i-6QO/3-75-010b
itember 1975
Ecological Research Series
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development,
U.S. Environmental Protection Agency, have been grouped into
five series. These five broad categories were established to
facilitate further development and application of environmental
technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in
related fields. The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ECOLOGICAL RESEARCH series.
This series describes research on the effects of pollution on
humans, plant and animal species, and materials. Problems are
assessed for their long- and short-term influences. Investigations
include formation, transport, and pathway studies to determine the
fate of pollutants and their effects. This work provides the
technical basis for setting standards to minimize undesirable
changes in living organisms in the aquatic, terrestrial and
atmospheric environments.
This document is available to the public through the National
Technical Information Service, Springfield, Virginia 22161.
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EPA-600/3-75-010b
September 1975
ANNUAL CATALYST RESEARCH PROGRAM REPORT APPENDICES
Volume I
by
Criteria and Special Studies Office
Health Effects Research Laboratory
Research Triangle Park, North Carolina 27711
U.S. ENVIRONMENTAL PROTECTION AGENCY
OFFICE OF RESEARCH AND DEVELOPMENT
HEALTH EFFECTS RESEARCH LABORATORY
RESEARCH TRIANGLE PARK, NORTH CAROLINA 27711
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CONTENTS
Page
CATALYST RESEARCH PROGRAM ANNUAL REPORT
EXECUTIVE SUMMARY 1
INTRODUCTION 5
PROGRAM SUMMARY 7
. TECHNICAL CONCLUSIONS 17
DISCUSSION 22
REFERENCES 45
APPENDICES TO CATALYST RESEARCH PROGRAM ANNUAL REPORT
VOLUME 1
A. OFFICE OF AIR AND WASTE MANAGEMENT
AT. AUTOMOTIVE SULFATE EMISSIONS 1
A2. GASOLINE DE-SULFURIZATION - SUMMARY 53
A2.1 Control of Automotive Sulfate Emissions
through Fuel Modifications 55
A2.2 Production of Low-sulfur Gasoline 90
VOLUME 2
B. OFFICE OF RESEARCH AND DEVELOPMENT
Bl. FUEL SURVEILLANCE
B1 .1 Fuel Surveillance and Analysis 1
B1.2 The EPA National Fuels Surveillance
Network. I. Trace Constituents in Gasoline
and Commercial Gasoline Fuel Additives . . 19
B2. EMISSIONS CHARACTERIZATION
B2.1 Emissions Characterization Summary .... 44
B2.2 Sulfate Emissions from Catalyst- and Non-
catalyst-equipped Automobiles ........ 45
B2.3 Status Report: Characterize Particulate
Emissions - Prototype Catalyst Cars .... 68
B2.4 Status Report: Characterize Particulate
Emissions from Production Catalyst Cars . . 132
B2.5 Status Report: Survey Gaseous and Particu-
late Emissions - California 1975 Model Year
Vehicles 133
B2.6 Status Report: Characterization and Meas-
urement of Regulated, Sulfate, and Particu-
late Emissions from In-use Catalyst Vehicles -
1975 National Standard 134
B2.7 Gaseous Emissions Associated with Gasoline
Additives - Reciprocating Engines. Progress
Reports and Draft Final Report - "Effect of
Gasoline Additives on Gaseous Emissions". 135
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VOLUME 3
Page
B2.8 Characterization of Caseous Emissions from
Rotary Engines using Additive Fuel -
Progress Reports 220
B2.9 Status Report: Exploratory Investigation of
the Toxic and Carcinogenic Partial Combus-
tion Products from Oxygen- and Sulfur-
containing Additives 232
B2.10 Status Report: Exploratory Investigation of
the Toxic and Carcinogenic Partial Combus-
tion Products from Various Nitrogen-
containing Additives 233
B2.11 Status Report: Characterize Diesel Caseous
and Particulate Emissions with Paper "Light-
duty Diesel Exhaust Emissions" 234
B2.12 Status Report: Characterize Rotary Emissions
as a Function of Lubricant Composition and
Fuel/Lubricant Interaction 242
B2.13 Status Report: Characterize Particulate
Emissions - Alternate Power Systems (Rotary) . . 243
B.3 Emissions Measurement Methodology
B3.1 Emissions Measurement Methodology Summary. . . 1
B3.2 Status Report: Develop Methods for Total
Sulfur, Sulfate, and other Sulfur Compounds
in Particulate Emissions from Mobile Sources ... 2
B3.3 Status Report: Adapt Methods for SO2 and SO3
to Mobile Source Emissions Measurements 3
B3.4 Evaluation of the Adaption to Mobile Source
SO~ and Sulfate Emission Measurements of
Stationary Source Manual Methods 4
B3.5 Sulfate Method Comparison Study. CRC APRAC
Project CAPI-8-74 17
B3.6 Determination of Soluble Sulfates in CVS
Diluted Exhausts: An Automated Method 19
B3.7 Engine Room Dilution Tube Flow Characteristics. 41
B3.8 An EPA Automobile Emissions Laboratory 52
B3.9 Status Report: Protocol to Characterize Gaseous
Emissions as a Function of Fuel and Additive
Composition - Prototype Vehicles 89
B3.10 Status Report: Protocol to Characterize Particu-
late Emissions as a Function of Fuel and Additive
Composition 90
B3.11 Interim Report and Subsequent Progress Reports:
Development of a Methodology for Determination
of the Effects of Diesel Fuel and Fuel Additives
on Particulate Emissions 192
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Page
B3.12 Monthly Progress Report #7: Protocol to
Characterize Caseous Emissions as a Function
of Fuel and Additive Composition 200
B3.13 Status Report: Validate Engine Dynomometer Test
Protocol for Control System Performance '. '. '. . . . 218
B3.14 Fuel Additive Protocol Development 221
B3.15 Proposed EPA Protocol: Control System
Performance 231
VOLUME 4
B3.16 The Effect of Fuels and Fuel Additives on Mobile
Source Exhaust Particulate Emissions 1
VOLUME 5
B3.17 Development of Methodology to Determine the
Effect of Fuels and Fuel Additives on the Perform-
ance of Emission Control Devices 1
B3.18 Status of Mobile Source and Quality Assurance
Programs 260
VOLUME 6
B4. Toxicology
B4.1 Toxicology: Overview and Summary 1
B4.2 Sulfuric Acid Effect on Deposition of Radioactive
Aerosol in the Respiratory Tract of Guinea Pigs,
October 1974 38
B4.3 Sulfuric Acid Aerosol Effects on Clearance of
Streptococci from the Respiratory Tract of Mice.
July 1974 63
B4.4 Ammonium and Sulfate Ion Release of Histamine
from Lung Fragments 89
B4.5 Toxicity of Palladium, Platinum and their
Compounds 105
B4.6 Method Development and Subsequent Survey
Analysis of Experimental Rat Tissue for PT, Mn,
and Pb Content, March 1974 128
B4.7 Assessment of Fuel Additives Emissions Toxicity
via Selected Assays of Nucleic Acid and Protein
Synthesis 157
B4.8 Determination of No-effect Levels of Pt-group
Base Metal Compounds Using Mouse Infectivity
Model, August 1974 and November 1974 (2
quarterly reports) 220
B4.9 Status Report: "Exposure of Tissue Culture
Systems to Air Pollutants under Conditions
Simulating Physiologic States of Lung and
Conjunctiva" 239
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Page
B4.10 A Comparative Study of the Effect of Inhalation of
Platinum, Lead, and Other Base Metal Compounds
Utilizing the Pulmonary Macrophage as an Indicator
of Toxicity 256
B4.11 Status Report: "Compare Pulmonary Carcinogenesis
of Platinum Group Metal Compounds and Lead Com-
pounds in Association with Polynuclear Aromatics
Using [n_ vivo Hamster System 258
B4.12 Status Report: Methylation Chemistry of Platinum,
Palladium, Lead, and Manganese 263
VOLUME 7
B.5 Inhalation Toxicology
B5.1 Studies on Catalytic Components and Exhaust
Emissions 1
B.6 Meteorological Modelling
B6.1 Meteorological Modelling - Summary 149
B6.2 HIWAY: A Highway Air Pollution Model 151
B6.3 Line Source Modelling 209
B.7 Atmospheric Chemistry
B7.1 Status Report: A Development of Methodology to
Determine the Effects of Fuel and Additives on
Atmospheric Visibility 233
Monthly Progress Report: October 1974 255
B7.2 Status Report: Develop Laboratory Method for Collec-
tion and Analysis of Sulfuric Acid and Sulfates . . . 259
B7.3 Status Report: Develop Portable Device for Collection
of Sulfate and Sulfuric Acid 260
B7.4 Status Report: Personal Exposure Meters for
Suspended Sulfates 261
B7.5 Status Report: Smog Chamber Study of SO
Photo-oxidation to SOa under Roadway
Condition 262
B7.6 Status Report: Study of Scavenging of SO and
Sulfates by Surfaces near Roadways 263
B7.7 Status Report: Characterization of Roadside
Aerosols: St. Louis Roadway Sulfate Study .... 264
B7.8 Status Report: Characterization of Roadside
Aerosols: Los Angeles Roadway Sulfate Study . . . 269
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VOLUME 8
B.8 Monitoring
B8.1 Los Angeles Catalyst Study. Background Pre-
liminary Report <
B8.2 Los Angeles Catalyst Study; Summary of Back-
ground Period (June, July, August 1974) 13
B8.3 Los Angeles Catalyst Study Operations Manual
(June 1974, amended August 1974) 33
B8.4 Collection and Analysis of Airborne Suspended
Particulate Matter Respirable to Humans for
Sulfates and Polycyclic Organics (October 8, 1974) . . 194
VOLUME 9
B.9 Human Studies
B9.1 Update of Health Effects of Sulfates, August 28, 1974 1
B9.2 Development of Analytic Techniques to Measure
Human Exposure to Fuel Additives, March 1974- ... 7
B9.3 Design of Procedures for Monitoring Platinum
and Palladium, April 1974 166
B9.4 Trace Metals in Occupational and Non-occupation-
ally Exposed Individuals, April 1974 178
B9.5 Evaluation of Analytic Methods for Platinum and
Palladium 199
B9.6 Literature Search on the Use of Platinum and
Palladium 209
B9.7 Work Plan for Obtaining Baseline Levels of Pt
and Pd in Human Tissue 254
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Automotive Sulfate Emissions
Summary
The use of oxidation catalysts, starting in 1975, to control hydrocarbon
and carbon monoxide emissions from motor vehicles has introduced the potential
problem of high localized sulfate levels in the vicinity of multilane high-
ways and in street canyons with relatively stagnant air masses. In non-
catalyst equipped vehicles, the sulfur contained in the gasoline is emitted
almost entirely as $02 While the S02 from automobiles is eventually oxi-
dized to form sulfate, it is usually finely dispersed beforehand and makes
up only a small fraction, less than 1%, of the total SO;? burden to the at-
mosphere, the scenario for catalyst-equipped vehicles is slightly different.
Some of the S02 formed in the combustion process is further oxidized to $03
by the catalyst. The $63 is immediately converted to sulfate which could
cause high localized sulfate concentration levels at street level in the
vicinity of dense traffic situations.
The purpose of this report is to summarize the results of industry and
OMSAPC investigations on sulfate emissions from automobiles and to make
conclusions based on these results. (The details of the ORD work are to
be summarized in a parallel report). There is not complete agreement on
emission levels for various types of catalysts and test conditions, due
primarily to two factors. The first factor is storage of sulfates. Sulfates
are stored on the catalyst under some operating conditions and released under
others. The emission rate of sulfates over any particular period, therefore,
is dependent on the previous operating history of the catalyst. The second
problem revolves around analytical methods. Considerable progress has been
made in these areas and it appears that a concensus is emerging on analytical
methods. For these reasons, this report includes much detail about the test
conditions and analytical methods to help understand and explain the dis-
crepancies in the data. This understanding is not complete at this time.
Non-catalyst Vehicle Sulfate Emissions.
Non-catalyst equipped vehicles have very low sulfate emission levels
according to most investigations. EPA-ORD, GM, Ford and Exxon have reported
sulfate emissions to be less than 1% of the fuel sulfur (less than 0.001 gpm),
using a generally accepted analytical technique. Chrysler and preliminary
EPA-OMSAPC tests, using another analytical method, indicate conversion of
10 to 20% of the fuel sulfur to sulfates. However, this analytical method
has not been validated sufficiently for automotive sulfate emissions and may
be inaccurate.
Catalyst Vehicle Sulfate Emissions.
Work by GM and Exxon shows that pelleted catalysts have substantially
lower .jlfate emissions than monolith catalysts, over the EPA Federal Test
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Procedure, a low speed urban driving test. This work also shows that sulfates
are being stored on the pelleted catalyst under operating conditions found
during the FTP. This storage occurs to a much smaller extent on the monolith
catalyst which has much less alumina available for interaction with the sul-
fates. The storage phenomenon for the pelleted catalyst is expected to be a
temporary one with later release of sulfur compounds under higher speed
driving conditions which result in higher catalyst temperatures. It appears
that the stored sulfates might be released as both S02 and sulfate.
Work by GM, Ford, and Exxon show pelleted and monolith catalysts to
have almost identical sulfate emissions at 60 mph.
Typical emission factors obtained with a 0.03% sulfur fuel, the current
national average, are given below:
Driving Schedule Catalyst Investigator Sulfates (gpm)
1972 FTP Monolith GM 0.03
Pelleted GM 0.009
Pelleted GM 0.002
(No air injection)
1975 FTP Monolith Exxon 0.07
Pelleted Exxon 0.02
60 mph Monolith Exxon 0.05
Monolith Ford 0.06
Monolith GM 0.05
Pelleted Exxon 0.06
Pelleted Ford 0.05
Pelleted GM 0.05-0.07
Composite emission factors are as follows with the overall factor based on
65% pelleted and 35% monolith catalysts.
Driving Schedule Catalyst Sulfates (gpm)
FTP Monolith 0.05
Pelleted 0.01
Overall 0.02
60 mph Monolith 0.05
Pelleted 0.06
Overall 0.06
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The overall estimate for low speed driving conditions of the FTP is somev/hat
lower than the 0.05 gpm assumed by EPA in the earlier information submitted
to the Senate Public Works Committee. The 0.06 gpm value for 60 mph conditions
is slightly higher than this 0.05 gpm value.
Sulfate Emission Control.
It is not known to what degree catalyst parameters can be optimized for
low sulfate emissions and still have satisfactory HC and CO control. n 2-
liminary results from GM on the cars without air injection are much lower,
even at 60 mph for the one test run, than the cars with air injection. Close
control of the exhaust oxygen level may result in much lower sulfate emis-
sions. Furthermore, it is not known whether or not automotive sulfate traps
are feasible. Investigations are continuing in these areas.
Current Investigations.
The OMSAPC has programs underway to assess control technology for sulfates
and obtain characterization data. The ORD is continuing to develop measure-
ment methods, obtain characterization data, do air quality modeling and obtain
health effects data. The OAQPS is investigating the feasibility of fuel
desulfurization and assisting in the air quality modeling.
The OMSAPC has a contract underway with Exxon Research and Engineering
to perform four major tasks in assessing automotive sulfate control technology.
Task 1, which is essentially complete, is to conduct a literature search on
S02 oxidation, 503 hydration, kinetics and catalysis of these reactions, and
to determine potential trap materials. Task 2 is to assess emissions from
non-catalyst vehicles including a 1974 production vehicle, a rotary engine
equipped vehicle, a Honda CVCC and a Diesel car. Task 3, to determine factors
affecting oxidation of S02 will be started as soon as 1975 production vehicles
are available. Air injection rate, catalyst formulation, catalyst temperature,
and catalyst residence time will be studied. Task 4 is to evaluate the feasi-
bility of sulfate traps. Tests are underway on a calcium oxide trap.
The second OMSAPC contract, being conducted by Southwest Research Institute,
is to obtain S02 and sulfate emission data on monolith, pelleted, and dual
catalyst equipped vehicles, a pre-1973 vehicle, a 1975 non-catalyst car, and
Diesel and stratified charge engine equipped vehicles. Sulfate emissions will
be measured on the two oxidation catalyst equipped vehicles through 15,000 miles,
The scheduled completion date for both contracts is March, 1975.
The OMSAPC in-house work is directed towards determining sulfate emis-
sion factors. Measurements are made over the 1975 FTP, the Hiway Economy
Cycle and at 60 mph steady state.Twelve vehicles have been tested to date,
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1975 GM and Ford catalyst prototypes, a Gould dual catalyst vehicle at 0 and
25,000 miles, Mercedes and Peugeot Diesels, a Dresser carburetor equipped
vehicle, a Honda CVCC, a 1977 Ford catalyst prototype, a Ford stratified
charge vehicle with catalyst, a Volvo with three way catalyst and a 1974
Ford without catalyst. Arrangements have been made to continue testing
the Volvo three way catalyst vehicle and the 1975 GM catalyst prototype
vehicle plus the testing of a Texaco stratified charge vehicle, a 1977 GM
catalyst prototype and GM, Ford and Chrysler production vehicles. Future
plans include testing of HD Diesels for ^ulfate emissions.
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Automotive Sulfate Emissions
Introduction
The purpose of this paper is to summarize most of the currently av^;l
able emission data for sulfates from catalyst and non-catalyst vehicles.
These data include recent tests run by the automobile and petroleum companies
and are in both published literature and information submitted to the Senate
Public Works Committee and to EPA. The Senate Public Works Committee held
Hearings in November, 1973 on sulfate emissions from catalyst vehicles and
received extensive information from various groups including the automobile
and petroleum companies. On March 8, 1974, an EPA request for information on
automotive sulfate emissions was published in the Federal Register. The
automotive, petroleum, and other companies sent extensive test data to EPA
in response to this notice. Furthermore, EPA requested reports from the
automotive companies on their progress in meeting the 1975-76 automotive
standards. In this request, EPA also asked for data on unregulated emissions
such as sulfates. These reports, sent to EPA last November, included data
on sulfate emissions.
This paper discusses all of the above information and also includes
data obtained from tests run by the EPA Office of Mobile Source Air
Pollution Control (OMSAPC). Emission data obtained by the EPA Office of
Research and Development (ORD) are not included in this report but are
included in a separate report parallel to this one.
An EPA report was submitted earlier this year to the Senate Public
Works Committee summarizing all data available for sulfates. This paper
by the OMSAPC provides additional technical data on some aspects of the
report sent to Congress. Hov/ever, this paper covers only sulfate emissions
and does not cover other possible unregulated emissions such as polycyclic
organic matter, reactive organics, hydrogen sulfide, platinum, other noble
metals, and nickel compounds.
Section 1 - Particulate Emissions
It is important to understand particulate emissions from non-catalyst
cars as background before examining particulate and sulfate emissions from
catalyst equipped vehicles. Non-catalyst vehicle particulate emissions
should be considered for both leaded and unleaded fuel. The following two
sections will briefly discuss particulate emissions for leaded and unleaded
fuel. These discussions are not meant to be comprehensive (i.e., include-.
all published work) but rather to summarize recent work reported by the
automobile companies in their 1973 status reports to EPA and in their testi-
mony before the Senate Public Works Committee in November 1973,
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1.1 Particulate Emissions with Leaded Fuel
Non-catalyst type cars, especially older ones (e.g., pre-1971 vehicles)
with higher compression ratio engines, have used leaded gasoline which
contained an average of about 2.5 g/gallon of lead in the form of lead
alky! compounds. This corresponds to an input to the engine of 0.18 gpm
of lead assuming a 13.5 mile/gallon fuel consumption. Approximately 80-
90% of this is emitted to the atmosphere with the remainder trapped in the
engine and exhaust system. The emitted lead is in the form of various
halide and oxyhalide compounds. Thus, about 0.15 gpm of lead is emitted,
not including the weight of the halide or oxyhalide part of the compound.
Extensive work done by various investigators and by EPA (both in-house
and by contract, such as contracts EHS 70-101 and CPA-22-69-45 with Dow
Chemical Company) have shown total airborne particulate emissions from
non-catalyst vehicles operated on leaded gasoline to be about 0.25 gpm.
