. The use of an orchard or citrus grove heater which does not
produce unconsumed solid carbonaceous matter at a rate in excess of
one(1) gram per minute.
e. The use of other equipment in agricultural operations in the
growing of crops, or raising of fowls or animals.
Rule 55. Exceptions.
1. For the purpose of the prevention of a fire hazard
which cannot be abated by any other means, or
2. The instruction of public employees in the methods of
fighting fire.
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Rule 56. Storage of Petroleum Products.
A person shall not place, store or hold in any stationary tank, reser-
voir or other container of more than 40,000 gallons capacity any gasoline
or any petroleum distillate having a vapor pressure of 1 5 pounds per square
inch absolute or greater under actual storage conditions, unless such tank,
reservoir or other container is a pressure tank maintaining working pressures
sufficient at all times to prevent hydrocarbon vapor or gas loss to the atmos-
phere, or is designed and equipped with one of the following vapor loss con-
trol devices, properly installed, in good working order and in operation-
a. A floating roof, consisting of a pontoon type or double-deck
type roof, resting on the surface of the liquid contents and equipped
with a closure seal, or seals, to close the space between the roof edge
and tank wall. The control equipment provided for in this paragraph
shall not be used if the gasoline or petroleum distillate has a vapor pres-
sure of 11.0 pounds per square inch absolute or greater under actual
storage conditions. All tank gauging and sampling devices shall be gas-
tight except when gauging or sampling is taking place.
b. A vapor recovery system, consisting of a vapor gathering sys-
tem capable of collecting the hydrocarbon vapors and gases discharged
and a vapor disposal system capable of processing such hydrocarbon
vapors and gases so as to prevent their emission to the atmosphere and
with all tank gauging and sampling devices gas-tight except when gaug-
ing or sampling is taking place.
c. Other equipment of equal efficiency, provided such equip-
ment is submitted to and approved by the Air Pollution Control Offi-
cer.
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Rule 59. Effluent Oil Water Separators.
(Effective June 29, 1971 for any equipment not completed and put
into service. Effective for all equipment after July 1, 1972)
A person shall not use any compartment of any vessel or device operat-
ed for the recovery of oil from effluent water which recovers 200 gallons a
day or more of any petroleum products from any equipment which proc-
esses, refines, stores or handles hydrocarbons with a Reid vapor pressure
of 0.5 pound or greater, unless such compartment is equipped w.th one of
the following vapor loss control devices, except when gauging or sampling
is taking place:
a. A solid cover with all openings sealed and totally enclosing
the liquid contents of that compartment.
b. A floating pontoon or double-deck type cover, equipped
with closure seals to enclose any space between the cover's edge and
compartment wall.
C. A vapor recovery system, which reduces the emission of all
hydrocarbon vapors and gases into the atmosphere by at least 90 per
cent by weight.
d. Other equipment of an efficiency equal to or greater than
a, b, or c, if approved by the Air Pollution Control Officer.
This rule shall not apply to any oil-effluent water separator used ex-
clusively in conjunction with the production of crude oil, if the water
fraction of the oil-water effluent entering the separator contains less than
5 parts per million hydrogen sulfide, organic sulfides, or a combination
thereof.
This amendment shall be effective at the date of its adoption for any
equipment not then completed and put into service. As to all other equip-
ment this amendment shall be effective on July 1, 1972.
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Rule 60. Circumvention.
A person shall not build, erect, install, or use any article, machine,
equipment or other contrivance, the use of which, without resulting in a
reduction in the total release of air contaminants to the atmosphere, re-
duces or conceals an emission which would otherwise constitute a violation
of Division 20, Chapter 2 of the Health and Safety Code of the State of
California or of these Rules and Regulations. This Rule shall not apply to
cases in which the only violation involved is of Section 24243 of the Health
and Safety Code of the State of California, or of Rule 51 of these Rules and
Regulations.
(Effective June 29, 1971 for any equipment not completed and put
into service. Effective for all equipment after July 1, 1972)
A person shall not load organic liquids having a vapor pressure of 1.5
psia or greater under actual loading conditions into any tank truck, trailer,
or railroad tank car from any loading facility unless the loading facility is
equipped with a vapor collection and disposal system or its equivalent ap-
proved by the Air Pollution Control Officer.
Loading shall be accomplished in such a manner that all displaced
vapor and air will be vented only to the vapor collection system. Measures
shall be taken to prevent liquid drainage from the loading device when it is
not in use or to accomplish complete drainage before the loading device is
disconnected.
The vapor disposal portion of the vapor collection and disposal system
shall consist of one of the following:
a. An absorber system or condensation system which processes
all vapors and recovers at least 90 per cent by weight of the organic
vapors and gases from the equipment being controlled.
b. A vapor handling system which directs all vapors to a fuel gas
system.
c. Other equipment of an efficiency equal to or greater than a
or b if approved by the Air Pollution Control Officer.
This rule shall apply only to the loading of organic liquids having a
Rule 61. Organic Liquid Loading.
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vapor pressure of 1.5 psia or greater under actual loading conditions at a
facility from which at least 20,000 gallons of such organic liquids are loaded
in any one day.
"Loading facility", for the purpose of this rule, shall mean any aggie-
gation or combination of organic liquid loading equipment which is both
(1) possessed by one person, and (2) located so that all the organic liquid
loading outlets for such aggregation or combination of loading equipment
can be encompassed within any circle of 300 feet in diameter
This amendment shall be effective at the date of its adoption for any
equipment not then completed and put into service. As to all other equip-
t this amendment shall be effective on July 1, 1972.
A person shall not burn within the Los Angeles Basin at any time be-
tween May 1 and September 30, both dates inclusive, during the calendar
year 1959, and each year thereafter between April 15 and November 15,
both inclusive, of the same calendar year, any gaseous fuel containing sulfur
compounds in excess of 50 grains per 100 cubic feet of gaseous fuel, calcu-
lated as hydrogen sulfide at standard conditions, or any liquid fuel or solid
fuel having a sulfur content in excess of 0.5 per cent by weight.
The provisions of this rule shall nqt apply to.
a. The burning of sulfur, hydrogen sulfide, acid sludge or other
sulfur compounds in the manufacturing of sulfur or sulfur compounds
b. The incinerating of waste gases provided that the gross heat-
ing value of such gases is less than 300 British Thermal Units per cubic
foot at standard conditions and the fuel used to incinerate such waste
gases does not contain sulfur or sulfur compounds in excess of the a-
mount specified in this rule.
;ule 62. Sulfur Contents of Fuels.
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c. The use of solid fuels in any metallurgical process.
d. The use of fuels where the gaseous products of combustion
are used as raw materials for other processes.
e. The use of liquid or solid fuel to propel or test any vehicle,
aircraft, missile, locomotive, boat or ship.
f. The use of liquid fuel whenever the supply of gaseous fuel,
the burning of which is permitted by this rule, is not physically avail-
able to the user due to accident, act of God, act of war, act of the
public enemy, or failure of the supplier.
a. A person shall not burn within the Los Angeles Basin at any
time between the days of November 16 of any year and April 14 of the
next succeeding calendar year, both dates inclusive, any fuel described in the
first paragraph of Rule 62 of these Rules and Regulations.
b. The provisions of this Rule do not apply to:
1. Any use of fuel described in Subsections a,b,c,d,e, and f of
said Rule 62 under the conditions and for the uses set forth
in said Subsections.
2. The use of liquid fuel during a period for which the supplier
of gaseous fuel, the burning of which is not prohibited by
this Rule, interrupts the delivery of gaseous fuel to the user.
c. Every holder of, and every applicant for a permit to operate fuel-
burning equipment under these Rules and Regulations shall notify the Air
Pollution Control Officer in the manner and form prescribed by him, of each
irruption in and resumption of delivery of gaseous fuel to his equipment.
Notwithstanding the provisions of Section (f) of Rule 62 or any pro-
Rule 62.1 Sulfur Contents of Fuels.
Rule 62.2 Sulfur Contents of Fuels.