Most of the 0.25 gpm are lead compounds. GM cites tests in its progress
report showing average emissions of 0.21 gpm (range of 0.13 to 0.33 gpm)
for seven vehicles using leaded fuel on the 1972 Federal Test Procedure (FTP).
1.2 Particulate Emissions with Unleaded Fuel
Most 1971 and later cars can use lower octane low lead or unleaded
fuels. Some manufacturers, such as GM, recommend the use of such gasoline
in their newer cars. Particulate emissions from non-catalyst cars using
unleaded fuel are substantially lower than leaded fuel.
EPA tests at Dow Chemical show particulate emissions with unleaded
fuel to be about 0.01-0.02 gpm under either 30 or 60 mph steady state or
a cold start type test. These particulates consist of carbon and various
higher molecular weight organic compounds. GM mentions that six cars tested
on the 1972 FTP showed an average emission of 0.03 gpm (range of 0.015 to
0.04 gpm). Ford cites a recent test done at a program they sponsored at
Battelle Laboratories showing a 0.01 gpm emission factor for a car using
unleaded fuel at 60 mph steady state.
1.3 Particulate Emissions from Catalyst Vehicles with Unleaded Fuel
Much less work has been done on total particulate emissions from catalyst-
equipped vehicles although sulfate emissions have received much more atten-
tion. The major work in this area was done by EPA through a contract with
Dow Chemical Company (EHS-70-101). Several catalysts were tested on an
engine dynamometer, and several catalysts were tested on vehicles. Both
noble metal monolith and base metal pelleted catalysts were tested. There
is some variation in particulate emissions from test to test. However,
generally the total particulate emissions with the catalyst and unleaded
fuel were far less than those obtained for non-catalyst cars with leaded
fuel but greater than those found for non-catalyst cars with unleaded fuel.
Typical particulate emission levels for the Engelhard monolith noble metal
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catalyst were about 0.03-0.08 gpm under either steady state conditions
(30 or 60 mph) or a cold start test. The emissions for the pelleted
catalysts tested were lower at approximately 0.02-0.05 gpm under the same
conditions. Ford work at Battelle Laboratories with noble metal monolith
shows particulate emissions of 0.12 gpm at 60 mph steady state.
These emission results and those mentioned earlier in Section 1 are
summarized in Table 1.
Section 2 General Aspects of Sulfate Emissions
The sulfur in gasoline (about 0.03% by weight) oxidizes to SO? in the
combustion process with very minute quantities of SO? also being formed.
It is important to note that on a national average S02 emissions from motor
vehicle are less than one percent of total S02 emissions from man made
sources. Atmospheric S02 is slowly oxidized to $03. However, automotive
oxidation catalysts apparently increase the amount of $63 directly emitted
from motor vehicles and may result in high localized sulfate levels.
Increased sulfate emissions from catalyst equipped vehicles were dis-
covered in 1972 in an analysis Ford did on particulate samples collected
by Dow under Contract EHS-70-101 with EPA. These samples were collected
from a vehicle equipped with an Engelhard noble metal monolith oxidation
catalyst. Abnormally high particulate emissions were obtained on this Ford
car even though it was operated with unleaded fuel. Some of the samples
were sent to Ford for detailed analysis which showed sulfuric acid. Since
this initial finding at the end of 1972, more extensive characterization
of sulfate emissions has been done by various groups including the OMSAPC
and the ORD of EPA, General Motors, Ford, Chrysler, and Exxon Research.
The results of this work, with the exception of the ORD work which is covered
in a separate report, will be summarized in the following sections.
The purpose of this work was not only to obtain sulfate emission factors
but also to determine what parameters affect sulfate emissions. Parameters
that could possibly affect sulfate emissions from catalyst equipped vehicles
include catalyst type (base or noble metal), catalyst substrate (pellet or
monolith), catalyst mileage, catalyst location, catalyst operating tempera-
ture, and air injection rate. For example, a fresh catalyst with higher
activity may result in increased S02 oxidation compared to a catalyst with
high mileage. Also, catalyst temperature may affect $03 formation since
the S02~S03 equilibrium shifts more to S02 at higher temperatures.
In addition to these factors, it is possible to "store" $03 on a catalyst
by reaction with the alumina type substrate. This storage could occur in
one driving condition, such as low speed driving with subsequent release in
another condition such as high speed driving. High speed driving results in
higher catalyst temperature which could decompose the aluminum sulfates
formeH >t lower temperatures. It is also possible to store and later release
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SO;? by similar reactions. This storage and release makes the previous
driving history of a catalyst vehicle very important. For example, sulfate
emissions obtained over the FTP from a vehicle previously operated at low
speed conditions may be somewhat higher than those on an FTP preceded by
high speed conditions. Also, it is possible that sulfate would be stored
during an FTP to be released later under high speed driving conditions.
The work done over the past year has determined the magnitude of the^j
factors to a preliminary extent.
The work done has used two basic sampling methods for automotive sulfate
emissions, the condensation method using a dilution tunnel and the absorp-
tion method using an isopropyl alcohol SOs scrubber. Most investigators
are using the condensation method.
the condensation method uses a dilution tunnel to mix the exhaust
approximately 10 to 1 with fresh air. A large blower displaces a constant
amount of gas mixture including both the entire exhaust volume and what-
ever volume of dilution air is required at any instant to hold the total
amount of gas constant. The exhaust gas and dilution air are mixed in the
dilution tunnel and a small isokinetic sample is withdrawn through a filter
trapping the particulates in the exhaust stream. This method can be used
with either a transient driving cycle such as the FTP or a steady state
driving condition. The amount of sulfate collected on the filter is measured
either by a wet chemistry technique or X-ray fluorescence spectroscopy. In
this method, S02 must be measured independently.
The absorption method has been adapted from the Volume 36, 247, December
23, 1971, Federal Register which gives a recommended method for measuring
$03 and sulfate emissions from stationary sources. This method involves
passing a small portion (about 0.5 CFM) of undiluted exhaust gas through
either a Greenburg Smith impinger or the smaller type impinger used in the
MBTH aldehyde method. The impinger contains an 80 percent solution of iso-
propyl which absorbs both SO? and sulfuric acid emissions. The isopropyl
alcohol inhibits ozidation of the S02 which passes through the impinger.
A second impinger in series follows the first one and contains a hydrogen
peroxide solution which oxidizes the S02 to 803 which is absorbed in the
solution. This method can be used to measure both SOs an^ S02 simultaneously.
Since undiluted exhaust gas is sampled, several sampling trains can be set
up to simultaneously make measurements before and after the catalyst as
well as at the tailpipe. Since this method takes a constant volume of un-
diluted exhaust regardless of the total exhaust flow (which varies greatly
under different driving conditions), a sample proportional to the total
exhaust can be taken only under steady state conditions. This method cannot
accurately determine sulfate emissions over a transient driving cycle such
as the FIP.
Theoretically, it would be possible to sample over a transient driving
cycle with this method using exhaust diluted by a CVS type system. However,
it is possible that the much lower level of H2S04 in the diluted exhaust
cannc-, be measured by this method.
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Genera] Motors, Ford, Ethyl, ORD, and OMSAPC have used the condensa-
tion method. Chrysler, OMSAPC, Ethyl, and, to some extent, GM have used
the absorption method. Ford also has used the Goksoyr-Ross method for
sulfate measurement which is described in Section 4.
SectipnJS - General Motors Work on Sulfates
General Motors has done extensive studies in the sulfate area including
work developing measurement procedures for sulfates and S02> developing
emission characterization data for sulfates, and determining what factors
affect sulfate emissions. These three areas are discussed in the following
three subsections.
3.1 6M_Work on Measurement Methods
The primary method used by GM to obtain sulfate emission data is the
condensation method with a dilution tunnel. All of the GM data discussed
in Section 3.2 was obtained by this method.
GM has run limited tests with the absorption method using the isopropyl
alcohol bubblers. The initial tests run by GM on the catalyst vehicle GM
loaned to EPA for testing involved a comparison of the condensation method
with the absorption method. The absorption method showed substantial sulfates
before the catalyst which indicates sulfates would also be found at these
levels in non-catalyst systems. However, none of the GM work on non-catalyst
cars discussed in Section 3.2 showed sulfates at this level from non-catalyst
vehicles. Even the after catalyst numbers by both methods do not agree
and show no clear trend. Table 2 summarizes these results.
TABLE 2
Comparison of Absorption and Condensation
Method for Sulfates
Sulfate Emissions (gpm)
Driving Condensation Absorption Method
Catalyst Cond. Method Before Cat. After Cat.
HN 2364 30 mph 0.013 0.009 0.018
60 mph 0.029 0.019 0.016
60 mph 0.039 0.006 0.025
10
-------
However, after completing the above tests, GM ran additional tests
on a non-catalyst car using the absorption method and found variable results.
In one case, with technical grade isopropyl alcohol in the impingers, no
sulfate emissions were found. In a second run when much purer reagent grade
alcohol was used, significant sulfate was measured from the non-catalyst
car. GM speculates that an impurity in the technical grade alcohol inhibited
S02 oxidation so that the method gives the correct result.
GM now feels that the absorption measurement is a valid way to measure
sulfates provided a second alcohol bubbler is used to check whether any
S02 oxidation occurred. GM feels much additional development work should
be done with the absorption method including cross checks between different
laboratories.
Another method to measure sulfates has been developed by GM involving
use of the TECO S02 instrument. First, the S02 content of the sample is
measured. Then, a sample is passed through a quartz tube held at about
1000°C which causes thermal decomposition of sulfuric acid to S02- The
S02 is measured again, which this time represents both the S02 and sulfate
originally in the sample.
GM feels that this instrumental approach could possibly be developed
to supplement or even replace the filter method. This analysis would be
much simpler than the filter analysis and could conceivably be used to
follow transients during a driving cycle.
3.2 GM^Emission Data
GM has measured sulfate emissions from about six non-catalyst vehicles
using the FTP or 60 mph steady state conditions. The results of these
tests are in Table 3 and show little sulfate formation without a catalyst.
TABLE 3
GM Non-catalyst Vehicle Sulfate Data
Vehicle Fuel Sulfur Level Test Sulfates gpm
1973 Chev. 0.02% 1972 FTP (8x) <0.001
1973 Chev. 0.15% 1972 FTP 0.003
1973 Pontiac 0.04% 1972 FTP 0.001
1973 Chev. 0.02% 60 mph <0.001
1973 rhev. 0.15% 60 mph 0.005
11
-------
GM has also conducted extensive measurement of sulfate emissions on
both monolith and pelleted catalysts over the FTP. Somewhat more limited
tests were run under other conditions such as 60 mph and other speeds.
GM measured sulfate emissions from catalysts with and without air injection
and found much higher results with air injection. The results of the GM
tests are given in Table 4. All of these measurements were taken with the
GM dilution tunnel. All of the data in this table is taken from tests using
0.03/i sulfur gasoline or from other tests normalized to a 0.03% sulfur level.
TABLE 4
GM Sulfate Emission Data
Catalyst
Pelleted
Monolith
Pelleted
Monolith
Pelleted
Pelleted
Metal
Pelleted
Pelleted
Monolith
Monolith
Mono! i th
Pelleted
Pelleted
Pelleted
Air
Yes
Yes
No
No
Yes
Base
Yes
No
Yes
Yes
Yes
Yes
No
No
No
Driving
Condition
1972 FTP
1972 FTP
1972 FTP
1972 FTP
60 mph
9
60 mphp
60 mph
60 mph3
30 mph3
40 mph3
60 mph3
10 mph3
30 mph3
60 mph3
Number of
Tests
23
8
6
2
3
2
1
2
1
i
i
i
i
3
Average Sulfate
gm/mt
.0095
.0258
.0018
.0012
.0737
.0224
.0127
.0481
.0618
.0757
.0485
.0000
.0088
.0438
2
3
This is an average (except for single test values) of the sulfate
figures after having been linearly normalized to a fuel sulfur
content of 0.03 wt.%.
Single test after FTP
Extended steady state tests
12
-------
These results show the pelleted catalyst seems to have much lower sulfate
emissions than the monolith catalyst over the FTP when both vehicles are
equipped with air injection. Without air injection, both monolith and pelleted
catalysts have even lower sulfate emissions. Interestingly, the limited
number of tests taken show pelleted and monolith catalysts to have sinuuir
sulfate emissions without air injection even over the FTP. One other point
to note is this preliminary work shows that HC and CO emissions seem to
increase significantly without air injection as shown by the results in Table
5 for two similar cars with the same type of pelleted catalyst but with and
without air injection.
TABLE 5
Effect of Air Injection on Gaseous Emissions
1975 FTP
Car Air Injection HC^ CfJ NOx gpm
0-39680 Yes 0.35 4.45 2.06
0-38608 No 0.94 11.44 1.91
However, the GM data show the pelleted and monolith catalysts to have
similar sulfate emissions at 60 mph. GM data also show the total amount
of sulfur compounds (i.e., S02 and sulfates) emitted at 60 mph for the
pelleted catalyst to be much greater than can be accounted for by the amount
of sulfur in the fuel. The S0£ readings were especially high. Apparently,
sulfur compounds stored on the catalyst at lower speeds are emitted at higher
speeds. The GM data indicate a large amount of S02 being released from the
catalyst at 60 mph. Possibly, much of the stored sulfur is released as S02
rather than sulfates. However, more work is needed to determine the magnitude
of sulfate emissions immediately after extended low speed operation.
Storage of sulfates on a catalyst is caused by a chemical reaction of
these compounds with the alumina. Sulfates interact with the alumina to
form sulfate salts. The large amount of alumina (6-7 pounds) in a pelleted
catalyst can result in a high storage of sulfur compounds. Since there is
insufficient alumina to store sulfates over the lifetime of the vehicle, the
stored sulfates must be later released.
The storage would be much less with a monolith catalyst which consists
of a lower mass cordierorite support coated with alumina. While the sulfur
compounds would react with the alumina to produce storage effects, it would
not react with the cordierorite support. The storage on the catalyst pellets
is reversible at higher temperatures resulting in a decomposition of the
aluminum sulfate salts.
GM measured sulfate emissions with fuels of various sulfur levels and found
sulfate emissions are proportional to fuel sulfur levels. However, the test
results do not necessarily show a linear reltationship as was assumed in de-
riving the data in T~b1e 4. This is in contrast to other test results such
as Exxon's which she1- a "! ;r:?ar relationship.
13
-------
3_.3_ Factors Affecting Sulfate Emissions
GM h-is done some preliminary work to determine how the following parameters
affect sulfate emissions:
Catalyst formulation
Catalyst temperature
Air injection rate
Space velocity
Regarding catalyst formulation, GM feels a pelleted catalyst emits
less sulfate than a monolith catalyst. This is true under FTP conditions
where large amounts of sulfates are stored on the pelleted catalyst. How-
ever, sulfate emissions are equivalent fror, the tv/o different types of
catalysts at 50 mph.
GM determined that noble metal loading has only a small effect on sulfate
emissions. A laboratory apparatus with engine exhaust and catalysts con-
taining 0.1% and 1.0% platinum were used for these tests.
Theoretically, catalyst temperature is expected to have a significant
effect en sulfate formation. The therriodynamic equilibrium constant for
S02 oxidation is such that higher temperatures lead to decreased sulfate
formation. However, if the reaction activation energy is sufficiently high,
a certain temperature is required to obtain a sizeable reaction rate. T'r.js,
at lower temperatures, the S02 oxidation reaction would be very slow and
at higher temperatures S02 will not oxidize. Catalysts operate most of the
time in the temperature range where SO? oxidizes readily. Lov/ temperature
operation is not feasible because HC and CO oxidation is also very slow.
High temperature operation results in poor durability.
GM did several experiments measuring S02 oxidation rates on pelleted
catalysts at various temperatures. These test results indicate that in-
creasing the catalyst temperature to 1200"F results in a slight increase
in sulfate emissions beyond which sulfate emissions decrease. Hcv/ever, S02
emissions increase greatly with increasing temperature. These tests suggest
that modifying catalyst temperature is not an effective control technique.
Additional work is necessary, including ,/ork with other catalysts and vehicle
tests, to confirm this preliminary conclusion.
One item of interest noted in these tests was that emissions of S0'2
and sulfates combined were less than the sulfur ir:put into the catalyst
at lower temperatures but increased with increasing temperatures. This
is due to storage of sulfur compounds on the pelleted catalyst at lc,;e^
temperatures which are released at higher temperatures. As the temperature
increases, the percentage of total sulfur ccmcounds represented by sulfates
decreases. More work is needed to determine quantities of sulfur compounds
released from a pelleted catalyst at various temperatures.
-------
Air injection rate is expected to affect sulfate formation in that
excess oxygen results in higher sulfate formation with all other cone! Hi or s
(e.g., catalyst temperature) being identical. Initial work in this area
was done by GM who measured sulfate emissions of catalyst cars with air
pumps and without air pumps. Substantial increases in sulfate om'ss'~'3
ware found in this preliminary work for both pelleted and monolith catalyst'-
with use of air pumps.
GM did some additional tests measuring the effect of two leve1" : f
oxygen on sulfate formation at five different temperatures. These results,
given in Table 6, show that a two-fold increase in oxygen level approyina ely
doubles the amount of sulfate found.
TABLE 6
Effect of Oxygen Level on Sulfate Formation
Catalyst %02 503 (ppm)
900°F 1000°F 11QO°F 1200°F 1300°F
O.U Pt. 1% 5.0 4.5 - 7.2 6.5
(A/F 15.4,
SV 28,000)
0.1% Pt. 2% 12.7 10.7 11.8
(A/F 16.2,
SV 17,500)
While these results show the effect of oxygen level on sulfate emissions,
they indicate no clear trend of catalyst temperature versus sulfates. This
is contrary to the earlier findings of sulfate emissions increasing with in-
creasing temperature up to 1200°F beyond which they decrease. However, these
results are very promising in that they indicate a large reduction of sulfates
with lower oxygen levels. Close control of air injection rate could be a
promising way to control sulfate emissions and should be investigated further.
Space velocity is, in effect, the total time period in which the exhaust
gas is in contact with the catalyst. It is expressed in bed volumes per
hour which indicate the total number of catalyst beds of a given volume
the exhaust gas could pass through in an hour. A smaller catalyst bed results
in a higher space velocity number. A larger catalyst bed generally results
in more effective HC and CO oxidation and is less likely to suffer "break
through", that is, unreacted exhaust gas passing through if the bed is too
small. However, a catalyst bed that is too large (i.e., a low space velocity
number) will have a very long warm-up period and high cold start emissions.
A trade-off is made between these two factors to define an optimum space
velocity. Sulfate emissions can also be affected by space velocity with a
low space velocity resulting in higher sulfate emissions. It should be
possible to add sulfates as another variable in defining optimum catalyst
sp? velocity.
15
-------
GM is the only company to date running tests to determine the effect
of space velocity on sulfate formation. These tests are summarized in
Table 7 and v/ere run at !200°F with a pelleted catalyst.
TABLE 1
Effect of Space Velocity on Sulfate Formation
Space Velocity
-1
7,000 hr
28,000 hr
-1
Sulfate Formation
18%
14%
These test results show greater sulfate emissions at the lower space velocity
which allows more time for the sulfate to form in the catalyst. This re-
sult suggests that sulfate formation is limited by reaction kinetics (i.e.,
reaction rates) rather than thermodynamics. Even though the effect of space
velocity is relatively small, it is, nevertheless, one more variable to con-
sider in designing a catalyst for low sulfate emissions.
These test results are very encouraging in that they indicate several
parameters which affect sulfate emissions. It is possible that a catalyst
could be designed for low sulfate emissions and still meet HC and CO standards,
Sectj_on 4 - _Ford_Motor Company Work on Sul fates
Ford analyzed the samples collected under the EPA contract with Dow,
in which sulfuric acid emissions were first found from catalyst vehicles.
Ford is currently exploring this problem by the following three phase program:
Phase 1 - This involves engine dynamometer testing at steady state
speeds to develop sampling and analysis methodology. Both
sulfate and S02 emissions are being analyzed as discussed
later.
Phase 2 - Emission data for sulfates and
vehicles using the 1975 FTP.
S02 will be obtained from
Phase 3 - The effects of parameters such as catalyst type and age,
temperature, oxygen level, and space velocity on sulfate
emissions will be determined. The mechanism of any sulfate
storage phenomenon will be investigated.
Ford has completed the first phase of this project by a contract with
Battelle Laboratories. Ford will start the second phase of this project
in-house later this year. Ford has already started the third phase of their
project using a small laboratory rig to simulate vehicle conditions..
16
-------
Ford measured sulfate emissions in the first phase of their program
by the following two methods:
(1) the dilution tunnel method using filters to collect
sulfates from a small stream of diluted exhaust.
(2) the Goksoyr-Ross method using a condensation coil to
condense sulfates from a small stream of undiluted
exhaust.
The condensation or dilution tunnel method is being used by other investi-
gators. Ford is the only investigator using the Goksoyr-Ross method which
involves condensing sulfuric acid from a small stream of undiluted exhaust.
The acfd is condensed in a glass coil at 60-90°C and measured by the
gravimetric method. The SC>2 passes through the coil uncondensed and is
removed by a hydrogen peroxide solution. The S02 sample collection and
analysis is identical to that in the absorption method described in Section
2. The Goksoyr-Ross method, like the absorption method, can only be used
for steady state conditions when concentrated exhaust is used.
The tests under phase 1 were run on an engine dynamometer at Battelle
and are summarized in Table 8.
TABLE 8
Ford Sulfate Emission Data
*
Catalyst Type Speed mph Number of Tests Average ^$04 gpm
None 60 5 0.0011
Monolith 60 8 0.057
AC Pelleted 60 2 0.051
AC Pelleted 30 2 0.074
* H2S04 figures have been normalized to .03 wt.% Sulfur fuel before
averaging.
Ford measured S02 in all of these tests to obtain a sulfur balance. Ford
also measured both S02 and sulfates at several places along the exhaust
system including both upstream and downstream of any catalyst present.
Ford ran tests only at 60 mph since they wanted to develop the measurement
methodology before obtaining emission data under other test conditions.
The Ford data at 60 mph are in excellent agreement with the GM and Exxon
data at 60 mph.
17
-------
The tests on the engine without a catalyst showed only very small
amounts of sulfate with almost all of the fuel sulfur recovered as S02-
Furthermore, Ford obtained an excellent material balance upstream of the
catalyst finding almost all of the fuel sulfur as S02 before the catalyst.
These results strongly indicate that very little sulfate is formed without
a catalyst.
Ford did extensive tests on monolith catalysts at 60 mph and more
limited tests on pelleted catalysts at 30 and 60 mph. Ford finds almost
no storage of sulfates on the monolith catalyst at 60 mph. However, Ford
finds significant storage of sulfates with the pelleted catalysts at both
speeds, especially when the catalysts are fresh. The magnitude of the
storage effect is shown in Table 9.
TABLE 9
Ford Sulfur Balances
Type of
Catalyst
Monolith
Speed mph
60
Pelleted, new
60
Pelleted, after
1300 mi. 60
Pelleted, "new",
after the
above 60 mph 30
Pelleted, after
1120 mi. at
30 mph 30
Total Particu-
late* gpm
0.14
0.10
0.12
0.11
0.29
Sulfur Compounds
SO3 SO4 S02 Lost in System
38+9% 53+5% 11+7%
Stored in Catalyst
28% 40% 32%
34% 40% 25%
31% 6% 63%
68% 12% 23%
* Particulate normalized linearly to .03 wt.% sulfur fuel.
No data are available yet from the third phase of the Ford program. A
laboratory rig with a small catalyst sample and synthetic exhaust gas is
being used for this study. Conditions such as catalyst formulation, catalyst
temperature, air injection rate, and catalyst residence time are being varied
to determine their effect on sulfate emissions.
18
-------
Section 5 - Chrysler Corporation Work
Chrysler Corporation has done extensive measurement of sulfate emis-
sions from both catalyst and non-catalyst cars using the absorption method.
Chrysler has also done considerable work to evaluate use of this method
Both areas will be discussed in the following sections.
5.1 _Chrysler Work on Method Development
Chrysler has used the absorption method for the work discussed in
Section 5.2. This method involves bubbling a small portion of undiluted
exhaust directly into a small impinger, the same type used in the MBTH
aldehyde measurement method, filled with an 80 percent solution of isopro-
pyl alcohol. The $03 and sulfates are measured by titration. Chrysler
measured the $62 directly with a DuPont Model 411 SC^ analyzer. Chrysler
did all of its measurements using a hot start 1975 FTP. As mentioned in
Section 2, it is not valid to use this type of sampling system, which
takes a small sample of undiluted exhaust at a constant flow rate, in a
transient driving cycle. A transient driving cycle gives various exhaust
flow rates which would result in a sample not proportional to the actual
emissions. However, Chrysler feels this sampling system is valid for indi-
cating trends in sulfate emissions. Chrysler feels it may be valid to
take 503 samples directly from a bag using the standard CVS-FTP test.
Chrysler took $63 bag samples from two cars using the absorption method.
The numbers compared well with those obtained from cars sampling concen-
trated exhaust over the FTP with the absorption method. However, the $03
(or sulfate) could be partially lost by condensation on the walls of the
bag which would introduce an error into this method. Even though these
results are encouraging much more work is needed to justify use of the
absorption method for bag samples. Comparisons with the condensation method
by different companies are needed.
Chrysler did extensive work to evaluate the validity of the absorption method.
The initial work was done in a tube furnace containing catalyst samples
and showed substantial formation of $03 over a catalyst. Samples of S02
and 62 passed through the empty tube furnace at 1000°F showed no sulfate teing
formed. However, exhaust components such as nitrogen oxides may affect
S02 oxidation in the sampling systems. Chrysler passed a mixture of S02,
02 > H20, NO, and CO through the empty tube furnace at 1100° and other
temperatures to address this point and found no 503.
In addition to the tube furnace work, Chrysler has done additional
tests with a single cylinder engine to justify the method. An engine test
was run with isooctane fuel containing no sulfur to see if non-sulfur ex-
haust components will give a positive $03 reading. Again, no $63 response
was noted. Chrysler then introduced some S02 into the exhaust system with
the engine presumably operating on isooctane fuel which would check whether
othe- ^xhaust components result in 503 formation. About five percent of
the jj£ was converted to S03, as reported to EPA on October 12, 1973, indi-
ing formation of SO; in either the exhaust or sampling system. Chrysler
19
-------
reported another test where S02 and nitrogen were introduced into the ex-
haust system of the engine running on isooctane fuel. No $03 was found
in this test probably because of the lower oxygen levels than in the pre-
ceding test. However, Chrysler reported another test to EPA on November
2, 1973, in which SC>2 was introduced into the exhaust system of the engine
running on isooctane fuel with no 863 being found.
Chrysler also did an experiment introducing S02 into the sample probe
which was at full operating temperature with the engine running on isooctane
fuel. No $03 was found. Chrysler then introduced SOg into the impinger
itself with the engine running on isooctane fuel and found no 803. Chrysler
did a third experiment adding particles from the exhaust systems, presumably
iron type compounds, and titrating the impinger solution without any exhaust
being passed through the system. The titration showed no 863 to be present
demonstrating the exhaust particles by themselves do not give a positive
503 reading. Chrysler then ran a sample of engine exhaust from a sulfur
containing fuel through the impinger system with exhaust system particles
in the impinger. The amount of 863 was 60 percent less than that found
without the exhaust system particles in the impinger. This indicates the
exhaust system particles somehow react with the 863, possibly by adsorption-
Chrysler has run several single cylinder engine tests with a catalyst
in the system and, in all cases, found increased 803 formation over the
catalyst. These tests Chrysler ran involved measuring sulfate emissions
from CVS bags identical to those used for HC, CO, and NOx emissions. This
involves dilution of the exhaust by a CVS type system which is the first
time the absorption method has been u^ed for dilute exhaust. In one of
these tests with 0.4 percent sulfur fuel, 120 parts per million (ppm) and
240 ppm of SOs were found before and after the catalyst respectively. An-
other single cylinder engine test using 0.4 percent sulfur fuel, which
would give 265 ppm of S02 if no $03 was present, showed 63 ppm 803 before
the catalyst and 77 ppm 803 after the catalyst.
5.2 Chrysler Vehicle Tests
Chrysler has conducted extensive vehicle tests using the absorption
method over a hot start 1975 FTP type test. As mentioned in Section 5.1,
the emission numbers were obtained using the absorption method over a trans-
ient driving cycle and are not accurate emission numbers.
Chrysler has tested a large number of non-catalyst cars and, contrary
to the results of other investigators, reported in Sections 3 and 4, has
found substantial sulfate emissions. Six 1975 non-catalyst prototypes,
two with air pumps and four running lean, were tested with both leaded and
unleaded fuel. One 1973 production car was tested with leaded and unleaded
fuel. The sulfate emission results and percent sulfate formed are listed
in Table 10.
20
-------
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21
-------
These results show slightly less than 20 percent conversion to sulfate
for non-catalyst cars using unleaded fuel. Less than 10 percent conversion
to sulfates occurs when leaded fuel is used. Leaded fuel results in the
formation of some lead sulfate which may not be measured by the absorption
method due to its slov; solubility. The lead sulfates may also be stored
temporarily in the exhaust muffler. However, it is significant that leaded
fuej_sjiowed_ 1 ower_ sulfate emissions than unleaded fuel. These results have~
not been confirmed by other investigators.
The percentage of fuel sulfur converted to sulfate was usually deter-
mined by the amount of SOs and 502 found in the exhaust rather than com-
paring the amount of SOs with the amount of fuel sulfur. Frequently, the total
amount of sulfur recovered was greater than the amount theoretically burned
in the engine. This is the reason why $03 emissions can be substantially
higher in one case (e.g., Car 185 with the air pump on versus air pump off)
with no change in percent sulfates and 502- A large part of this problem
is probably due to the sampling method used. It is also conceivable that
sulfates (e.g., iron sulfates) could be stored in the muffler in one driving
condition and emitted in another. At any rate, much more work is needed
on the sulfur balance to make firm conclusions.
Chrysler has also measured sulfate emissions from a number of vehicles
with pelleted and monolithic oxidation catalysts. The results of these
tests are given in Table 11.
TABLE 11
Catalyst Sulfate Emission Data from Chrysler
Modified 1975 FTP
Fuel Sulfur H2S04 Emis- Percent S Con-
Vehicle Percent sions gpm verted to H2S04
Car 411, 1975 Monolith
Catalyst (0 miles)
Before catalyst 0.1 0.20 23
After catalyst 0.1 0.29 34
Car 554, 1975 Pelleted
Catalyst
0 miles 0.014 0 0
200 miles 0.014 0.017 13
400 miles 0.014 0.023 19
20,000 miles (4 different 0.014 0.012 10
catalysts)
Car 554, Monolithic Catalyst
0 miles 0.014 0.010 9
200 miles 0.014 0.010 8
2,000 miles 0.014 0.012 10
50,000 miles 0.1 0.009 10
22
-------
These results show that a catalyst causes increased 502 oxidation but
a significant amount of $03 exists before the catalyst. The Chrysler tests
are the only tests other than the OMSAPC tests of EPA which show a signifi-
cant amount of sulfate from non-catalyst vehicles. More work is clearly
needed to determine if this is an actual phenomenon or caused by errors
in the measurement method.
5.3 Chrysler Tests of Catalyst Poisoning
Some very recent work has been done by Chrysler on lead poisoning of
catalysts. This work was reported by Dr. Maxwell Teague of Chrysler on
April 14, 1974 at an EPA sponsored symposium titled, "Health Consequences
of Environmental Controls: Impact of Mobile Emissions Controls". The paper
by Dr. Teague was titled, "$04 Emissions From Oxidation and Non-oxidation
Catalyst-Equipped Vehicles" and discussed, for the most part, the sulfate
emission data given in the OMSAPC progress report.
However, Chrysler also reported some engine dynamometer tests run with
various combinations of lead, ethylene dibromide, and ethylene dichloride
in gasoline. Ethylene dibromide and ethylene dichloride are added with
tetraethyl lead (or other alky! lead compounds) to serve as scavengers
insuring that lead is removed from the combustion chamber as the volatile
lead chloride or bromide type compounds. Chrysler ran tests with gasoline
containing the following additive combinations:
(1) lead additive (3 g/gal) with both ethylene dibromide and
ethylene dichloride
(2) ethylene dibromide and ethylene dichloride without lead additive
(3) lead additive by itself with no scavengers
(4) lead additive (2 g/gal) with ethylene dichloride only.
For each of the above four combinations, the catalyst conversion efficiency
on an engine dynamometer for HC and CO was monitored. A serious decrease
in catalyst efficiency was noted for the first two additive combinations,
(1) and (2). However, no significant change in catalyst efficiency occurred
for the last two packages.
This preliminary work indicates that ethylene dibromide poisons catalysts
while lead itself and ethylene dichloride have little poisoning effect.
Chrysler feels it may be possible to run catalyst equipped vehicles with
leaded fuel, provided no ethylene dibromide is used. Furthermore, the
presence of lead could perhaps lower sulfate emissions. Chrysler is con-
tinuing tests to see if engine and catalyst durability are satisfactory
for leaded fuel with ethylene dichloride scavenger. It is possible that
both ethylene dichloride and ethylene dibromide scavengers are required
when lead is used for satisfactory engine durability.
The EPA Office of Mobile Source Air Pollution Control on May 2, 1974
requested from Chrysler complete details of their tests and also requested
the comments of a few other automobile manufacturers, catalyst manufacturers,
gasoline additive manufacturers, and petroleum companies on these points.
23
-------
The responses to EPA have been analyzed. The primary conclusion made is
that leaded gasoline as it is currently formulated with both scavengers
will poison catalysts. Whether an engine can operate satisfactorily and
avoid valve problem on gasoline with lead only or lead and ethylene chloride
has not been established. Furthermore, the data from Ford, GM, and Exxon
indicate that lead by itself poisons catalysts. The contradictory data on
catalyst poisoning has yet to be resolved. Additional data are still re-
quired to assess whether operation of catalyst vehicles on fuel with lead
alone or lead and ethylene dichloride is feasible.
Section 6.1 - Exxon Research and Engineering Work
Exxon Research and Engineering has done extensive work on measuring
sulfate emissions from catalyst and non-catalyst vehicles. Exxon has also
done considerable work developing sampling procedures for particulates and
sulfates.
Exxon uses the condensation method with a dilution tunnel to measure
sulfates and has not used the absorption method. The Exxon dilution tunnel
has provisions to dehumidify and chill the incoming dilution air and can
take filter samples at lower temperatures (90°F) without water condensation
which usually occurs at these temperatures. While the Exxon dilution tunnel
is smaller in diameter than the one used by EPA, GM, and Battelle, it should
be just as effective for sulfate collection.
Exxon tested monolith catalyst, pelleted catalysts and non-catalyst
vehicles at 40 mph, 60 mph, and over the FTP. A summary of the Exxon re-
sults is given in Table 12.
TABLE 12
Exxon Research and Engineering Sulfate Emission Data
Catalyst
Monolith
Monolith
Monolith
Pelleted
Pelleted
Pelleted
None
None
Dnyjng_ Condition
1972 FTP
40 mph Cruise
60 mph Cruise
1975 FTP
40 mph Cruise
60 mph Cruise
1972 FTP
40 mph Cruise
Number of Tests Average Sulfates gpm
18
18
4
13
4
22
1
4
0.066
0.048
0.053
0.017
0.015
0.060
0.005
0.0004
These are averages of the sulfate figures after they have been
linearly normalized to a fuel sulfur content of 0.03 wt.%.
-------
These data show significantly greater sulfate emissions from the mono-
lithic catalysts than from the pelleted catalysts under FTP and 40 rnoh
conditions. However, both catalysts have similar sulfate emissions at
60 mph. For the monolith catalyst, this is equivalent to a 25-35% conversion
of the fuel sulfur to sulfate at 40 or 60 mph as well as the FTP. For trie
pelleted catalyst, this is equivalent to 5-10% over the FTP or 40 mph con-
ditions. At 60 mph, this is equivalent to a 25-35% conversion for the
pelleted catalyst. In all cases, the sulfate emissions were proportional
to fuel sulfur content.
These results agree with the GM results which show that the pelleted
catalyst stores sulfates at lower speeds where the catalyst temperature is
lower. However, this phenomenon is reversible and sulfur compounds are
released at higher temperatures which occur with higher speeds. It is ~
important to measure the amount of SU2 from catalyst cars to determine
a sulfur balance and the form in which these compounds are released.
Exxon also tested several non-catalyst vehicles for sulfate and $62
emissions. Exxon had difficulty measuring the low sulfate emissions over
the FTP but was able to obtain an accurate emission figure over an extended
40 mph cruise. The sulfate emissions at 40 mph were 0.004 gpm or 0.5% of
the fuel sulfur with the remaining fuel sulfur being converted to S02-
Section 7 -Ethyl...Corporation Work
Most of the Ethyl Corporation work has been on measurement methodology
with some limited work on obtaining emission factors on catalyst and non-
catalyst cars.
7.1 Ethyl Method Evaluation Work
Ethyl initially evaluated the absorption method by passing mixtures
of S02 through the impingers to see if any sulfate readings were obtained
from S02 oxidation in the impingers. Ethyl found a significant amount of
S02 trapped in the first impinger and measured as sulfate.
Ethyl feels this error is less when the first impinger contains sulfuric
acid which suppresses the solubility and oxidation of S02- This error
would be less for catalyst cars which emit sulfuric acid which is trapped
by the first impinger. Ethyl states that a spuriously high sulfate reading
would be found from non-catalyst cars. For catalyst cars, the error would
be smaller.
Ethyl tested this hypothesis through a modification of Method 8 by
adding a known amount of sulfuric acid to the first impinger. The amount
of sulfat- found from non-catalyst cars was lower than found previously.
Ethyl r- -es this modification lowers but does not eliminate the error due
to S^- oxidation.
25
-------
Ethyl also measures sulfate emissions by a modified condensation method.
This method does not involve a dilution tunnel but rather uses a large black
bag (100 m3 volume) which holds the entire vehicle exhaust from a test cycle
and sufficient dilution air to allow cooling and condensation of exhaust
particulates. Ethyl has used this system in the past to measure total
particulate, lead, and POM emissions. Ethyl finds that sulfates are lost
to the walls of the bag over extended time periods. Even though the exhaust
is in the dilution tunnel for only several seconds in the GM, Exxon, and
EPA methods, work should be done to insure no losses occur in the dilution
tunnel. Ethyl is still developing and validating their air dilution method.
Ethyl included in their submission complete analytical details for
their analysis techniques which are helpful to EPA and other investigators.
Ethyl uses an iodine method to anlayze the sulfates collected. They use
the West-Gaeke method to analyze S02 and obtain a sulfur balance.
7.2 Ethyl Vehicle Sulfate Data
Ethyl has obtained sulfate emissions from only a limited number of cars.
These cars include the following three non-catalyst cars and one catalyst
car:
1973 Chevelle, production car
Ethyl lean reactor car
Pinto with rich reactor system
1973 Chevelle with Engelhard catalyst.
Only trace quantities (less than 1%) of sulfate were found with the
1973 production car. No sulfate was detected for the two thermal reactor
cars. Ethyl also measured S02 and obtained good sulfur balances for the
1973 production car and the rich reactor car. However, only 50% of the
fuel sulfur was recovered in the black bag for the lean reactor car showing
work is still needed to develop measurement methodology.
For the catalyst car, six tests were made on the low mileage catalyst.
At 40 mph steady state, Ethyl found about 0.07 gpm of sulfates which is
higher than the Exxon value of 0.05 gpm for 40 mph cruise. Ethyl noted
only a 50-60% recovery of total sulfur and is doing further work on this.