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vision of said section as incorporated into Rule 62.1 or any provision of
Subsection (2) of Section b of Rule 62.1, a person shall not burn within the
Los Angeles Basin any liquid fuel or solid fuel having a sulfur content in ex-
cess of 0.5 per cent by weight.
It shall not be a violation of this rule to burn such fuel for a period of
not to exceed three calendar days (and in addition for that period of time
necessary for the Hearing Board to render a decision, provided that an ap-
plication for a variance is promptly filed) when other fuel which complies with
this Rule is not used due to accident, strike, sabotage, or act of God.
a. A person shall not, after June 30, 1960, sell or supply for use
within the District as a fuel for motor vehicles as defined by the Vehicle
Code of the State of California, gasoline having a degree of unsaturation
greater than that indicated by a Bromine Number of 30 as determined by
ASTM Method D1159-57T modified by omission of the mercuric chloride
b. For the purpose of this rule, the term "gasoline" means any pe-
troleum distillate having a Reid vapor pressure of more than four pounds
Rule 64. Reduction of Animal Matter.
S A person shall not operate or use any article, machine, equipment or
other contrivance for the reduction of animal matter unless all gases, vapors
and gas-entrained effluents from such an article, machine, equipment or
other contrivance are:
a. Incinerated at temperatures of not less than 1200 degrees
Fahrenheit for a period of not less than 0.3 second, or
b. Processed in such a manner determined by the Air Pollution
Rule 63. Gasoline Specifications.
catalyst.
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Rule 66.1. Architectural Coatings.
a. A person shall not sell or offer for sale for use in Los Angeles
County, in containers of one quart capacity or larger, any architectural
coating containing photochcmically reactive solvent, as defined in Rule
66(k).
b. A person shall not employ, apply, evaporate or dry in Los Angeles
County any architectural coating, purchased in containers of one quart
capacity or larger, containing photochemically reactive solvent, as defined
in Rule 66 (k).
c. A person shall not thin or dilute any architectural coating with a
photochemically reactive solvent, as defined in Rule 66(k).
d. For the purposes of this rule, an architectural coating is defined as
a coating used for residential or commercial buildings and their appurte-
nances; or industrial buildings.
A person shall not during any one day dispose of a total of more than
VA gallons of any photochemically reactive solvent, as defined in Rule 66(k),
or of any material containing more than VA gallons of any such photochemi-
cally reactive solvent by any means which will permit the evaporation of
/ent into the atmosphere.
A person shall not build, erect, install or expand any non-mobile fuel
burning equipment unit unless the discharge into the atmosphere of contam-
inants will not and does not exceed any one or more of the following
rates:
1. 200 pounds per hour of sulfur compounds, calculated as sulfur
Rule 66.2 Disposal and Evaporation of Solvents
Fuel Burning Equipment.
-------
dioxide (SO2);
2. 140 pounds per hour of nitrogen oxides, calculated as nitrogen
dioxide (NO2),
3. 10 pounds per hour of combustion contaminants as defined in
Rule 2m and derived from the fuel.
For the purpose of this rule, a fuel burning equipment unit shall be
comprised of the minimum number of boilers, furnaces, jet engines or other
fuel burning equipment, the simultaneous operations of which are required
for the production of useful heat or power.
Fuel burning equipment serving primarily as air pollution control
equipment by using a combustion process to destroy air contaminants
shall be exempt from the provisions of this rule.
Nothing in this rule shall be construed as preventing the maintenance
or preventing the alteration or modification of an existing fuel burning
equipment unit which will reduce its mass rate of air contaminant emissions.
A person shall not discharge into the atmosphere from any non-
mobile fuel burning article, machine, equipment or other contrivance, having
a maximum heat input rate of more than 1775 million British Thermal
Units (BTU) per hour (gross), flue gas having a concentration of nitrogen
oxides, calculated as nitrogen dioxide (NO2) at 3 per cent oxygen, in ex-
cess of that shown in the following table*
NITROGEN OXIDES - PARTS PER MILLION PARTS OF FLUE GAS
Rule 68. Fuel Burning Equipment -- Oxides of Nitrogen.