Section 8 - EPA OMSAPC Test Results
81 Introduction
Both the OMSAPC and ORD have done extensive work measuring sulfate
emissions. The OMSAPC in-house work has measured sulfate emissions on
the following five vehicles using the absorption method:
Ford - Engelhard Catalyst
1975 GM Non-catalyst Prototype
1975 GM Catalyst Prototype
Gould Dual Catalyst Vehicle
Opel Diesel
26
-------
OMSAPC also has a dilution tunnel installed and has taken particulate
and sulfate with the condensation method on the following cars:
GM Catalyst Prototype
Ford Catalyst Prototypes
Gould Dual Catalyst Vehicles
Peugeot Diesel
Mercedes Diesel
Honda CVCC
Ford Stratified Charge
Volvo Three Way catalyst
Ford Non-catalyst
Dresser Carburetor Prototype
In addition to this work, OMSAPC has funded a contract effort at Dow to
measure catalyst particulates. The OMSAPC Dow contract has measured sulfate
emissions on the following five vehicles:
Ford-Engelhard Catalysts (same vehicle tested
by OMSAPC in-house)
Peugeot Diesel
Mazda Rotary
Williams Gas Turbine
GM Catalyst Vehicle
The OMSAPC results are covered in this paper while the QRD results are
covered in a parallel paper. Both OMSAPC and ORD have planned extensive
additional work in this area.
8.2 F-PA-OMSAPC Work With Absorption Method
OMSAPC has obtained extensive emission data with the absorption method
described in Section 2. This method involves sampling a small portion of
undiluted exhaust with a quartz probe. The exhaust is bubbled through three
impingers in series containing an isopropyl alcohol in the first impinger
to absorb 503 and sulfates and a hydrogen peroxide solution in the second
and third impingers to absorb S02-
These tests were run at three steady state speeds, 10, 30, and 60 mph
using undiluted exhaust.
Of the five cars tested by this method, three vehicles were tested
extensively. These three cars, which are conventional engine 1975 proto-
types, are listed below:
(1) 1975 Ford Prototype, air injection, quick-heat intake
manifold, Engelhard catalysts (2 sets)
(2) 1975 GM non-catalyst prototype, exhaust manifold air
injection
("*' 1975 GM catalyst prototype, 0-mile noble metal pelleted
oxidation catalyst (0.05 oz. noble metal), no air injection.
27
-------
The Ford vehicle was tested separately with two sets of Engelhard catalysts.
One set had been run 50,000 miles while the second set had less than 500
miles. This vehicle was also tested without a catalyst. Limited tests
were done on the following two additional cars:
(1) Gould dual catalyst car, Gould Monel reduction
catalyst and noble metal pelleted oxidation
catalyst (0 miles on reduction catalyst, 12,000
miles on oxidation catalyst)
(2) Opel Diesel
All of the OMSAPC tests have several limitations which must be noted.
The reproducibility from test to test was very poor. While multiple tests
were used to obtain average emission values, the reasons for the poor re-
producibility should be understood so this problem can be corrected. The
analytical method does not recover all of the sulfur compounds since the
material balance is less than 100 percent. The material balance is poorer
for the catalyst vehicles than for the non-catalyst vehicles but is variable
for all vehicles. Clearly, much more work is needed to validate this method
for mobile sources as it has been validated for stationary sources. Also,
work is needed to compare emission results from this method to those ob-
tained by the condensation method. Nevertheless, these test results do
give a preliminary estimate of the problem. The values reported in this
section are average values from many repeat tests.
The Ford vehicle was tested with high and low sulfur level fuel con-
taining 0.085% and 0.017% sulfur respectively. The test results were inter-
polated to give an emission estimate for a 0.03% sulfur fuel assuming a
linear relationship between fuel sulfur level and sulfate emissions.
Table 13 gives the results of the Ford tests for the vehicle in the
following three configurations:
No catalyst
Fresh catalyst
50,000 mile catalyst
The percent conversion to sulfate was based on the ratio of sulfate and
S02 found in the test. The percent sulfur recovered was based on comparing
the S02 and sulfate found with the sulfur consumed by the engine.
The tests on the Ford vehicle showed the following:
(1) There appears to be significant formation of sulfate.s (over 10
percent of the fuel sulfur is converted to sulfates) without a
catalyst. These results are possibly due to errors in the measure-
ment method.
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(2) A catalyst significantly increases sulfate formation (about 20-80
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(3) The amount of sulfate formed is about twice as great with a
fresh catalyst as with an aged catalyst (50,000 miles).
(4) Sulfate emission values are a maximum at 10 mph and a minimum
at 60 mph steady state speeds. This could possibly be due to
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(1050°). The equilibrium conversion to sulfate decreases at
higher temperatures.
The tests on the GM vehicles were more extensive than the Ford tests.
Sulfate emissions were usually sampled at the following three locations:
(1) Behind the exhaust manifold before any catalysts present
(2) Immediately behind the catalyst in the exhaust system (or
behind the reduction catalyst in a dual catalyst system).
(3) At the tailpipe.
Tests were made on a 1975 non-catalyst prototype with the air pump
operating and with the air pump disconnected. Tests were also made with
a 1975 catalyst prototype with a fresh pelleted noble metal catalyst in
the underfloor converter. This vehicle did not have an air pump. The
GM test results are given in Tables 14, 15, and 16. Fuel containing 0.03%
sulfur was used in these tests.
The following conclusions can be made from these tests:
(1) Significant sulfate emissions were again found in the non-
catalyst vehicle. This finding may well be a result of the
measurement method rather than an actual phenomenon.
(2) The sulfate emissions were slightly higher in the non-catalyst
car with the air pump running than with the air pump disconnected.
(3) Sulfate emissions with the catalyst car were significantly higher
than for the non-catalyst car with much of the sulfate being
formed over the catalyst itself.
(4) Sulfate emissions were higher at 10 mph than at 30 mph. This
could possibly be due to the lower catalyst temperature at 10 mph
(750° at 10 mph versus 770°F at 30 mph.
(5) Sulfate emissions are very high at 60 mph and are somewhat greater
than at 10 mph. This would not be predicted from thermodynamic
considerations since the high catalyst temperature at 60 mph (1120°F)
30
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should result in lower sulfate formation. However, the
pelleted catalyst may be storing sulfates formed at lower
speeds and releasing them at higher speeds with the higher
temperatures. The pelleted catalyst, with the large amount
of alumina substrate, probably has a much greater tendency
to store sulfates at lower temperatures. This storage results
from chemical interaction with the substrate forming sulfate
salts which are decomposed at highp<" temperatures. Such
storage has been found occurring with pelleted catalysts from
tests run by Exxon Research and Engineering
The test on the Gould dual catalyst car is the first sulfate test re-
ported on a car equipped with a nitrogen oxide reduction catalyst. Dupli-
cate tests were run at 10 and 30 mph. The tests showed some sulfate forma-
tion (16 percent and 30 percent for 10 and 30 mph, respectively) in the
engine and exhaust manifold. The sulfate conversion, defined as percentage
of the S02 and sulfates recovered as sulfates, increased to 50-60 percent
after the reduction catalyst. The sulfate formation was higher yet (78
percent and 93 percent at 10 and 30 mph, respectively) at the tailpipe
suggesting additional sulfates were formed in the oxidation catalyst and/or
exhaust system. The overall sulfate emissions were about the same levels
as those of the GM catalysts.
The Opel Diesel vehicle tested had a very small amount of the fuel
sulfur (less than 5 percent) converted to sulfates in the limited tests
at 60 mph done by OMSAPC. Even with the sulfur content of Diesel fuel being
about ten times greater than gasoline, the sulfate emissions are about the
same as from a spark ignition engine. However, the S02 emissions arc much
greater than from a conventional engine.
8.3 OMSAPC Work with Condensation Method
In-House Work
OMSAPC has measured sulfate and particulate emissions on twelve
vehicles using a dilution tube to collect the samples and the chloranilate
method to analyze them.
The dilution tube is 18 inches diameter and 22 ft. long. The sample
point is 13 ft downstream of the point where the vehicle exhaust is
introduced to the filtered air stream. The total flow rate through the
tube is about 600 cfm. The samples are collected on a 47 mm diameter
fluoropore filter using a sample flow rate of 2.2 cfm. The sample col-
lection time period varies depending on the test condition and vehicle
type.
The filter samples are weighed for total particulates using
a Sartorius analytical balance and then analyzed for sulfates.
The filters are dissolved in 65% isopropyl alcohol. A small amount of
this liquid is pumped through a liquid chromatograph column (Varian
-------
Model 8500) where the sulfate ions are quantitatively exchanged with chloranilate
ions. The amount of chloranilate ion released is measured by ultraviolet
spectroscopy (Varian Model 635). The system has recently become operational
and data on ten vehicles are available. The analysis method has been found
to be inappropriate for the diesel samples and must, therefore, be modified
slightly before the stored diesel sulfate samples can be analyzed. However, the
particulate weights have been determined and can be found in Table 22. Some of
the diesel samples were analyzed by EPA-ORD and these preliminary results can be
found in Tables 18 and 21.
The following twelve vehicles have been tested to date:
1) 1975 GM catalyst prototype 7) Honda CVCC
2) 1975 Ford catalyst prototype 8) 1977 Ford Prototype
3) Gould dual catalyst vehicle-25,000 miles 9) Gould Dual Catalyst Veh.-O mile
4) Dresser carburetor vehicle 10) 1974 Ford Production
5) Peugeot Diesel (non-catalyst)
6) Mercedes Diesel 11) Ford Stratified Charge
12) Volvo Three Way Catalyst
Also, a Chrysler prototype catalyst vehicle was tested briefly but developed
mechanical problems, was returned to Chrysler for repairs, and has been sent back
to OMSAPC. In addition to these vehicles, the following vehicles are scheduled
for testing in the near future.
GM Catalyst Prototype (designed to meet statutory HC and CO standard)
Texaco Stratified Charge
Non-catalyst 1975 vehicles
1975 Production Catalyst vehicles (GM, Ford, Chrysler)
An important car in this test program has been the 3-way catalyst vehicle. The
3-way catalyst relies on very close control of air-fuel ratio for simultaneous
removal of HC, CO, and NOX. The close control, of air-fuel ratio, achieved
by a lambda sensor, and low oxygen levels in the exhaust resulted in very low
sulfate formation.
The vehicles tested in this program are being operated over the 1975
FTP, the Hiway Economy Cycle, and at 60 mph steady state. The HC, CO,
and NOX emission levels of the four vehicles for which sulfates have been
analyzed are given in Table 17. Tables 18, 19, 20, and 21 give the particulate
and sulfate emissions of these vehicles over the cold start FTP, hot start
FTP, EPA highway economy cycle, and 60 mph steady state.
35
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The values in Tables 18 thru 21 have been compared to the values other investigators
obtained for similar vehicles. This comparison suggests the in-house values are
somewhat Itjwer than those obtained by other investigators. The comparison of the
EPA values versus those obtained by others will continue as more in-house testing
is done.
Although the two diesel vehicles were tested and the samples taken, the samnles vpv
not analyzed because the analysis systancould not currently handle the he:.A pai c-c~
ulate matter. However, six filters were sent to EPA-ORD, where they were analyzed
and the results are included in tables 18 and 21. It should be noted t'nat *hese
values are based on only one test sequence and are strictly preliminary. , evertheless
they do show that even though the percent sulfur conversion is low the sulfate
emissions are high due to the high diesel fuel sulfur content.
The total particulate values for these diesel vehicles are listed in Table 22. One
item that must be noted is that the diesel vehicles had high particulate emissions
which rapidly clogged the filters preventing complete collection of particulates
during the rest of the test. Therefore, the values listed for the transient tests
should be considered minimum values.
TABLE 22
Particulate Emission Results
Test Number of Total Particulate
Vehicle Conditions Tests (Mg/mi) +_
Mercedes 220 75 FTP 4 Over 600
Diesel Hot Start LA-4 7 Over 600
(#12-217808) 60 MPH S.S 10 327 ( +.119)
Peugeot 504 75 FTP 4 Over 200
Diesel Hot Start LA-4 4 Over 200
(#504-A90- 60 MPH S.S. 15 219 (+ 52)
1800021) Hiway Economy Cycle 8 Over 200
Contract Work
OMSAPC has funded a contract with Dow Chemical Company for the past
several years to measure particulate emissions from automotive vehicles.
Initially, this contract work focused on particulate emissions from cars using
leaded fuel. Since 1971-72, emphasis was placed on particulate emissions
from cars using unleaded fuel which included a large number of catalyst cars.
Particulate measurements in 1972 from a Ford car equipped with Engelhard
catalysts showed unusually high particulate emissions. Ford analyzed these
samples and found sulfuric acid which was the first indication of this problem.
Since them, Dow has done particulate measurements on a large number of cars
as listed below:
-------
TABLE 23
Vehicles Tested at Dow
Honda CVCC
1973 Opel Diesel
Peugeot Diesel
Mazda Rotary (3 cars tested)
Williams Gas Turbine
Ford with Engelhard 50,000 mile Catalyst
(Vehicle 24A51)
Ford with Engelhard 0 mile Catalyst
(Vehicle 24A51)
GM Catalyst Prototype (Pontiac) with Monsanto
Base Metal Pelleted Catalyst
Ford Catalyst Vehicle (Vehicle A342-35)
Capri Stratified Charge
GM 1975 Catalyst Prototype
The particulate samples collected were either sent to ORD for sulfur
analysis or, in a few cases, analyzed by Dow themselves. ORD used X-ray
fuorescence to obtain total sulfur content of the filter which was assumed
to be all sulfate.
The results of these tests is given in Table 24 and show the Diesel
and gas turbine to form definite quantities of sulfate.
OMSAPC is now in the process of obtaining additional characterization
data through a contract with Southwest Research Institute. This work is
discussed in Section 10.
TABLE 24
Sulfate Emissions for Vehicles Tested at Dow
Vehicle Driving Cycle Fuel Sulfur Sulfate gpm
Ford 24A51 1975 FTP (glass 0.03% 0.012
50,000-mile fiber filter)
Engelhard
catalyst 1975 FTP (millipore 0.03% 0.022
filter)
Ford 24A51 1975 FTP (glass 0.03% 0.014
0-mile fiber filter)
catalyst
1975 FTP (millipore 0.03% 0.023
filter)
-------
Table 24 Cont.
Vehicle
Pontiac-
Monsanto base
metal pelleted
catalyst
Driving Cycle
1975 FTP (mi Hi pore
filter)
Fuel Sulfur Sulfate gpm
0.03% 0.010
Chevrolet- 1975 FTP
Pelleted
catalyst
(tested prev-
ious to Con-
tract 68-01-0480)
0.03%
Peugeot
Diesel
Mazda
Rotary
Williams
Gas
Turbine
1975 FTP (millipore
filter)
1975 FTP (millipore
filter)
1975 FTP (mi Hi pore
filter)
50 mph (millipore
filter)
0.35%
0.03%
0.03%
0.03%
0.011
0.009
0.003
0.005
0.004
Section 9 - Sulfate Traps
If it is not possible to control the formation of sulfates in the
catalyst, it may be possible to control sulfate emissions after the catalyst
by use of a sulfate trap. A sulfate trap is a device, which by chemical
reaction or mechanical means, removes sulfuric acid particles and $03 from
the exhaust gas downstream of the catalyst. Most of the available informa-
tion on automotive sulfate traps was submitted in response to the March
8th Federal Register notice requesting information on sulfates.
Most of the feasible sulfate traps are chemical traps and involve
reaction of the acidic sulfate with a base. Sulfate trap type devices,
such as limestone scrubbers, were developed to control sulfur dioxide emis-
sions from stationary sources. These traps have not been previously con-
sidered for automotive use. Very few comments were received on sulfate
trap '.her than general comments from GM and Ford and some specific comments
f"", atomics International.
47
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It is also possible that mechanical traps such as those used for lead
particulates could be used for sulfates. These traps are not as technically
feasible as the chemical traps.
9.1 Mechanical__Traps
The mechanical trap is a centrifugal separator type device used to
remove particulates from automotive exhau^L. These traps have been developed
by DuPont, Ethyl, and PPG and have been demonstrated for lead particulates.
It is theoretically possible that sulfuric acid could be removed by this
trap vf the sulfate particles were condensed into particulates when the
exhaust reaches the trap.
Ford commented on mechanical traps stating that exhaust system tempera-
tures were too high to allow condensation of sulfates in the exhaust. EPA
measurements of temperatures along standard exhaust systems show this state-
ment to be true. Ford mentions that a heat exchanger could be used to lower
the exhaust temperature. However, this heat exch?nger would condense the
water in the exhaust if a large temperature drop occurred. Ford feels it is
virtually impossible to maintain the temperature below the condensation
point for sulfuric acid yet above the condensation point for water over a
wide range of driving conditions.
EPA can tentatively conclude on the basis of the Ford comments and our
own measurements of exhaust system temperatures that the mechanical trap is
not a promising sulfate trap.
9.2 Jfalten Carbonate Traps
Atomics International Division (AI) of Rockwell International stated
they had developed and tested an exhaust gas scrubber device which has
been effective in removing particulates from automobile exhaust gases.
This scrubber works by passing the exhaust gas through a molten alkali
metal carbonate eutectic consisting of equal parts by weight of lithium,
sodium and potassium carbonates. A paper calculation shows this salt will
require changing every 15,000 to 20,000 miles. Removal of particulates
in this scrubber is accomplished by both a chemical reaction and wetting
of the particulates. Atomics International feels the trap is effective
at all temperatures but is most effective when the salt has melted. This
trap has been tested to only a very limited extent by passing undiluted
exhaust gas through a fiberglass filter and aqueous scrubber. While neither
sulfates nor S02 were analyzed in general, total particulates were measured
and found to be about 90% lower with the trap. One measurement was taken
of S02 removal which showed a 99% reduction.
However, a major problem with this type of scrubber is potential emis-
sion of alkali carbonate itself by entrainment from the trap. Limited data
from Atomics International indicate an emission rate at 60-70 mph which
corresponds to a 2.2% loss of the scrubbing salt over 15,000 miles. Addi-
tional work is needed to determine the magnitude of any problem.
-------
Exxon is examining various sulfate traps under contract to EPA and
feels the molten carbonate trap has low potential compared with other
possible traps. They cite the above entrainment problem, mention that the
trap cannot work until the salt is molten, and feel the molten salt mixture
is corrosive and hard to contain. Due to these problems, Exxon does not
plan to test molten carbonate traps in their program. Furthermore, the
molten carbonate trap is considered less feasible for stationary source
S02 control than other control systems which makes it a less attractive
candidate for automotive application.
9.3 Metal Oxide Sulfate Traps
Metal oxides, such as calcium oxide and aluminum oxide (alumina), are
good candidates for use in automotive sulfate traps. Metal carbonates,
such as calcium carbonate, can also be used. These substances react chemi-
cally with the sulfuric acid forming inert sulfate salts. A trap containing
calcium carbonate functions similarly to one with calcium oxide in that the
solid compound (calcium carbonate or calcium oxide) reacts with the sulfuric
acid. A calcium carbonate trap is different from the molten carbonate trap
discussed earlier which uses molten salts at high temperatures. Metal oxide
and calcium carbonate scrubbers are used to control stationary source $03
emissions. Ford, GM, and Exxon commented on metal oxide sulfate type traps.
Ford has done a paper study on metal oxide sulfate traps and feels
calcium oxide would be an effective trapping agent. However, Ford calculates
that 250 pounds (a cube of 20 inches on edge) of calcium oxide is required
to control sulfafce emissions over 50,000 miles. Periodic replacement of the
calcium oxide at specified mileage intervals would decrease the size of
the trap. Ford also commented that the high C02 content of the exhaust
converts calcium oxide to calcium carbonate which is also an effective
trapping agent. Ford has not done any testing with a calcium oxide sulfate
trap.
Ford feels that a sulfate trap containing alumina is more promising
and would require 32 pounds of alumina over 50,000 miles. Alumina is the
same substance used for catalyst pellets and readily reacts with sulfuric
acid. However, the temperature of the trap must be kept low enough to pre-
vent decomposition of aluminum sulfate. Ford also commented that attrition
of the alumina could occur from the trap. Any development program on sulfate
traps must measure for trap attrition products. Finally, Ford stated that
a major design problem with alumina and other compounds is a suitable trap
design to assure adequate contact between the alumina and the exhaust gas.
3
GM has designed and tested a 90 in vehicle sulfate trap containing
aljmina The sulfate trap was installed on a vehicle with a GM catalyst
ni.d te ..j over the FTP. GM stated that the results of testing over the
r ;" jre inconclusive due to low baseline emissions over the FTP without
+ trap. Clearly, the trap must be tested under conditions such as 60 mph
uise which results in high sulfate emissions. GM, using slightly different
assumptions than Ford, calculates that 10-20 pounds of alumina are needed
over 50,000 miles.
-------
Exxon has a laboratory program to test calcium oxide traps. Further-
more, Exxon is- under contract to EPA to test and evaluate vehicle sulfate
traps containing alumina, calcium oxide, or other promising materials. One
potential problem with metal oxide traps is that the sul fate compound formed
from reaction with the trapping media with $63 is larger in volume than
the metal oxide. The trap must be designed to accommodate this expansion.
At this time, it is not possible to make any conclusions about the
effectiveness or cost of a chemical sulface trap. Much more evaluation
and testing by various companies is needed.
Section 10 - Plans For Future Work
This section briefly discusses the OMSAPC work that will be done in
the sulfate area over the coming year. Plans for ORD work on sulfates are
covered in a separate paper. Basically, OMSAPC will assess control technology
for sulfates and obtain characterization data. ORD will continue to develop
measurement methods, obtain characterization data, help do air quality,
modeling, and obtain health effects data. In addition to these two broad
areas, the EPA Office of Air Quality Planning and Standards will investigate
the feasibility of fuel desulfurization and will help in the air quality
modeling efforts.
The OMSAPC program is divided into two parts, a contract portion and
an in-house portion.
10.1 OMSAPC Contract Work
The two major goals for the OMSAPC contract work are to assess control
technology for sulfates and to obtain additional characterization data.
The former is being done by Exxon Research and Engineering while the latter
is being done by Southwest Research Institute.
The Exxon contract started in June, 1974 and will be completed in
March, 1975. This work is divided into the following four overall tasks:
0) literature search on aspects of S02 oxidation pertinent to
automotive sulfate emissions
(2) assessment of sulfate emissions from non-catalyst vehicles
(3) determination of factors affecting S02 oxidation on catalyst vehicles
(4) evaluation of sulfate traps.
A plan of performance has been turned in outlining the work to be done in
these tasks.
50
-------
The literature search is almost complete and has obtained information
in the following areas:
thermodynamic equilibrium of S0£ oxidation
thermodynamic equilibrium of SOs hydration
kinetics and mechanisms of these reactions with emphasis on materials
catalyzing these reactions
reaction of S02 and S03 with potential trap materials.
Work on the second task has also started. Sulfate emissions will be
measured on a 1974 production car, a rotary engine equipped vehicle, a
Honda CVCC, and a Diesel car.
Work on the third task will start when catalyst equipped vehicles are
obtained. The effect of the following parameters on sulfate emissions will
be obtained:
catalyst formulation
air injection rate
catalyst temperature
catalyst residence time.
The last task will involve evaluating and testing vehicle sulfate traps.
Vehicle testing is already underway on a calcium oxide trap.
As a supplement to the Exxon contract, EPA has also awarded a contract
to Monsanto Corporation to act in an advisory capacity to EPA in the Exxon
work. Monsanto will independently evaluate the four areas above from the
results of the Exxon work.
The second major contract area involves obtaining additional sulfate
characterization data. This contract is with Southwest Research Institute
and started in June, 1974 and will also be complete in March 1975. This
contract involves measuring S02 and sulfate emissions from the following
cars:
Monolith Catalyst car
Pelleted Catalyst car
Dual Catalyst car
Pre-1973 car
1975 Non-catalyst car
Diesel Engine Vehicle
Stratified Charge Engine car.
Sulfate emissions will be measured from the oxidation catalyst cars from
low mileage and on through 15,000 miles as mileage is accumulated on the cars.
Sulfa; emissions will be measured at 30 and 60 mph steady state conditions
a1 ^ver the FTP. Measurements will be made with a dilution tunnel and also,
. the steady state conditions, by the absorption method.
51
-------
In addition to this work, contract work is being planned to assess
sulfate emissions from heavy duty Diesels. LDV Diesels, even with their
very low fuel consumption, have definite sulfate emissions. It is possible
that HD Diesel engines would have substantially greater sulfates.
10.2 In-house Work
Future OMSAPC in-house work will be directed towards testing vehicles
to determine sulfate emission factors. The vehicles tested to date are
given in Section 8.3. Vehicles scheduled for testing in the future provided
OMSAPC can obtain them are:
GM catalyst prototype (designed to meet statutory HC and CO
standard)
Plymouth catalyst vehicle
Volvo 3 way catalyst vehicle
Production model 1975 catalyst vehicles (GM, Ford, Chrysler)
Texaco Stratified Charge vehicle
Arrangements have been completed to obtain several of these vehicles.
52
-------
Appendix A2
Gasoline De-Sulfurization
Summary
In 39 CFR 9229-9231 March 8, 1974, EPA asked for submission of data
and views on the magnitude of the automotive sulfate emissions, the impact
of such emissions on ambient air, and the alternative approaches to con-
trolling such emissions.
The Petroleum Refinery Task Force, ESED, OAQPS, was given responsibility
for developing parpagraph C, Control of Automotive Sulfate Emissions through
Fuel Modif1ca11 on and subsequent review of industry input to this section.
Responses to section C were received from 23 refiner/ refineries operating
85 refineries and representing 55 percent of the United States crude capacity
of about 14, 173,000 B/D reporting by the National Petroleum Refiners Asso-
ciation (NPRA) April 12, 1974. several of the larger oil companies, notably
Gulf and Standard of California (Chevron) failed to submit responses. The
reporting companies, numbers of refineries and crude capacity are given in
Attachment I.
While the response level of 55 percent might be considered good for this
type of inquiry, the quality of some of the reports, including those from
at least two majors, was generally marginal to poor.
General comments were received from NPRA who mailed a questionnaire (see
Attachment II) to essentially all the refiners in the United States. As of
July 12, 1974, NPRA has received responses from 130 refineries representing
e\,ut 12.5 million barrels per day or 88 percent of U.S. crude capacity. This
data was made available to us at a meeting with NPRA in Washington, D.C. on
July 16, 1974.
53
-------
In summary, individual comments were helpful in providing specific
impacts on specific configurations of refineries, and in providing ranges
of impacts over a wider spectrum of configurations. A more definitive
study has been planned by the PRTF, awaiting only the inputs of these
comments. Our analysis of the comments did not find any new or startling
data or conclusions, and the PRTF study has been initiated generally; in
its original form. The proposed work plan is appended as Attachment III.
-------
appendix M£.i
Control of Automotive Sulfate
Emissions through Fuel _Modifications
I. Introduction
EPA received responses from twenty-three refiners (encompassing eighty-
five refineries). This represented fifty-five percent of the United Stau.-s crude
capacity of about 14,173,000 barrels per day (as reported by the National
Petroleum Refiners Association April 12, 1974). Several of the larger oil
companies, notably Gulf and Standard of California (Chevron) did not submit comments
The reporting refiners, numbers of refineries and crude capacities are given
in Attachment I.
While the response level of fifty-five percent might be considered good
for this type of inquiry, some of the reports, including those from at least
two majors, were of little value.
In addition to the comments received by EPA in response to the March 8
Federal Register notice, at least three additional sources of information have
been summarized here in order to complete our current analysis of this alternative
approach to controlling automotive sulfate emissions. M.W. Kellogg, under
contract to EPA, recently completed an analysis of desulfurization of gasoline.
Arthur D. Little, under contract to General Motors, also recently completed an
analysis of this subject. Finally, NPRA has completed (although a final report
has not been issued to date) an industry survey in which responses were received
from refiners encompassing 130 refineries (representing eighty-eight percent
of the U.S. crude capacity). A discussion of their preliminary results has been
also included.
11. Sup "Of responses to the Federal Register of inarch 8, 1974.
v point by point coverage of the comments received in response to the Federal
^,^iiLis fliven in this :uction. The Kellogg and ADL gasoline desulfurization
studies and the NRPA survey are summarized in Section III.
55
-------
C-l The current sulfur content of crude oils, Intermediate refinery fractions,
and fuel (by type or grade) and trends and anticipated changes In those sulfur
levels taking into account changes required to comply with fuel allocation
regulations and the projected demand for low-lead and lead-free gasoline.
The response to this item was quite limited in scope and did not provide us
with any significantly new view-points on sulfur trends and their Impact on sulfur
contents of refinery intermediate streams or products.-
The general consensus remains that light Arabian crude containing 1.5 to 2.0 wt
percent sulfur should be considered as representative of the swing crude during
the 1975-1980 period. No mention was made of the effect of availability of North
Slope crude containing 0.8 wt percent crude after 1980. There will be an excess
of this crude above West Coast requirement for a number of years and it is
probable that some of this might be refined in the Mid-Continent. All agreed that
the National average level of sulfur in crude runs would increase as a result
of increased sour crude importation. Two refiners, Atlantic Richfield and United
Refining, predicted a National average sulfur content of 1.0 to 1.2 wt percent in
1975-80. This level is consistent with that indicated by the American Petroleum
Institute in a critique of July 2, 1974, on the M. W. Kellogg reports, "Production
of Low Sulfur Gasolines Phase I and II."
Actually, average sulfur values may have limited utility in assessing the impact
of producing a lower sulfur gasoline on an individual refinery or even a typical
type refinery in a PAD district.
For example, Husky who operates in Wyoming and Utah reported processing
a crude mix ranging from 2.0 to 3.0 percent, and produces gasoline averaging about
1500 ppm (above ASTM specifications of 1000 ppm). Koch, located in Minnesota, runs on
90 percent Canadian crudes and reported the average sulfur content of the crude
mix to the refinery to be 2.5 wt percent. Extensive desulfurization equipment
has been installed by Koch whose unleaded gasoline is expecled to have about
56
-------
550 ppm of sulfur in 1974-75, 300 ppm in 1976-78 and a final reduction to 240 ppr»
in 1979. An antithesis to this is Derby Refining, Wichita, Kansas, who processes a
sweet crude with 0.3 wt percent sulfur and produces a total gasoline pool v;i -,
700 ppm of sulfur. Derby expects their unleaded gasoline will contain 3C^ opm of ^ui
Texaco provided,for their refineries,a comparison between 1972 sulfur content
of crude, gasoline blending components, and total gasoline pool versus similar
projections for 1980. The 19£0 case assumes installation of substantial additional
hydrotreating facilities, presumably to desulfurize catalytic reformer feed stocks,
which essentially keeps sulfur level in products at the 1972 level. Hydrodesul-
furization of FCC feedstocks or FCC gasolines was not considered in these
assessments. Shell furnished a more detailed breakdown of sulfur contents of
light and heavy FCC gasolines but did not project these beyond the current situation,
The Shell and Texaco data highlight the range of values reported. The Shell and
Texaco data are summarized in the following table.
57
-------
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of the pool, 65 to 71 percent based on the Texaco data and essentially 100 percent
based on the Shell data. Texaco assigns significantly higher sulfur to butane,
alkylate and reformate than does Shell. This is extremely important
since the only viable method of providing short rdnge low sulfur lead-free
gasoline is by selective blending of low sulfur components.
C-2 and C-3: Quantities of low sulfur gasoline expected to be available
by September 1974, and in subsequent years, specifying this
information by grade and sulfur content.
The ability of the petroleum refining industry to provide
unleaded gasoline of low sulfur content using existing or
planned refined capacity through appropriate blending of refinery
streams, including consideration of blending products of different
refineries or facilities.
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gasoline is by selective blending of low sulfur components. The refiners made it
clear that gasoline blending is a compromise of many and sometimes conflicting
requirements. Comments made by Union Oil typify the resnnnses anH are summarized
below:
1. All gasoline stocks must be blended into products - there can be no left
overs.
2. The gasoline produced must meet quality requirements.
3. Volumes produced of each grade must meet marketing requirements.
The , ,^t common problem is the FCC gasoline, the main contributor to *he
sulf'-r content of the pool. FCC gasoline is low in octane, has a low response to
le.;.. because of high sulfur, and directionally would be used in unleaded gasoline.
59
-------
Lead restrictions in other grades limit octane improvement from lead. To compensate
for the FCC gasoline, low sulfur higher octane blending stocks like alkylate
and reformate are required. Therefore producing low sulfur gasoline using these
low sulfur blending components is an antagonistic requirement and severly limits
the ability of. the refinery to provide quantities of low lead from existing facilities
In general the refiners indicated only about 20 to 30 percent of the gasoline
pool could be made available as low sulfur unleaded gasoline containing 100 ppm
of sulfur. Availability of low sulfur gasoline containing 50 ppm was indicated
to be nil. In the following table it will be noted that supplies of 100 ppm low
sulfur, lead-free gasoline would meet projected demand only through 1977.
Interchange of blending components, even between refineries operated by the
same refiner, was considered impractical based on the contention that segregated
facilities were not available for handling by pipeline. Even if piping changes,
additional tankage, and other equipment for component segregation were installed,
it was the general opinion that such exchange would only marginally increase low
sulfur, lead-free supplies.
60
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C-4 The current status of desulfurization technology which could be used to redjco
gasonnc suirur levels - -:
a and b - Desulfurization Technology
Opinion was unanimous that desulfurization technology is well proven and uiat
the options available for reducing the sulfur content of gasoline are Tim, :ad.
As evidenced in C-l, the gasoline from fluid catalytic cracking (FCC) is f "
major contributor of sulfur to the gasoline pool. In a high conversion gasoline
refinery,the FCC gasoline makes up over 30% of the pool. Sulfur content of the total
FCC gasoline may typically run 1000 ppm contributing 300 ppm of sulfur to the pool.
Another problem is that the sulfur content of the FCC gasoline is skewed, with the
heavy FCC gasoline containing twice as much sulfur as light FCC gasoline.
Light straight run naphthas which usually comprise about 10% of the pool may also
contain substantial quantities of sulfur, i.e. 100 to 500 ppm. Of course the sulfur
contents of these streams are a function of sulfur contents of refinery crude runs
as well as the amount of desulfurization equipment operating in the refinery.
Three processing schemes are generally accepted as being applicable to reduction
of sulfur in gasoline.
(1) Desulfurize feed to the fluid catalytic cracking unit, (FCC)
(2) Desulfurize FCC gasoline.
(a) Desulfurize full range FCC gasoline
(b) Desulfurize heavy FCC gasoline.
(c) Severly desulfurize heavy FCC gasoline-.nrildly hydrotreat light FCC gasoline.
(3) Desulfurize light straight run naphtha.
The two companies who supplied the most in-depth analysis spofce to only (1),
(2) (a) and (3) above. Simplified flow plans of these options are shown in Figures 1
thrc >gh 4. The most, severe case would be either (1) + (3) or (2a) + (3).
Re - js processing high sulfur content crudes would probably be faced with these
op ,ns. A lower sulfur crude refinery might not opt to use (3) and could
possibly make low-sulfur lead-tree gasoline using 2(b) only.
63
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It is generally impossible to generalize on which options might be used as they
will vary from refinery to refinery. Projection from a single or even several
refineries to a National basis can be extremely misleading.
c. Effect on Octane
The minimal effect on octane will be when total FCC naphtha is fractionated into
a light (Cg - 180°F) and heavy fraction (180°h - 430°F) and only the heavy fraction
desulfurized. Atlantic Richfield estimates 35 vol percent of C5 - 180°F, 93 RON clear,
could be sent directly to the gasoline pool. Sulfur content of this fraction is
about 200 ppm. The 65 vol percent heavy fraction containing 1230 ppm of sulfur would
be completely desulfurized and octane reduced from 92.3 to 76 RON clear. The total
FCC gasoline would be reduced by 10.2 RON clear. NO daca were given on MON impact.
Union Oil reported an 8 RON 2 MON reduction if total full ranqe.FCC naphtha wf?re
hydrotreated. This is not consistent with the Atlantic Richfield data but differences
between refineries are to be expected. An average value for desulfurizing full
range FCC naphtha is probably in the order of 8 to 15 RON clear.
With FCC naphtha accounting for about 30 percent of the gasoline pool full range
naphtha treating would cost about 3.0 to 4.5 RON (less than 1 MON) clear octane numbers.
d.thru i.- Impact on the Industry - Time, Cost, Energy
Construction Impact
Leadtimes for individual refiners to have the capability to supply all of their
gasoline with a limit of 100 ppm sulfur ranged from zero to greater than six years
depending upon the current desulfurization capabilities and crude supplies of each
refiner. The median response was four years, but most refiners added that leadtimes
may be much longer because of the large amount of construction planned to increase
total refining capacity.
Capital Investment
Capital investment estimates for individual refiners ranged from zero to $994
million for the manufacture of 100 ppm sulfur gasoline for a refiner with eleven
-------
rerinenes to ii,«45 rrninon tor the same refiner to manufacture 50 ppm sulfur gasol it--
However, the second highest estimate was $257 million and most refiners' estimates
were between 30 and 200 million dollars. The data- were insufficient to determine
the cost for a typical or average refiner or refinery. Only three comments included
an estimate for the total industry impact. The Mobil and Atlantic Richfield estii -tes
were $2.5 billion and $2.0 billion respectively. However, .the Texaco estimate was
much greater -- $12 billion. Preliminary results of the survey by the National
Petroleum Refiners Association indicate a capital cost of approximately $3.7 billion.
Operating Costs
Refiner incremental operating costs were estimated by only three companies. For
100 ppm sulfur, Cities Service and Exxon estimated $12 million per year and Texaco
estimated $200 million per year. For 50 ppm sulfur, Cities Service and Exxon
estimated approximately $30 million per year and Texaco estimated $230 million per
year. Costs per gallon of gasoline ranged from 0.5 to 2 cents per gallon with only
five estimates.
Energy and Yield Impacts
Energy penalties were estimated by only six companies and r^nge from 1/2% to
1 1/2% on crude. These estimates are difficult to assess because of the variety of
processing schemes and methods of calculation of penalties.
Yield penalties were estimated Ly Lin ce cuiiiparneff oT~co"hstant "crude input.
yield losses shown were approximately 1 to 2%. Again, the estimates are difficult
to assess because of the differences in calculation procedures.
65
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Industry Impact'
Construction leadtime
Capital investment
Annual operating costs
Cost per gallon of gasoline
Energy penalty
2
Gasoline yield penalty
Note:
1
100 ppm sulfur
At constant crude inout
Range
0 to 6 years
$2 to 12 billion
$12 to 200 million
0.5 to 2.0 cpg
1/2 to 1 1/2%
1 to 2%
Median
4 years
$2 1/2 tillion
$12 million
1 cpg
1%
1%
66 '
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C-5 Impact or "inaustry-v.'iuf duupLiun
a and b Impact of gasoline desulfurization on refinery flexibility.
Gasoline desulfurization using the technology described in C-4 is not expected
to have an appreciable affect on the refinery flexibility to vary product yield patterns
This is not so in the early years 1975-79 prior to installation of desulfurization
facilities. The greatest portion of the sulfur is contained in the heavier portion of
FCC gasoline. This fraction is a seasonal swing item, going into gasoline in the
summer and heating oil in the winter. Thus sulfur restrictions could limit ability
to maximize gasoline in the short term.
c. Feasibility of desulfurizinq only lead-free vs total pool.
Only certain gasoline blending components need to be desulfurized to meet
various sulfur restrictions. If lead-free gasoline gradually increases to essentially
100 percent it is probably most economical to size the desulfurizers to treat these
components to meet those ultimate requirements. For example, desulfurization of all
FCC gasoline would be more practical than just the portion needed for lead-free.
Furthermore, the time frame required for construction of facilities to desulfurize
only lead-free is the same as for total gasoline.
d. Impact of various degrees of gasoline desulfurization on sulfur content of other
fuels.
If FCC gasoline desulfurlzatlon i* ^'.ecueu as chTrproceirs- to meet gasoline sulfur
specifications, the affect on the sulfur content of other products is negligible.
Desulfurization of total FCC feed stock would reduce the sulfur content of
No. 2 Distillate.
C"6 Contribution of fuel additives to gasoline sulfur content.
The two refineries who reported on this item stated their additives contributed
about 5 to 7 ppm sulfur to the gasoline pool.