EFFECTIVE DATE
FUEL
DECEMBER 31, 1971 DECEMBER 31,1974
Gas
Liquid or Solid
225
325
125
225
-------
\/r'
Rule 68.1. Fuel Burning Equipment - Combustion Contaminants.
A person shall not discharge into the atmosphere combustion contami-
nants exceeding in concentration at the point of discharge, 0 3 grain per
cubic foot of gas calculated to 12 per cent of carbon dioxide (CO2) at
standard conditions.
l/
Rule 69. Vacuum Producing Devices or Systems.
A person shall not discharge into the atmosphere more than 3 pounds
of organic materials in any one hour from any vacuum producing devices or
systems including hot wells and accumulators, unless said discharge has been
reduced by at least 90 per cent.
This rule shall be effective at the date of its adoption for any equip-
ment not then completed and put into service. As to all other equipment
this rule shall be effective on July 1, 1972.
X'
Rule 70. Asphalt Air Blowing.
A person shall not operate or use any article, machine, equipment or
other contrivance for the air blowing of asphalt unless all gases, vapors and
gas-entrained effluents from such an article, machine, equipment or other
contrivance are-
a. Incinerated at temperatures of not less than 1400 degrees
Fahrenheit for a period of not less than 0 3 second, or
b. Processed in such a manner determined by the Air Pollution
Control Officer to be equally, or more, effective for the purpose of air
pollution control than (a) above.
This rule shall be effective at the date of its adoption for any equip-
ment not then completed and put into service. As to all other equipment
this rule shall be effective on July 1, 1972.
/
Rule 71. Carbon Monoxide.
A person shall not. after December 31, 1971, discharge into the atmos-
phere carbon monoxide (CO) in concentrations exceeding 0.2 per cent by
volume measured on a dry basis.
The provisions of this rule shall not apply to emissions from internal
-------
combustion engines
lule 72. Pumps and Compressors.
A person shall not, after July 1, 1973, use any pump or compressor
handling organic materials having a Reid Vapor Pressure of 1 5 pounds or
greater unless such pump or compressor is equipped with a mechanical seal
or other device of equal or greater efficiency approved by the Air Pollution
Control Officer
The provisions of this rule shall not apply to any pump or compressor
which has a driver of less than one (1) horsepower motor or equivalent
rated energy or to any pump or compressor operating at temperatures in
;cess of 500°F
A person shall not, after July 1, 1973, use any safety pressure
relief valve on any equipment handling organic materials above 15 pounds
per square inch absolute pressure unless the safety pressure relief valve is
vented to a vapor recovery or disposal system, protected by a rupture disc,
or is maintained by an inspection system approved by the Air Pollution
Control Officer
The provisions of this rule shall not apply to any safety pressure relief
valve of one (1) inch pipe size or less.
Rule 73. Safety Pressure Relief Valves.
-------
APPENDIX C
PROCESS HEATER AND STEAM BOILER LISTING
-------
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-------
APPENDIX D
INTERNAL COMBUSTION ENGINE LISTING
-------
Form 04
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-------
APPENDIX E
STORAGE TANK LISTING
-------
Texaco
STORAGE VESSELS: I Ol Q _^Lnq 'v:™'; PLA*rr
TAJTK
NU'BER
DATE
BUILT OR
yODIFIZO
DIAMETER
feet
CAPACITY
BAP?,ELS
TYPE OF
TA'^K OR
ROOF
SU3MERGED
FILL
YES-NO
PRESSURE
TANK
yes-t:o
AIR
POLLUTION
CONTROL
EQUIPMENT
TYPE OF
STO
MATERIAL
RED
TRUE VAPOR -
PRESSURE OF.
PRIMARY FRODoCT
PSIA
TAKK TZirPERA"?.
or #
ANNUAL
AVG.
SEASONAL
KAXITOH
AVSFAGZ
11~V Ii!.
PRIi ARY
\LTERN=\TE
39
1941
8 ' -0"
50
CONE
YES
no
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-
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70
- 70
100
56
7 ' -9"
100
NO
H
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H2S04-9 8%
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57
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100
II
YES
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63
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• 1
NO
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1
2
61 "
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119
55
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11
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69
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120
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130
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65 .