67
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III. Other Studies
A. Kellogg - Low Sulfur Unleaded Gasoline
In order to obtain a quick analysis of the impact of desulfurizing gasoline,
EPA contracted M. W. Kellogg Company for a three-phase study to be completed by-
early summer 1974. The draft final report of Phase 3 was completed in July.
Phases 1 and 2 assess the impact, on a typical U.S. refinery, of producing low-
sulfur (60 ppm), unleaded gasoline. (Phase 2 is essentially a better-calibrated
version of Phase 1.) The major conclusions of the Kellogg Phase 2 report are that
a typical existing refinery can produce sufficient quantities of low-sulfur, unleaded
gasoline by blending current low-sulfur streams until 1976, while maintaining
refinery product outputs. In order to manufacture mure low-sulfur, unleaded
gasoline than blending allows in later years, the refinery is allowed a choice of
two desulfurization schemes: (1) hydrodesulfurization of cat cracker feed and
light virgin and light coker (or thermal) gasolines and (2) hydrodesulfurization
of cat cracked gasoline. Phase 2 calculates that the cat cracked feed desul-
furization'route would require an incremental cumulative capital investment of
$2.0 billion for the United States and an incremental operating cost of 0.7 to
1.6 cents per gallon of total gasoline (for refinery sizes of,100,000 to 16,000
-barrels per calendar day) to produce low-sulfur unleaded gasoline thru 1979.
After 1979 additional (unspecified amount) octane improvement facilities would be
necessary. Phase 3 of the Kellogg study evaluates the same scenarios for a typical
California refinery. Phase 3 concludes that a typical existing California refinery
can manufacture low-sulfur,unleaded gasoline until 1976 by blending current low-
sulfur components. After that, hydrodesulfurization of cat cracker feed and light
virgin gasoline and light thermally cracked gasoline, would cost $280 million
(for the 1.4 billion barrel per stream day (bpsd) capacity of the eleven California
refineries larger than 75,000 bpsd, i.e., 78 percent of the total California
capacity) and 1.1 cents per gallon of total gasoline. The alternate route of
-------
rlpc.ni furi7flt inn of rat cracked aasoline would cost $200 million incremental
investment and 1.0 cents per gallon incremental manufacturing cost. Furthermore,
additional facilities (unspecified amount) would be required to replace the
octane lost by hydrodesulfurizing the gasoline.
As with any study of the petroleum industry, the input assumptions and
calibration and flexibility of the model are extremely important. The EPA-
required lead phase-down is not included in the base scenario. Rather, the
base is an existing "typical" refinery producing current grades of gasoline.
The study then assesses the incremental impact of manufacture of low-sulfur,
unleaded gasoline on that refinery. A more realistic base (or a first-step)
scenario would include the unleaded introduction rate and the lead phase-
down schedule in order to account for refinery commitments to meet those
requirements (which have been known for the last few years) before assessing
the incremental impact of a sulfur specification. In regard to calibration
and flexibility of the model, it should be noted that several simplifying
assumptions were used in the Kellogg study because of the constraints of
providing a timely analysis. For example, reformer severity, cat cracker
conversion, and alkylate production volume were fixed and aromatic production
was assumed to be part of total reformate rather than utilizing a separate
reformer. The degree of impact of these simplifying assumptions can not be
quantified without additional modeling.
B. Arthur D. Little - Low Sulfur Unleaded Gasoline
As a result of concern over sulfate emissions and in response to the EPA
request for information on this potential problem, General Motors Corporation (GM)
commissioned Arthur D. Little, Incorporated (ADL) in April of 1974 to study the
ability r the U.S. refining industry to produce low-sulfur, unleaded gasoline.
The final report was completed in June. The ADL study assesses the impact, on
a composite U. S. gasoline refinery, of reducing the sulfur content of unleaded
gasoline to approximately 100 ppm and 30 pprn for the period 1975-1985. The
69
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nonpf va f-ion rafp of unloarHpH rtacnl i no =»nH +-ho loaf, ^cp-Hoi-'n crhorlulp i.ir>v«n
incorporated in the base scenario. For simulations of the years 1975 and 1976,
the model configuration was restricted to the present ratio of downstream processing
capacity to crude distillation capacity. However, the simulations for post-1976
were allowed complete flexibility to determine future refinery processing requirements,
including direct desulfurization of gasoline, desulfurization of cat cracker feed,
and increased use of hydrocracking. The major conclusion of the ADL study is that
for the 1975 to 1979 time period there is essentially no increase in refinery
desulfurization processing capacity required to manufacture low-sulfur (both the
30 ppm and 100 ppm cases), unleaded gasoline. That is, until 1980, the low-sulfur,
unleaded gasoline can be manufactured by selectively blending sweet components
into the unleaded grade. Beginning in 1980, when the unleaded gasoline volume
first exceeds 50 percent as forecast by GM, significant hydrodesulfurization/
hydrocracking capacity must be added. By 1985, the incremental impact of reducing
the sulfur content of unleaded gasoline to 100 ppm would require a $2.3 billion
cumulative incremental investment (1974 dollars) and an incremental manufacturing
cost (including delta raw materials, by-products, capital charge, and operating
cost) of 0.62 cents per gallon of unleaded gasoline. The impact for 30 ppm would
be $7.5 billion and 1.35 cents per gallon.
As mentioned above, the input assumptions and calibration and flexibility
of the model are extremely important for any study of the petroleum industry.
As ADL notes in the study, an overview considering the entire U.S. refining industry
as a single composite model has inherent limitations. The extent of these
limitations can only be quantified by additional studies. ADL states that their
composite model reasonably represents the flexibility and economics of the large
volume gasoline manufacturers which supply the majority of the market place, although
their analysis does not address itself to regional variations or the specific
problems of small or atypical refiners. Further, the ADL study did not attempt
to assess the ability of the construction industry to respond to the incremental
70
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investment required. This is clearly an important variable which must be properly
evaluated .especially for the 1974-1980 time period.
C. National Petroe^um Refiners Association
In May 1974, the National Petro'elum Refiners Association (NPRA) began a survey
of the industry to assess the impact of .manufacturing low-sulfur, unleaded
gasoline. As of July 12, 1974, NPRA had received responses'from 130 refineries
representing about 12.5 million barrels per day or 88 percent of U.S. crude
capacity. These data were made available to EPA at a meeting with NPRA in
Hashington, D. C. on July 16, 1974. The survey indicates that approximately
25 percent of the gasoline output can currently be made as low-sulfur (100 ppm),
unleaded. Also, ten refineries, with a total crude capacity of 607,000 bpsd
(approximately 4.3 percent of the U.S. capacity) can make 100 percent of their
gasoline as low-sulfur, unleaded now. For the other refineries to manufacture
100 percent as low-sulfur, unleaded would require a median of 4 years construction
lead time and approximately $3.7 billion incremental investment. Included in
this investment would be 510 million standard cubic feet per day of hydrogen
production, 2100 tons per day of sulfur recovery, 1.9 million bpsd of cat
cracker feed desulfurization, 0.8 million bpsd of naphtha destilfurization, 0.6
million bpsd of reforming, and 49,000 bpsd of isomerization.
71
-------
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75
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FIGURE 4
ON/v- F'ACILi fi IS REOiHRFD TO LOWER
SULFUR CONTENT OF THE GASOLINE POOL
Texaco
SELECTED OPTION
FCCU FEED
"""I
HYDROGEN
GENERATION
UNIT
H-,5
RUN GASOLINE
GAS OIL
HYDROTREATER
SULF'JR
RECOVERY
UNIT
LIGHT STRAIGHT V
GASOLINE
HYDROTREATER
SULFUR REMOVAL
FCCU
SULFUR
K> BLENDING
SULFUR REMOVAL
Texaco
ALTERNATE OPTION
r
L
FCCU GASOLINE "K
LIGHT STRAIGHT
RUN GASOLINE
H2S
r"
H2 I
r |
CRACKED >^
GASOLINE J "
HYDROTR EATER
STRAIGHT LV> \
HUN """""" """ "
HYDROTR EATER
? V
SULFUR
RECOVERY
UNIT
CATALYTIC
REFORMER
c5-c6
ISOMER1ZATION
SULFUR
"1
^J
.MI . ^ni nf P^J ni p- T
76
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NPRA SURVEY OF
U.S. DOMESTIC PETROLEUM REFINING INDUSTRY'S
CAPABILITY TO MANUFACTURE LOW-SULFUR
UNLEADED MOTOR GASOLINE
A. Introduction
In the March 8, 1974 Federal Register, the Environmental Protection Agency
expressed concern over the sulfate emissions from automobiles equipped with catalytic
converters and requested information on alternative control systems including "Control
of Automobile Sulfate Emissions Through Fuel Modifications."
The National Petroleum Refiners Association has completed a survey of the
U.S. domestic petroleum refining industry to develop information concerning the impact
of reducing the sulfur content in unleaded gasoline to 100 parts per million (100 ppm)
during the period 1974 - 1980.
A survey questionnaire was sent to each petroleum refining company to be
completed for each refinery which had the capability to manufacture finished motor
gasoline. The survey was designed to give not only an overall picture of the effects
of unleaded gasoline sulfur control but also to demonstrate the large variation between
refineries in the industry's current capability to manufacture low-sulfur unleaded gasoline
and the need for additional process facility requirements.
Survey responses were received from refiners operating 148 refineries, having
a combined crude charge capacity of 13.2 million barrels per day (b/d). The data in
this report represents more than 90% of the U.S. crude processing capacity and
approximately 95% of the finished gasoline manufacturing capacity.
The individual refinery data in the accompanying Tables have been tabulated
by three capacity categories:
1) 100,000 b/d and over -- (46 refineries),
2) 30,000 - 99,999 b/d ~ (63 refineries),
3) under 30,000 b/d (39 refineries).
Within the first category, the capacities of the 16 largest refineries have been
combined and the refineries listed randomly in order to maintain the confidentiality of
data due to the uniqueness of their capabilities.
77
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B. Survey Results
Table 1 summarizes the $3.7 billion industry capital investment and 361 facilities
which are projected to be needed in the period 1974 - 1980 for the manufacture of low-
sulfur (100 ppm) unleaded gasoline by the 148 refineries in the survey.
The majority of survey respondents stated that it would not be economically
feasible to provide for the incremental (i.e. 50%) construction or expansion of desul-
furization facilities, if the entire gasoline poo1 -vould eventually be desulfurized.
Therefore, the total projected capital investment of S3.7 billion would be expended at
the time desulfurization of unleaded gasoline was mandated. It is important to note
that this expenditure has been estimated in 1974 dollars and that by the time the money
would actually be spent in the late 1970's the amount would be much higher.
The adverse impact on the small and medium size refineries is apparent from
reviewing the range and average costs per barrel of refinery capacity shown in Table 1 .
Desulfurization of the total unleaded gasoline pool of these refineries would result in
a per barrel cost of more than double that of the large refineries. The variation in the
per barrel costs are due in part to different crude types, sulfur content of crudes, refinery
size and process configurations.
Respondents to the survey indicated six categories of additional process plants
would be needed to provide the capability to desulfurize unleaded gasoline during the
period 1974 - 1980. The capacities and number of these new process facilities are
summarized in Table 2 for each refinery s>7.e category. Here again, the adverse impact
on small and medium size refineries of desulfurizing unleaded gasoline is substantiated
by the fact that they will need a total 242 new process facilities for their 4.3 million
b/d of crude capacity while the large refineries will only require 119 new process
plants for their 8.9 million b/d of crude capacity. The number of new plants is perhaps
more important than capacity in that technical manpower is more closely related to the
number of plants. Survey respondents believe that it is not within the capability of
the already overloaded engineering/construction industry to complete these desulfurization
facilities in the short term (3 years) while simultaneously constructing refinery facilities
to meet the country's increased energy demands.
The present extended refinery construction periods, due largely to the recent
doubling or tripling of the time required for delivery of many major equipment items,
are widely recognized as a major problem in the U.S. energy picture. This situation
is not expected to ease and may become tighter even without the imposition of more
stringent sulfur specifications for unleaded gasoline.
Tables 3,4, and 5 delineate the additional capacity of process facilities needed
to manufacture low-sulfur (100 ppm) unleaded gasoline. Those refineries having no
capital investment costs shown either did not require additional desulfurization facilities
or did not report on plans to install additional gasoline facilities. The large variation
in additional process capacities and investment costs for new desulfurization requirements
is amply demonstrated upon a review of these three Tables.
78
-------
Table 6 summarizes the current capability of respondents to manufacture low-sulfur
(100 ppm) unleaded gasoline. Although the average capability to make this fuel is about
30% of the gasoline pool of refinery respondents, it is distributed such that 49 refine nes
with a crude capacity of 3.6 million b/d, can only manufacture less than 10% of their
gasoline stocks as low-sulfur unleaded gasoline.
As can be seen from the Fable, 38 refineries operated by 16 companies, can
currently manufacture over 30% of their gasoline pool as low-sulfur unleaded gasoline.
This capability amounts to about 1 .2 million b/d. Although this volume of low-sulfur
unleaded gasoline appears adequate to satisfy the expected 1975 demand, any
regulation by the EPA and FEA requiring the nationwide distribution of low-sulfur
unleaded gasoline would be severely disruptive due to the limited production base.
Moreover, logistic problems involving segregated storage, component exchanges,
quality control, and transportation of this sterile fuel would certainly result in
additional costs. With such a limited manufacturing base, any regulation further
limiting the sulfur content of unleaded gasoline could not be very effective until
significant capital expenditures and refinery construction efforts are consumated.
Tables 7,8 and 9 show the the anticipated average weight per cent of sulfur
in the respondent's crude oil and gasoline pool for 1974 and 1980. For all categories
of refineries, trends in crude supplies are in the direction of increasing sulfur content
with the larger refineries indicating significant increases in sulfur while the small
refineries show only nominal increases. Further analysis of the sulfur content of
gasoline pool of the refinery respondents reveals a slight increase in the sulfur level
in the large and medium size refineries while the small refineries expect to have
essentially the same sulfur level in the gasoline pool.
The projected capital investment, for desulfurization facilities detailed
In Tables 3,4 and 5 correlate quite closely to the sulfur data shown in these Tables.
Finally, although the data on energy consumption directly associated with
the desulfurization of unleaded gasoline varied quite widely, it is estimated that an
increase in energy requirements of between 100,000 - 200,000 b/d of equivalent
fuel oil (approximately 1% of crude charge) would take place; and, depending on
the processing method selected, additional losses in gasoline and other products
yields could result.
Although no quantitative data were requested, refiners were asked to
discuss the possibility of producing unleaded gasoline with 50 ppm of sulfur.
Many responded that they did not know how this could be done consistently.
It should be noted that to guarantee a 50 ppm maximum sulfur level in the finished
unleaded gasoline, the sulfur levels would have to be much lower to allow for
p nt upsets and gasoline blending flexibility.
79
-------
C. Conclusions
The ramifications of desulfurizing unleaded gasoline to the level of 100 ppm
or less, as detailed in the preceding sections, provide sufficient justification in
pursuing a cautious and comprehensive approach before either proposing or promul-
gating regulations to desulfurize unleaded gasoline as a means of controlling
automotive sulfate emissions through fuel modifications. The critical energy and
inflation problems of our nation demand that we seek and achieve the solution which
enhances our energy self-sufficiency while effectively curbing inflation.
,80
-------
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-------
TABLE: ,
NEW PROCESS CAPACITY REQUIREMENTS TO
MANUFACTURE LOW-SULFUR (100 ppm) UNLEADED MOTOR GASOLINE
Refineries with 100,000 and over b/d capacity
1.-
2.
3.
4.
5.
6.
7--
8.^
9.
10.
11.
12.
13.
14.
15.
16
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
41.
42.
43.
44.
45.
46.
Refinery
Capacity
(M b/d)
*
> **
190
190
130
180
170
170
170
170
170
150
150
140
140
140
130
130
120
120
120
120
110
110
110
110
110
100
100
100
100
iQO
Totals 8,900
FCC Feed
Treating
(M b/d)
105
87
50
150
35
50
30
69
70
57
20
60
75
60
56
55
48
52
6
40
20
35
10
15.5
27
1,282.5
Naphtha/Gasoline Catalytic Isomerization Hydrogen Sulfur Copital
Treating Reforming Plant Plan! Costs
(Mb/d) (Mb/d) (Mb/d) (MMscf/d) (Tons/d) ($ million)
15
5
18
7.5
15
33
12
17
40
25
7
25
32
20
89
30
3.1
393.6
87 8.8
15
65
5
7.5
42 8
19
12
17
40
10
20
15 20
40
30
30
16
16
22 10
10
20
10 12
9
30
3.1 2.3
10
316.5 25.1 320.1
50.0
120 0
-------
NEW PROCESS CAPACITY REQUIREMENTS iw
MANUFACTURE LOW-SULFUR (100 ppm) UNLEADED MOTOR GASOLINE
Refinerias with 30,000-99,999 b/d capacity
Isomerization
(Mb/d)
1,
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
41.
42.
43.
44.
45.
46.
47.
48.
49.
50.
51.
52.
53.
54.
55.
56.
57.
58.
59.
60.
61.
62.
63.
Refinery FCC Feed
Capacity Treating
(M b/d) (M b/d)
95
95
90
90 30
90
90 50
85
85 33
85
85
85
85 35
85
75 75
75 15
70
70
70 20
70
70 35
70
65 16
65
65 10
65
65 35
60
60
60 47
55 12.5
55 25
55 41
55
50
50 11.1
50 24
50 12
50
50 27
50 13
50 25
45
45 15
45
45 8
45 18
45
40
40
40 15
40
40 15
40
40 8
40
40
35 12
35 14
35
35 6.1
30
30 12.5
30 14
Naphtha/Gasoline Catalytic
Treating Reforming
(M b/d) (M b/d)
5
10
on o/-»
OU £\J
28 8
20 20
on on
£\J Z\)
16.5
94 fl
^*t o
T\
f-O
8
11 10
2.6
2.5
25 25
OO oi
22 22
50
7.5
10
14
A 1
o . i
2
15 15
1(1
f U
26
7 14
4
6
10
5.3
5
4 4
8
10
7.1 9
3
1.8 5.8
8 8
Totals 1,462.6
729.2
406.2
0.8
3
264.0 24.8
Hydrogen Sulfur
Plant Plant
(MM scf/d) (Tons/d)
4.8
17
25 50
25 50
15 40
25 50
5
5
10
25 50
150
9
33.5
5 33
1.25 2
22
30
10 40
55
2 20
15
3 15
5
15
30
Capital
Costs
($ million)
0.0
12.8
0.0
21.4
13.0
108.9
17.4
18.0
21.0
24.7
23.3
96.2
25.0
13.0
44.0
18.0
13.0
22.0
10.0
96.2
7.0
4.8
5.5
14.2
6.0
96.2
46.0
39.8
44.9
6.0
16.6
25.3
37.0
25.5
21.0
21.9
32.0
5.0
33.3
10.0
75.9
29.3
11.0
3.0
38.0
25.0
15.0
0.0
3.6
9.7
7.5
16.9
4.0
22.3
4.0
0.0
15:6
53.1
.5
6.8
0.0
6.0
19.5
161.C
731.5 1,462.6
-------
NEW PROCESS CAPACITY REQUIREMENTS TO
MANUFACTURE LOW-SULFUR (100 ppm) UNLEADED MOTOR GASOLINE
Refineries with less than 30,000 b/d capacity
TABLE 5
Refinery
Capacity
(M b/d)
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
29
29
29
29
27
27
26
26
25
25
25
23
23
22
22
21
21
20
20
16
16
16
13
13
11
11
10
10
10
9
9
9
6
6
5
5
5
3
3
FCC Feed
Treating
(M b/d)
16
17
8
10
10
10
9
10
10
10
1.5
6
3
3.5
2
3.5
Naphtha/Gasoline Catalytic bomerization Hydrogen Sulfur
Treating Reforming Plant Plant
(Mb/d) (Mb/d) (M b/d) (MM scf/d) (Tons/d)
14
6 6
3.6
5
7 4
7
5
2.5
5 5
14.3 14.3
8 4
2 2
4
1
6
2 2
1.5 1.5
2
3.6 25
5
4.5 25
2.8 25
6
1.8 9
5 25
5 25
5 25
5
2 10
1.5 15
1.5 10
10
0.7 3
Ccp'tc..-'
Costs
($ mlHIon)
9 0
0.0
13.2
1" '
7.2
3.0
5.5
5.5
10.4
6.6
8.0
6.0
10.9
12.0
5.6
11.3
44.0
0.0
44.0
44.0
0.6
4.5
6.2
5.8
0.0
6.9
0.0
8.1
0.0
1.6
6.5
0.0
0.0
5.0
0.0
9.2
0.0
0.0
0.0
Totals 665
129.5
88.9
43.8
35.4
223
316.0
85
-------
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-------
TABLE 7
SULFUR CONTENT (AVG. WT.%) IN CRUDE OIL AND GASOLINE
FOR REFINERIES WITH CAPACITY 100,000 b/d AND OVER
Refinery
Capacity
21
3. 1
4. V
5.