82
145
41
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130
11
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80
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192 1
41
12"-0"
230
l»
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11
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62
62
200
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12'-0"
220
II
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11
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60
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201
44
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260
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61
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209
7£
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63
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II
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II
ii
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60
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43
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240
II
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3 5
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200
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-
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280
i 66
10 '-3"
230
"
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1
2
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6
8
86
1~ b
II
CONS.VENT
ti
RED.CRUDE
0
0 .
117 -
If
II If
ri
n ii
0
0
115
1-2
tt II
1
rt
tt it
0
0
120
1
t
I
t
!
-------
- (
I
S70?-~>
¦ixc-c o
~ VESSELS:
7ofq
-ta::k
nu: j£r
DATE
BUILT OR
vCDIFIEO
DIAIIETER
FEET
CAPACITY
BARRELS
TYPE OF
TAXK OR
ROOF
30092
8C0S3
80034
S008 5
800S7
8008S
SO:'39
8 0 P a 0
800 = 1
80092
80209
80210
00211
— £C212
SO 21 3
80214
8021 5
80216
80217
80218
96000
118:55
125000
125001
125002
12 50 03
143000 -
5201
1925
25
25
25
2 5
25
2 5
2 5
26
26
58
57
52
52
52
54
54
54
54
69
72
40
25
25
69
71
70
44
117 '
117'
117'
117'
117 '
117 '
11" '
119 '
117'
117 '
120 '
120 '
117 •
; 117-
1 117'
i 120 '
| 120 •
I 120'
120'
! 120'
| 150'
144 '
148 '
148 '
150 '
150 1
14 0'
86*
-0"
-0"
-2"
-2"
-1"
-1"
-10'
-10'
-1"
-2"
-2"
-0"
-0 "
-0"
-0"
-0"
-0"
-0"
-0"
-0"
-0"
-0"
-6"
-6"
-0"
-0"
-0"
-0"
76000
77000
76000
76000
76000
76000
76000
76000
76000
76000
73000
71000
72000
75000
72000
73000
73000
73000
73000
30000
S5000
112000
120000
120000
125000
125000
143000
5000
cok:f
FLOAT
FLOAT
CONE
FLOAT
It
OPEN
COKE
i
A~CTU:S PLANT
PRESSURE
TANK
YES-N'O
NO
AIR
POLLUTION
CONTROL |
EQUIPMENT
TY?E OF MATERIAL
STORED
ONS .VEMT
VAP.REC.
CONS.VENT
VAJL-REC .
v. lior^c
VAP.REC.
VAP.REC.
CONS.VEMT
FLOATROOF
PRIKARY
CRUDE
SLOP "OIL
GAS OIL
FUEL OIL
GAS OIL
>1 tt
GASOLINT
NONE
FLOAT
CONS.VENT
FLOATROOF
NONE
FUME VAP.
RECOVERY
ALTERNATE
RED.CRUDE
WATER
GASOLINE
CAS OIL
CRUDE
II
WST.WTR.
GASOLINE
WATER
H2S04
Tr-Ui.. VAjPCR
PRESSURE CF !
?ri:l\ry pp.CD-.-cr! x.-.::.:
PS IA !
A^C.v f T i-\ i.
AVG.
0
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3
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121
135
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76
150
104
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76
75
81-.
70 -
67
6 6
74
79
6 6
7 C
112 -
100
91
SO .
63
cLnir ier.'
. I
-1
-------
Texaco
G. STOPAGE VESSELS- ^'O 1 I Ln\r; esjic; TrwMixaT,
1
c-\: \c:ty
EX—ELS
TiPF OF
TA OR
"OOF
SlO^CHGED
FILL
\Z5-\0
PRESSURE
T7i\K
YES-MO
AIR
poLL'jTin;:
CONTROL
EQUIPMENT
—
TYPE OF "iATSRIAI#
STORLD
TRUE VAPOR
PRESSURE OF
?RI!'.ARY PRODUCT
V SI h
TA2CK 7E
-
o
J
^ (
n z? £
TV
-------
"Te\
TZ VEESEES •
SULFUR RECOVERY PLANT
T RUc.
VAPOR
- •*
P?^ZS5*
J RE OF
_ J
AIR
PRIMARY PRODUCT
TANK TEMPERATtrPj: 1
DATE
TYPE OF
SU3MERGED
PRESSURE
POLLUTION-
TYPE OF
"AT
ERIAL
PS IA
°F. ¦ i
7
A^"K
BUILT OR
DIAMETER
CAPACITY
TANK OR
FILL
TANK
CONTROL
STORED
ANNUAL
SEASONAL
SEASONAL-
^TTtBETR
I'ODIFIED
FEET
BARRE LS
ROOF
YES-NO
YES-NO
EQUIPMENT
PRIMARY
AL
? EPA ATE
A*'G.
."AXI^UM
AVERAGE
KAXIIIUTi
17-1231)
1973
lO'-O"
420
-
YES
-
LP^
-
122
145
67
80
3II
T-* 3«)
6 5
5 1 -0 "
28
PIT
NO
NO
VAP.REC.
SUL^-J'
-
0
0
300
320 •-
:3
7-93 4)
57
5 1 - 0 "
28
-
tf
II
" I ON E
!2S04-98%
-
0
0
nbient
-
"5 .~
12-1305;
74
5' -0"
IS
OPEN
II
• 1
NONE ti'EM. MIX
-
0
0
103
150'
2'i
17-1506)
74
lO'-O"
250
FLAT
It
II
NDNE
NaOH
-
0
0
93
150
: 22
7-10 4)
57
14'-0"
420
CONE
It
VAP . *CL
-
0
0
100
105
3 0
12-1903)
74
2 81-0 M
1930
OPEN
II
It
NONE
-
0
0
100
105
335
12-1904)
74
28'-0"
1980
OPEN
"
l»
rnMr
II
11
-
0
0
130
105.
CZ
T-502)
67
25'-0"
1900
CONE
YES
II
VAP.REC.
DEA |
-
0
0
110
130 *
133
17-1904)
74
25'-0"
2100
CONE
II
II
30NSV.VENT
^UEL OIL
-
0
0
ancient
-
""3
7-533)
65
451-0"
7000
CONE
NO
It
VAP.REC.
SULFUR
-
0
rt
TC.
300
__
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65
4 5'-C"
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tl
t!
ii ii
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300
1 »
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tl
NONE
stretfpr:
•
-
0
0
100
105
7-631)
- , 28
"
lO'-O"
28
PIT
If
n
VAP.REC.
SULFUR
0
0
300
jr
320
-¦
;
-i
-------
APPENDIX F
SULFUR PLANT DETAILS
-------
ACID GAS FROM
AYiNEREGEN- -
ERATOR AND SOUR
WATER STRIPPER
CZ.
«~"> Q
So
o ^
<8
sc_
SOUR WATER
&
SOUR WATER SURGE
TO TREATMENT
SECONDARY CONVERTER
STEAM
PRIMARY CONVERTER
WASTE HEATv. ^ .
BURNER ,
STEAM'
CONDENSERS
I «
A RBLOWER
1 1
1 ]
i
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! !
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BOILER FEED WATER
STEAM
0
J
•— ~¦ \
J
~
J
TAIL GAS TO
INCINERATOR OR
TAIL GAS PROCESS
LIQUID SULFUR PRODUCT
SULFUR TAKK AND SUw.P PUMP
Typlca! packaged claus plant (2 stage).
-------
HYDROGENATF.D
COOLED TAIL GAS
CLEAN GAS
TO H2S RHCOVERY
SULFUR PLANT
TAIL GAS
REACTOR
AIR
FUEL GAS
SULFUR
MELTER
AIR
FILTER
SULTL
FROTH
LIQUOR RETURN SULFUR
TYPICAL BEVON-STRETFORD TAIL GAS UNIT
-------
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-------
APPENDIX G
VIOLATION NOTICES ISSUED TO TEXACO, INC.