6.
7-J
8^^y
r \
9- \
10. 1
11. I
12. \
13. /
14. /
15.
16^
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
41.
42.
43.
44.
45.
46.
Total capacity
of 2. 59 million
* b/d for refineries
larger than -
300,000 B/D
Total capacity
of 2.21 million
^ b/d for refineries
larger than -
200,000 B/D
190
190
180
180
170
170
170
170
170
150
150
140
140
140
130
130
120
120
120
120
110
110
110
110
110
100
100
100
100
100
*Refineries grouped together
1974
Crude
1.50
1.00
1.00
.96
.65
.48
.30
.00
.00
.00
.00
.00
.50
.50
.40
.30
1.10
1.50
.30
1.40
1,25
.38
1.10
.20
.40
1.20
.22
.91
1.10
2.60
.30
.80
1.20
.50
.30
.60
2.50
.65
1.40
1.00
.50
.20
1.60
1.00
.80
.50
to maintain
Gasoline
.80
.066
.05
.025
.025
.009
.06
.011
.05
.04
.03-. 04
.01
.01
.005
.01
.04
.11
.005
.013
.07
.02
.024
.06
.013
.06
.01
.04
.021
.04
.07
.01
.02
.016
.C3
.035
.10
.038
.04
.04
.05
.026
.009
.02
confidentiality of data.
87
19
Crude
1.00
.72
1.00
.90
.90
1.20
1.50
1.20
2.00
.70
1.30
1.00
1.00
1.10
1.50
.35
1.80
1.50
.30
.80
.20
1.00
2.00
1.70
1.32
1.55
2.00
.30
.70
1.20
1.00
1.55
2.50
.65
1.40
1.00
.70
1.30
1.90
1.20
1.20
.90
80
Gasoline
.065
.0437
.08-. 12
.052
.03
.0123
.06
.013
.03
.04
.03-. 04
.015
.016
.005
.01
.04
.12
.01
.013
.07
.02
__
.10
.016
.04
.01
.03
.04
.07
.015
.01
.02
.035
.10
.038
.04
.06
.01
.026
.014
.02
-------
SULFUR CONTENT (AVG. WT.%) IN CRUDE OIL AND GASOLINE
FOR REFINERIES WITH CAPACITY 30,000-99,999 b/d
TABLE 8
Refinery
Capacity
1974
1980
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
37.
38.
39.
40.
41.
42.
43.
44.
45.
46.
47.
48.
49.
50.
51.
52.
53.
54.
55.
56.
57.
58.
59.
60.
61.
62.
63.
95
95
90
90
90
90
85
85
85
85
85
85
85
75
75
70
70
70
70
70
70
65
65
65
65
65
60
60
60
55
55
55
55
50
50
50
50
50
50
50
50
45
45
45
45
45
45
40
40
40
40
40
40
40
40
40
35
35
35
35
30
30
30
Crude
1.0
1.2
.50
.20
2.00
.16
1.70
.40
.70
.65
.25
.25
1.25
.55
1.31
.35
1.60
1.00
.25
.27
1.7
2.0
1.21
.94
1.45
.30
.20
1.40
.20
.60
.06
.40
1.5
.93
.35
.65
.75
.45
.30
.40
.47
1.2-1.7
1.6
.25
.50
.60
.50
.82
1.0
.90
.28
.50
.35
.20
1.7
.50
.50
.50
1.02
1.0
.75
.40
.80
Gasoline
.005
.016
.00?
.016
.05
.012
.10
.02
.03
.03
.02
.002
.05
.035
.016
.06
.05
.03
.042
.015
.10
.23
.016
.025
.035
.02
.028
.10
.02
.013
.04
.095
.060
.02
.087
.03
.030
.10
.02
.045
.09-. 096
.06
.025
.05
.025
.025
.06
.03
.014
.03
.025
.05
.015
.05
.02
.03
.03
.06
.01
.02
.03
Crude
1.0
1.8
1.09
.20
3.0
.80
2.0
.7
1.0
.30
.50
1.25
1.20
.35
1.60
1.00
.85
.55
1.5
2.0
1.30
.94
1.45
.65
.25
1.40
.80
.11
1.5
.83
.35
.65
.75
.45
.30
.40
.58
1.2-1.7
1.8
.25
.50
.60
.80
1.40
1.00
.28
1.15
.35
.45
1.5
.50
1.50
1.50
1.35
.75
2.0
Gasoline
.005
.023
.01
.03
.033
.10
.03
.05
.02
.035
.05
.030
.016
.05
.03
.05
.028
.02
.01
.03
.016
.025
.032
.02
.028
.02
.095
.054
.02
.03
.035
.10
.02
.034
.09-. 096
.06
.025
.05
.025
.025
.015
.04
.014
.07
.025
.01
.02
.05
.06
.10
.08
.01
.045
88
-------
TABLE 9
SULFUR CONTENT (AVG. WT.%) IN CRUDE OIL AND GASOLINE
FOR REFINERIES WITH CAPACITY UNDER 30,000 b/d
Refinery 1974 1980
Capacity Crude Gasoline Crude Gasoline
1. 29 1.00 0.5 1.10 .05
2. 29 .30 .01 .30 .01
3. 29 1.00 .09 1.00 .09
4. 29 .62 .038 .86 .052
5. 27 .325 .019 .305 .019
6- 27 .15 .02 1.05 .02
7. 26 .70 .05 .70 .05
8. 26 1.70 .13 1.70 .10
9. 25 1.20 .12 1.50 .14
10. 25 .40 .032 .60 .04
11. 25 .50 .01 .50 .01
12. 23 .30 .03
13. 23 .60 .03 .50 .025
14. 22 .60 .01 .70 .005
15. 22 .645 .035 .645 .030
16. 21 .60 .03 .90 .05
17. 21 1.32 .034 1.32 .034
18. 20 .14 .01 .14 .01
19- 20 .28 .027 .74 .048
20. 16 .55 .032 .75 .042
21. 16 .08 0.1-0.2
22. 16 .28 .033 .50 06
23. 13 .40 .023 .60 .03
24. 13 .50 .15 .50 .01
25. 11 .05 .01 .05 .01
26. 11 2.90 .17 2.90 .17
27. 10 .20 .002 .22 .002
28. 10 .30 .10 .30 .01
29. 10 .10 .008-.014 .10 .008-.014
30. 9 .015 .001 .020 .001
31. 9 .60 .025
32. 9 .08 .0001 .08 .0001
33. 6 .10 .008-.014 .10 .008-.014
34. 6 1.30 .90 1.30 .90
35. 5 .10 .008-.014 .10 .008-.014
36. 5 1.6 0.2 1.6 0.2
37 5 .50 .03 .80 .04
38 3 .10 .008-.014 .10 .008-.014
3? 3 .29 - .25
89
-------
Appendix A2.2
EPA-650/2-74-130
PRODUCTION
OF LOW-SULFUR GASOLINE
by
W. F. Hoot
M. W. Kellogg Company
1300 Three Greenway Plaza East
Houston, Texas 77046
Contract No. 68-02-1308
ROAP No. 21ADE
Program Element No. 1AB013
EPA Project Officer: John B. Moran
Special Studies Staff
National Environmental Research Center
Research Triangle Park, North Carolina 27711
Prepared for
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
July 1974
90
-------
PART 1
PRODUCTION OF LOW-SULFUR GASOLINES
(PHASE 1)
CHAPTER 1
INTRODUCTION
This part of the report covers work which was performed under Contract No.
68-02-1308, Environmental Protection Agency, Office of Research and Moni-
toring, Task No. 10, Phase 1.
The crude- mix used in Phase I resulted in capacities of the reformer,
catalytic- i-racker and alkylation units which do not match the average I'.S.
refinery capacities. Future work planned for Phase II will modify th<-
Phase I study in order to match the average l;.S. production capacities of
1iie.se units.
I uture work planned for Phase III will be based on crudes and refiner>
capacities typical of the l.os Angeles area.
( atalylic -onverters are to be installed in the exhaust systems of new cars
starting with the 1975 model year. The use of catalytic converters is in-
tended to control carbon monoxide ancj hydrocarbon emissions. However, the
catalvsts convert sulfur in the gasoline into sull'uric acid mists in the exhaust.
'I he purpose of this study is to determine the impact on oil refineries lo
produce unleaded, low-sulfur gasolines and also to desulfurize all gasolines
produced tor United States sales.
Prior to installation of additional desulfuri/ation process units, unleaded,
I'lW-sulfu.' gasolines would have to be blended I rom existing low-sulfur
gasoline blendiny stocks.
91
-------
CHAPTER 2
SUMMARY
Automotive exhausts are to have catalytic mufflers for pollution control
starting with the 1975 models. However, the catalysts convert the sulfur
in gasoline into sulfuric acid mists in the exhaust.
This study indicates that the "typical" United States refinery can produce
no-lead, low-sulfur gasoline blended from normal butane, alkylate and re-
formate. The predicted sales percent of no-lead and premium gasolines
can be met for 1975 and 1976 with the total gasoline production meeting
the KPA phase-down of lead antiknock additives. New desulfurization and
octane upgrading facilities would have to be onst ream by 1977 to produce
the required sales percent of both no-lead, low-sulfur gasoline and premium
gasoline.
The total gasolines could be made low sulfur by hydrodesulf'urization of
the gas oi! leedstock to catalytic cracking and hydrodesulfuri zation of the
light virgin and light thermal gasolines. Economics indicate that this scheme
would add 0. 74 cents per gallon to the cost of gasoline production.
An alternate case considers hydrodesulfuri zation of the catalytically cracked
gasoline rather than the feedstock to the catalytic cracker. Economics in-
dicate that use of this scheme to produce low-sulfur gasoline would add
0. 95 cents per gallon to the cost of gasoline production. This cost includes
a penalty of 0.33 cents per gallon debited to the lower octane resulting
from partial hydrogenation of olefins in the l-'C'C gasoline.
92
-------
CHAPTER 3
DISCUSSION
GENERAL REFINERY SITUATIONS
No two crude oils or two refineries are the same. Furthermore,
no two refineries will produce and have the same product demand.
Depending upon the crude properties and refinery process capabili-
ties, different refineries are geared to the following categories or
combinations thereof:
Productions of gasolines, mid-distillates and residual oil.
Petrochemical production.
Lubricant production.
Asphalt production.
In crude topping and vacuum operations, crude oils can be distilled
into fractions with true boiling cut points approximately as follows:
Butanes and lighter components to gas recovery.
Pentanes to 200°F light gasoline for blending to gasoline
or isomerization of the pentanes and hexanes to upgrade the
octane number.
200 °F - 350° F naphtha for reformer feedstock to upgrade
the octane number or produce aromatics.
350 °1 - 500° F kerosine for production of aviation jet turbine
fuel and kerosine or for blending to diesel fuel or No. 2 fuel oil.
600 °I- - 1,000°F gas oil feedstock to catalytic cracking,
thermal crackn^ or hydrocracking.
Heavier than l.Ou. °F residuum for blending No. 6 fuel oil
or to asphalt or produced as feedstock for visbreaking, de-
layed coking, fluid coking or solvent deasphalting.
Typical ASTM distillations of refined products to sales are shown in
Figure 1-1. Gasolines distill in the range of 80° F to 400° F, kerosine
and jet fuel (kerosine-lype) distill in the range of 340° F to 530° F, and
diesel fuel and No. 2 fuel oil distill in the range of 350 °F to 650° F.
93 . r(
-------
o
CO
~0
DATA SOURCE
___j I
U.S. BUREAU MINES
PETROLEUM PRODUCTS SURVEYS
70~0~-
D
"To
To"
60
80
TOO"
VOL % DISTILLED
Figure 1-1. Typical ASTM distillations of petroleum products.
. 94
-------
U.S. PRODUCTION OF PETROLEUM PRODUCTS
United States refineries produce petroleum products in relation to
the market demands for quantities and properties. . Each refinery
bases its operations on market demands and availability of crudes
within the limitations of its refinery process units and the flexibility
of operating conditions.
Table 1-1 shows the U.S. production of petroleum products in 1972.
Table 1-2 shows the U.S. demand of mid-distillates by use in 1973.
The term "mid-distillates" refers to the distillates boiling between
gasoline and No. 6 fuel oil and comprises the kerosine, aviation
jet fuel, diesel fuels and No. 2 heating oil. Kerosine, aviation jet
fuel and No. 1-D diesel fuel are produced from the distillates boiling
between 350 °F and 500° F true boiling cut points. No. 2 heating
oil and No. 2-D diesel fuel are blends of essentially 50 percent
of the 350° F to 500° F fraction with 50 percent of the 500°F to
600 °F fraction.
Table 1-3 shows typical properties of the petroleum products sold
in the United States in 1972 and 1973.
It appears that the crude oils to supply needs in the United States
above the domestic production will be supplied by the Persian Gulf
countries. These crude oils have high sulfur contents and yield
more residual fuel oil.
Therefore, it is expected that the sulfur content in the products
will increase in the future unless additional desulfurization units
are installed.
95
-------
Table 1-1. U.S. PRODUCTION OF PETROLEUM PRODUCTS IN 1972
Production
Gasoline from Crude
Natural Gas Liquids to Gasoline
Gasoline Content of \'aphtha-tvpe
,U>i 1-uel
i , . . < s i n e
Ktjrosme-type Jet I'uel
Kerosine Content of Naphtha-
is pe Jet 1- uel
Distillate Fuel Oil
Residual Fuel Oil
1 .ubricants
Losses
Unaccounted
Crude Runs to Stills Plus
.Natural Gas Liquids to
Gasoline
Relmery Input
Crude Runs to Stills
Natural Gas Liquids to Gasoline
Alillion Barrels
Yield, %'
9
" »
9
^ »
4,
.Million
4,
014
305
38
U57
80
233
38
3 51
P64
293
65
5
552
587
Barrels
282
305
47. 0
7. 1
0.9
1)5.
1. 9
5.4
0.9
8.
2°.
6.
1.
0.
12.
107.
Input,
100.
7.
0
y
6
8
5
1
9
1
%-
0
1
4, 587
107. 1
'Volume percent on crude input
96 -
-------
Table 1-2. U.S. DEMAND FOR MID-DISTILLATES BY USE IN 1973
Million Barrels
Kerosine 80
Kerosine-type Jet Fuel 233
Kerosine Content of Naphtha-type Jet Fuel 38
No. 1 Range Oil 15
Diesel Fuel Used on Highways 164
Industrial Uses 50
Oil Company Fuel 14
Railroads 86
Vessel Bunkering 21
Military Uses 17
Heating Oil 509
Gas and Electric Company Public
Utility Power Plants 35
Miscellaneous and Unaccounted
3~5"2
5T4"
60
6. 1
17. 6
2.9
1. 1
12.4
3.8
1. 1
6. 5
1. 6
1.3
38. 5
2.6
TTi
TTTT
4. 5
Total Mid-distillates
1,322
T0().(3
97
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98
-------
UNLKADKD CiASOLIMC
The Environmental Protection Agency has issued regulations
(Jan. 10, 1973) on unleaded gasoline (minimum 91 research oclane)
to be supplied starting in July, 1974.
Unleaded gasoline to be used in automobiles equipped with catalytic
converters is to be generally available in United States.
General Motors announced plans to equip all its 1975 models with
converters, compared to about 60 percent for Ford. Thus about
80 percent of the 1975 automobiles will have catalytic converter's.
Figure 1-2 shows predicted future sales percent of unleaded and
premium gasolines.
99
-------
in
u
._!
w
fxi
m
o
a,
100 --
90 ..
80
50 --
5C
40 --
30 . :
20 - -
10 --
0
PREMIUM GASOLINE
SALES
PREMIU::
GASOLINE
RECOMMENDED
FOR CARS
OH ROAD
r
/
NO-LEAD GASOLINE
/
/
x
\
/
/
/
/
\/ \
\
1965
1970
197!
1980
1985
1990
YEAR
Figure 1-2. Projected percent of sales of premium and no-lead gasolines.
100
-------
PHASE-DOWN OF LEAD IN GASOLINE
The Knvironmental Protection Agency has ordered a phased reduction
of lead antiknock additives in gasoline (Federal Kegister, Dec. 6, 197.'i).
These regulations restrict the average lead content in all grades of
gasoline (including unleaded gasoline) produced by any refinery as
follows:
Lead Content
January 1 Cirams per Gallon
1975 1.7
1976 1.4
1977 1.0
1978 0.8
1979 0.5
101
-------
OCTANES OF TOTAL U. S. GASOLINES
The 1972 properties of the total U. S. gasoline pool were estimated
from U. S. Bureau of Mines surveys and Ethyl Corporation sales
data as follows:
Research Octane 97. 5
Motor Octane 90. 0
Lead, g/gal. 2. 24
Sulfur, wt% 0.031
The response of lead content in the total U. S. gasoline pool was
estimated from the lead response of various premium and regular
gasoline blends. Figure 1-3 shows the research and motor octanes
of the total U. S. gasoline pool in 1972 as a function of lead content.
102
-------
GRAMS , .-B
GALLON
115
mm
-i
o
ft
110
TOTAL U.S. GASOLINE POOL IN 1972
LEAD, g/gal. 2.24
RESEARCH OCTANE 97.5
MOTOR OCTANE 90.0
SULFUR, WT% 0.031
105
03
3
Z
O
O
-rrl no
105
100
j 0
o
o
- 05
I- 100
o
- t
1C IS 2.0 2 5 3.0 4.0 5.0 6.0
ANTIKNOCK CONTENT, GRAMS METALLIC LEAD PER GALLON
Figure 1-3. Octane of total U.S gasoline pool in 1972.
103 \
-------
SULFUR IN GASOLINE BLENDING COMPONENTS
The sulfur contents of various light straight gasolines are shown in
Table 1-4, and the sulfur contents in miscellaneous samples of other
gasoline blending components are shown in Table 1-5.
The sulfur content is variable and depends upon the crude source for
catalytically cracked gasoline, light straight-run gasoline, natural
gasoline and coker or thermal gasoline.
Reformate and alkylate can be considered sulfur-free. The bi-
metallic reformer catalyst requires that the feed naphtha be de-
sulfurized to less than 1.0 ppm sulfur. The feedstocks to alkylation
are desulfurized or essentially sulfur-free. In alkylation, the
hydrofluoric acid catalyst or sulfuric acid catalyst quantitatively
removes sulfur.
Therefore, production of sulfur-free gasoline generally will require
the desulfurization of the thermally cracked gasoline, catalytically
cracked gasoline and light straight-run gasoline.
Desulfurization of the gas oil feedstock to catalytic cracking will
produce catalytically cracked gasoline with low sulfur content.
104
-------
Table 1-4. SULFUR IN LIGHT VIRGIN GASOLINES*
Sulfur, WT %
Crude Source In Light Ciasoline
East Texas 0.01
West Texas Intermediate Sweet 0.038
Ellenberger (Texas) 0. 01
West Texas (0.31 wt % sulfur in crude) 0.01
West Texas Sour 0. 15
Oklahoma City 0. Oil
Tinsley (Mississippi) 0.006
Corning (Ohio) 0.060
South Louisiana 0.006
Kuwait 0. 006
Light Arabian (Saudi Arabia) 0.02
Light Iranian (Iran) 0. 01
- 200°F TBP
105
-------
Table 1-5. SULFUR IN GASOLINE BLENDING COMPONENTS
Gasoline Blending Components : Sulfur, WT %
C'alalylically ('racked Gasoline 0.055
0. 0:56
0.034
0.07
0. 327
0.039
0. 175
Alkvlatt- 0.001
0.008
0.002
0.003
Catalytic Reformate 0.001
0.007
0.013
0.006
0.002
Coker Gasoline 0.089
0. 19
1.43
0.59
\aturaLGasoline 0.008
0.010
0.027
Analyses of miscellaneous samples
106 <: <
-------
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE WITHOUT NEW FACIL.iJES
The time to plan, finance and construct refining facilities to upgrade
gasoline blending components requires two to three years from the
date of a firm decision to proceed.