BY THE LAAPCD
-------
TEXACO INCORPORATED
2101 East Pacific Hwy.
Wilmington, California
DATE OF VIOLATION NOTICE NO'S EQUIPMENT
October 23, 1962
Ct. I Sect. 24281
Rule 56 Rules &
Regulations H&S
October
Count I j
24242 K
-------
Compiled 10/16/7;
DATE OF VIOLATION
TEXACO, INC.
23203 S. Alameda Street
Carson, California
COURT CASE RECORD
NOTICE NO'S EQUIPMENT
DISPOSITION
COURT &
March 11, 1975
Ct. I: Rule 50
May 24, 1975
Ct. I: Sec. 24242
R-OSSO
56986
FA-^703
57491
Sulfur recovery unit
No. 300
Arraignment 5/12/75 Corp-on
Plea nolo contendere M22I323
$125.00 fine paid
6 mos. sum probation
limited to unit -^300
Sulfur recovery Arraignment 8/18/75 Compton
Unit No. 750 incinerator Plea nolo contendere M224269
$200.00 fine paid
M 499
-------
lit-
TEXACO, INC.
Los Angeles, California Refinery
SUMMARY AND CONCLUSIONS
3
Texaco, Inc., operates an 11,900 m (75,000 bbl)/day integrated
crude oil refinery in Wilmington, a suburb of Los Angeles, California.
An air pollution related inspection of these facilities was conducted by
NEIC personnel on October 30-31, 1975 at the request of Region IX, EPA.
Substantial amounts of process and air pollution control equipment
information were requested of, and received from, Texaco. The Los
Angeles Air Pollution Control District (LAAPCD) was requested to supply
information pertaining to stack testing conducted at this facility and
any violation notices issued to Texaco.
The following conclusions were derived based on the inspection
and information obtained:
1. With the exception of the exhaust gases from steam boilers
No. 1,3 and 5 (common stack), no visible emissions were noted from
any of the process units. A problem associated with the alkalation
process introduced excessive hydrocarbons into the line which feeds
mercaptan waste gases to the fireboxes of boilers No. 1,3 and 5.
The hydrocarbons upset the air/fuel ratio and caused approximately
15-20 minutes of 80-100% opacity exhaust emissions from the common
stack serving these boilers.
2. All equipment at this refinery is operating under a valid
LAAPCD permit.
3. General housekeeping at this refinery is very good.
4. Moderately strong sulfide/mercaptan odors were detected on
both days in the area near the delayed coking units. Very strong
sulfide/mercaptan odors were noted near the fluid catalytic
cracking (FCC) unit on October 31, 1975. The sources of these
odors were not determined.
-------
5. Calculations made using EPA emission factors in-
dicate that the emissions from the CO boiler attendant to the
FCC unit exceed the allowable rates under LAAPCD Rule 54. Stack
tests on this unit conducted by the LAAPCD on May 22, 1974 in-
dicated that it was operating in compliance with all LAAPCD rules.
6. Using EPA emission factors, the process heaters and
boilers at this facility appear to be significant sources of
nitrogen dioxide. There are no LAAPCD regulations which apply
to these units.
7. A stack test conducted by the LAAPCD (November 10, 1974) on
the Beavon-Parsons tail gas treating unit at the sulfur recovery
plant indicated that this unit complied with Rule 53.2. A pre-
vious LAAPCD test on this unit (September 19, 1974) indicated
non-compliance with this rule. It is not known what modifications
were made to the unit between the two tests.
8. Two violation notices were issued to Texaco by the LAAPCD
during 1975. Both violations were related to the sulfur recovery
plant.
RECOMMENDATIONS
1. Texaco should be required to stack test the Beavon-Parsons
sulfur plant tail gas treatment unit at least once per year.
2. Texaco should be required to stack test the CO boiler exhaust
at the mid-point of each FCC unit turnaround period.
3. Reports of the above tests should be provided to the Enforcement
Division of the LAAPCD and to the Director, Enforcement Division,
USEPA, Region IX.
------- |