During the period until the additional gasoline upgrade facilities are
onstream, the no-lead, low-sulfur gasolines will have to be blended
from low-sulfur components which can be produced in the present
refining facilities.
The potential production of gasolines with the EPA phase-down of
lead is shown in Table 1-6. Alkylate and reformate are thejiigh-
octane components and are components in both the unleaded and
premium gasolines. The gasoline blends shown in Table 1-6 are
based on the yields and properties from "A" Refinery (Case 1).
The unleaded gasoline would be sulfur-free, since the blend consists
of normal butane, alkylate and reformate. Comparison of the re-
sults in Table 1-6 with the projected percent of sales indicates that
the present day refineries could produce the required sales percent
of unleaded and premium gasolines in 1975 and 1976. New desulfuri-
zation and new octane upgrading facilities would have to be onstream
by 1977 to produce the required sales percent of both no-lead, low-
sulfur gasoline and premium gasoline.
107
-------
Table 1-6. POTENTIAL GASOLINE PRODUCTION
WITH LEAD PHASE-DOWN (1)
Year
Lead Content, g/gal.
Allowed by E]
Total Gasoline Pool
Premium Gasoline
Regular Gasoline
Potential Gasoline, vol %
Unleaded (92 RON)
Premium (100 RON)
Regular (U4 RON)
Unleaded Gasoline, vol %
N-Butane
Alkylate
Reformate
Premium Gasoline, vol %
N-Butane
Alkylate
Reformate
FCC Gasoline
Regular Gasoline, vol %
N-Butane
Light Virgin Gasoline
Light Coker Gasoline
FCC Gasoline
Alkylate
Reformate
1972 1975 1976 1977 1978 1979
4 9 < '> \
* «- V - "
2.2
2.4
1.9
1.7
1.3
2.5
1. 2
1.4
1.3
3.0
1.4
1.0
0.7
3.0
1.3
0.8
0.7
-
1.2
0.5
0.65(3)
_
0.65
37
63
18
26
56
30
21
49
40
6
54
44
(3)
56
14.2 14.2 14.2 14.2
39.5 39.5 39.5 39.5
46.3 46.3 46.3 46.3
(3)
(3)
100
None
None None
14.2
39.5
46.3
7.3
14.4
2.0
76.3
11.9
25. 5
29.4
33. 2
7.3
16.6
2.4
73.8
11.9
25.5
29.4
33. 2
7.3
16.6
2.4
73.8
7.3
14.4
2.0
76.3
10.3
8.1
1.2
43. 1
17.1
20.2
(l)Based on gasoline yields and properties from "A" Refinery (Case 1).
Unleaded gasoline to be low-sulfur.
(2)Prior to I'JPA regulation.
(3)EPA regulation on lead content precludes production of unleaded and
premium gasolines if total gasoline pool requirements are to be met.
, 108
-------
CHAPTER 4
DESULFURIZATION OF GASOLINE
CASE 1: TYPICAL "A" REFINERY
As a basis of comparison, a "typical" United States refinery and
crude mix were selected to produce about the same distribution and
properties of gasolines, mid-distillates and \o. 6 fuel oil (Bunker
'C") as the United States production in 1P72.
The refinerv feedstock v.as considered to be a 32 API crude oil
containing 0.51 weight percent sulfur. I-'or calculations, the crude
mix was considered to be 90 percent South Louisiana and 10 percent
Kuwait.
The refinerv process units selected were as follows:
Crude and \ acuum Distillation
Catalytic Reformer with Hydrogen Pretreat Section
Fluid Catalytic Cracker with Vapor Recovery
Delayed Coker
Alkylation
Sulfur Recovery.
Figure 1-4 is a block flow diagram showing the yields and properties
of the intermediate and final product streams. C'ase 1 is based on
100,000 barrels per calendar day (BPCIJ) of crude oil. Thus, the
volume1 percent vields based on crude oil may be obtained by
dividing the HPC'D flows bv 1,000. The sulfur from the crude oil
is shown distributed in the product streams, recovered sulfur and
emissions to the atmosphere.
Table 1-7 shows a comparison of the product yields and product pro-
perties for C ase 1 \\ith the 1972 U. S. production. The distribution
of yields in Case 1 shows more uasohnes and rnid-distillates. This
may be explained bv the 13.4 percent unaccounted in the 1972 U.S.
production. The properties of the products show general agreement
between C'ase 1 and the U172 I . S. production.
109
-------
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110
-------
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111
-------
CASE 2: "A" REFINERY WITH HYDRODESULFURIZATION OF CATALYTIC
CRACKER FEED, LIGHT VIRGIN GASOLINE AND LIGHT COKER GASOLINE
In order to calculate the costs of producing sulfur-free gasoline,
hydrodesulfurization of the gas oil feedstock to catalytic cracking and
hydrodesulfurization of the light virgin and light coker gasolines were
considered. In Case 1, the sulfur content in the light virgin gasoline
would be 0. 004 weight percent. The light virgin gasolines listed in
Table 1-4 show higher sulfur content. Therefore, hydrodesulfurization
of light virgin gasoline should be included in the "typical" refinery
for cost purposes.
The refinery process units in Case 2 would be the same as in Case 1
with the following additions:
Gas Oil Hydrodesulfurization
Light Gasoline Hydrodesulfurization
New C'apacity for Amine Treating and Sulfur Recovery.
Figure 1-5 is a block flow diagram of Case 2 showing the yields and
properties of the intermediate and final product streams. The
yields and product properties also are listed in Table 1-7.
For gas oil desulfurization, the calculations are based on 80 percent
sulfur removal with a hydrogen consumption of 42 standard cubic
feet per pound sulfur removed (3. 5 mols hydrogen consumed per mol
sulfur removed). Above 85 percent sulfur removal, the hydrogen
consumption increases due to saturation of polyaromatics and hydro-
cracking.
In Case 2, the hydrogen produced in the reformer would be more
than adequate to supply the refinery needs.
The sulfur content would be 0. 008 weight percent in the total gasolines.
Economics for producing low-sulfur gasoline in Case 2 are summarized
in Table 1-8. Based on payout of the investment for the desulfurization
units in five years (20 percent rate of return), the total added costs
(above Case 1) would be about 0.74 cents per gallon of low-sulfur gasoline.
The economic basis is presented in the Appendix.
Table 1-9 shows the estimated investment for the desulfurization
facilities in Case 2. Table 1-10 shows a comparison of yields in Case 1
and Case 2. Table 1-11 shows the estimated utilities and catalyst re-
placement cost in Case 2.
112
-------
The apparent liquid gain in products over charges for Case 2 is 379
BPCD above Case 1. However, the utilities for the desulfurization
facilities would require 584 BPCD of fuel equivalent. Thus, Case 2
would show a net loss of 205 BPCD in comparison to Case 1.
. 113 .
-------
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vt.tv* t.rf tnrf»
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Figure 1-5. "A" refinery with hydrodesulfurization of cata-;
\1
-------
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,
. ***>*>.#
0.9*9#T%
vt /'.&
1« ^"^ f f./ ^4, ? \
lytic cracker feed, light virgin gasoline, and light coker gasoline.
115
-------
Table 1-7. COMPARISON OF PRODUCTS
U.S.
Total Gasolines
Yield, vol %*
°API
Sulfur, wt '/<
Octanes:
Research C'lear
Research +3 cc
Motor Clear
Motor +3 cc
Research+2.24 g/gal. 97.5
Motor+2.24g/gal. 90.0
Reid Vapor Pressure 10.7
Middle Distillates
" Yield, voT7r* 30.8
Kerosine and Kerosine-type Jet Fuel
1972
Production
55.0
61.7
0.031
Yield, vol <7<*
°API
Sulfur, wt 7
Diesel Fuel
~ Yield, vol %*
°AP1
Sulfur, wt%
8
42
0
8.
36
0
.5
.3
.066
-^
5
.21
No. 2 Furnace Oil
Yield, voT%*
°API
Sulfur, wt%
No. 6 Fuel Oil
Yield, vol '%*
°API
Sulfur, wt %
Viscosity, Furol at 122°F
Carbon Residue, wt %
Miscellaneous Yield, vol 7 *
Lubricants
Delayed Coke (wt '',)
GJS to Fuel (F.O.H.)
Unaccounted and Losses
12.7
35.1
0.22
6.8
11.0
1.6
170
9.3
1.5
13.4
Case 1
58/8
64.2
0.033
90.0
98.7
82.9
92.5
97.7
91.4
11.0
37.6
8.4
41.0
0.041
8.4
37.3
0.19
20.8
30.5
0.31
Case 2
59.6
64.3
0.008
89.6
99.1
82.5
92.9
97.8
91.4
11.0
37.3
8.4
41.0
0.041
8.4
37.3
0.19
20.5
31.0
0.11
Case 3
59.1
64.8
0.007
88.0
97.8
HJ: i
93.0
96.7
91.8
11.0
37.6
8.4
41.0
0.941
8.4
37.3
0.19
20.8
30.5
0.31
78
100
1.5
200
7.5
7.8
10.6
1.1
200
7.5
7.8
10.0
1.5
200
7.5
2.6
3.7
2.6
3.4
2.6
3.5
*Yield as volume percent of crude input
116
-------
Table 1-8. COSTS FOR GASOLINE DESULFURIZATION - CASE 2*
Investment for Desulfurization Facilities
Years to Payout
$13. 0 million
f>. 0
Cash Flow (13.0/5.0)
Depreciation
Net Profit
Income Tax
Gross Margin
Operating C'osts:
Depreciation
Operating Manpower
Utilities
Catalyst Replacement
Interest
Maintenance
Local Taxes and Insurance
Debit for Products
(Ca.se 1 - Case 2)
Credit for Lower Rutane C'harges
Total Operating Costs
Total Added Cost lor Low-sulfur
(lasolme
Million Dollars
per Year
2.60
0.87
1.73
1.73
3.46
0.87
0.22
1.40
0.28
0. 65
0.46
0.20
0. 18
*/CD
3,840
760
480
(-2, 570)
6.78 18,580
(0. 7-1 cents per gallon)
-Compared to Case 1
117
-------
Table 1-9. INVESTMENT FOR PROCESS UNITS - CASE 2
Process Unit
Light Gasoline Hydrodesulfurizer
Gas Oil Hydrodesulfurizer
Sulfur Recovery (Claus Plant)
Onsite Subtotal
Oi'fsite at 30 percent of Onsite
Total Investment
C'apacity
5, 700 BPSD
45,000 BPSD
Two 20 TPD Units
Investment, :
Million Dollars
2. 6
6. 5
0. 9
10.0
3.0
13.0
-Investment includes paid-up royalty (if applicable) plus initial charge for
catalyst.
-------
Table 1-10. COMPARISON OF YIELDS - CASE 1 AND CASE 2
BPCD
CHARGES
C'rude Oil
Lsobutane
\-Butane
Total Charges
PKODl CTS
} uel Gas, I
Propane
Gasolines
o. K.
Mid-distillates
Sulfur
\o. 6 Fuel Oil
Delayed Coke
Total Product (Excluding
Sulfur and Coke)
CASE I
100,000
3.864
4.065
107,929
CASE 2
100,000
3,478
3, 984
107,462
DIFKKRKiXCH
(-386)
(-81)
(-467)
3. 664
2,047
58, 873
37, 592
(21 TPD)
7, 784
(393 TPD)
3, 167
2, 028
59, 574
37, 302
(40 TPD)
7, 801
(393 TPD)
(-497)
(-19)
f701
(-290)
-
+ 17
-
109,960
109,872
(-88)
Apparent Gain (Products - Charges)
2, 031
2,410
+ 379
' 119 i
-------
Table 1-11. UTILITIES AND CATALYST REPLACEMENT - CASE 2
Process Unit
Light Gasoline Gas Oil
Hydrodesulfurization Hydrodesulfurization
Sulfur Total
Recovery
One 20
TPD Plant
Consumption of Utilities:
Electricity, kw 280
Fuel, MM Btu/hr 23.7
Cooling Water, gpm 380
Boiler Feedwater, Ib/hr
Steam Consumed, Ib/hr
Steam Generated, Ib/lir
Net Steam Consumed, Ib/hr
Cost of Utilities, $/CD
Catalyst Replacement Cost, $/CD 20
Fuel Equivalent of Utilities,
BPCD (F.O.E.)
2,250
24.4
2,400
58,000
40
1.5
5,250
5,000
740
2,570
49.6
2,780
5,250
58,000
5,000
53,000
3,840
760
584
,120
-------
CASE 3: "A" REFINERY WITH HYDRODESULFURIZATION OF LIGHT VIRGIN,
LIGHT COKER AND CATALYTICALLY CRACKED GASOLINES
Case 3 considers the costs to produce sulfur--free gasoline by hydro-
desulfurization of the catalytic-ally cracked gasoline rather than the
feedstock to the catalytic cracker.
The refinery process units in Case 3 would be the same as in Case 1
with the following additions:
FCC' Gasoline Hydrodesulfurization
Light Gasoline Hydrodesulfurization.
Figure 1-6 is a block flow diagram of Case 3 showing the yields and
properties of the intermediate and final product streams. The yields
and product properties also are listed in Table 1-7.
Sulfur removal from the FCC gasoline was selected to yield about
the same sulfur content in the total gasolines as in C'ase 2.
In Case 3, the sulfur removal would be 75 percent from the FCC
gasoline. At this desulfurization severity, 42 percent of the olefins
in FCC gasoline would be hvdrogenated, which would result in de-
creased research octane.
Economics for producing low-sulfur- gasoline in Case 3 are shown in
Table 1-12. Based on payout of the investment for the desulfurization
units m five years (20 percent rate of return), the total added costs
(above C'ase 1) would be 0. 95 cents per gallon of low-sulfur gasoline.
The costs include a penalty of 0. 33 cents per gallon debited to the
lower octanes which result from partial hydrogenation of olefins in
the FCC gasoline.
Table 1-13 shows the estimated investment for the desulfurization
facilities in Case 3. Table 1-14 shows a comparison of yields in
Case 1 and Case 2. Table 1-15 shows the estimated utilities and
catalyst replacement.
The apparent gain (difference between products and charges) for
C'ase 3 would be 38 BPC'D above the apparent gain for C'ase 1. The
utilities for the desulfurization facilities would required 594 BPCD
of equivalent fuel oil. Thus C'ase 3 would result in a net loss of
556 BPCD compared to Case 1.
121
-------
Figure 1-6. Case 3: "A" refinery with hydrodesulfurization
122
-------
i.i r**,c
^z^ifvD
(7A
*9 0 f.? !
tr.t ft.o
9*.7 f/-9
'--r
-------
Table 1-12. COST FOR GASOLINE DESULFURIZATION - CASE 3*
Investment for Desulfurization Facilities
Years to Payout
$9.0 million
5.0
Cash Flow (9.0/5.0)
Depreciation
Net Profit
Income Tax
Gross Margin
Operating Costs:
Depreciation
Operating Manpower
Utilities
Catalyst Replacement
Interest
Maintenance
Local Taxes and Insurance
Debit for Lower Octane Gasoline
Credit for Lower Butane Charged
Credit for Products
Total Operating Costs
Total Added Cost for Low-sulfur
Gasoline
Million Dollars
per year
1.80
0. 60
1. 20
1.20
2.40
0. 60
0.22
1.43
0.04
0.45
0.36
0. 14
3.02
(-0.04)
(-0.03)
$/CD
6. 19
3,920
100
8,280
(-120)
(-90)
8.59 23,530
(0. 95 cents per gallon)
'Compared to Case 1
.124
-------
Table 1-13. INVESTMENT FOR PROCESS UNITS - CASE 3
Investment, ;
Process Unit C'apacity Million Dollars
Light Gasoline Hydrodesulfurizer 57, 000 BPSD 2.6
FCC Gasoline Hydrodesulfurizer 26,700 BPSD 4. 3
Onsite Subtotal 6. 9
Ofisite at 30 percent of Onsite 2. 1
Total Investment fj.O
'"Investment includes paid-up royalty (if applicable) plus initial charge of
catalv st.
125
-------
Table 1-14. COMPARISON OF YIELDS - CASE 1 AND CASE 3
BPCD
CHARGES
Crude Oil
Isobutane
N-Butane
Total Charges
PRODUCTS
Fuel Gas, F.O. E.
Propane LPG
Gasolines
Mid-Distillates
Sulfur
No. 6 Fuel Oil
Delayed Coke
Total Product (Exqluding
Sulfur and Coke)
CASE 1
100.000
3,864
4.065
107,929
3,664
2,047
58,873
37,592
(21 TPD)
7,784
(393 TPD)
109,960
CASE"S"
100,000
3,864
4.043
107.907
3.431
2.047
59,122
37,592
(23 TPD)
7,784
(393 TPD)
109,976
DIFFERENCE
(-22)
(-22)
(-233)
+ 249
(+16)
Apparent Gain (Products - Charges)
2,031
2,069
+ 38
126
-------
Table 1-15. UTILITIES AND CATALYST REPLACEMENT - CASE 3
Process Unit Light Gasoline FCC Gasoline Tota'
Hydrodesulfuri/ation Hydrodesulfurizatipn
Consumption of Utilities.
Electricity, kw 280 1,320 1,600
Fuel, MM Btu/hr 23.7 111.1 134.8
Cooling Water, gpm 380 1,770 2,150
Cost of Utilities, S/CD 3.920
Catalyst Replacement Cost, S/CD 20 80 100
Fuel Equivalent of Utilities, 594
BPCD (F.O.E.)
127
-------
SULFUR DISTRIBUTION
Table 1-16 shows the sulfur distribution in the products and atmospheri
emission as pounds per hour sulfur and as the percent of the sulfur
in the crude charge.
The sulfur in gasoline is only a small fraction of the sulfur in the crude
oil charge. The final combustion of the products used as fuel in-
cluding gasolines, mid-distillates and Bunker "C" results in emissions
of sulfur oxides to the atmosphere. The sulfur in delayed coke may m
emitted to the atmosphere or he combined in metallurgical sla^;, . -
pending upon the use of the delayeci coke.
Table 1-16 shows that the recovered elemental sulfur would be 27.0
percent of the sulfur in the crude oil in a "typical" refinery (('-use i)
and 52.3 percent of the sulfur in the crude oil in Case 2.
128
-------
Table 1-16. SULFUR DISTRIBUTION
Case 1
6, 443
Sulfur Content, LB/HR
Crude Oil
Products:
Gasoline
Mid-distillates
Bunker "C"
Delayed Coke
Recovered Elemental Sulfur
Emitted as SO2 to Atmosphere
Total
Sulfur Distribution. % :
Products:
Gasoline
Mid-distillates
Bunker "C"
Delayed Coke
Recovered Elemental Sulfur
Emitted as SC>2 to Atmosphere 12.6
100.0
Case 2
6,443
6,44.'-!
205
1,046
1, 708
897
1, 776
811
6,443
Case 1
49
534
1,235
897
3, 372
356
6,443
C'ase 2
47
1,046
1, 708
897
1, 928
817
6,443
C'ase 3
3.2
16.2
26.5
13.9
27.6
12.6
0.8
8.3
19.2
13.9
52.3
5.5
0. 7
16. 2
26.5
13. 9
30.0
12. 7
100.0
100.0
Sulfur distribution as percent of sulfur in crude charges.
129
-------
APPENDIX A.
COSTS
1. All costs and capital are based on January, 1974 levels.
2. Capital related charges
Straight-line depreciation for 15 year life.
Interest at 10 percent per year. This is equivalent to
5 percent per year over the average payout period.
Maintenance: onsite, 4 percent; offsite, 2 percent.
Local taxes and insurance: 1.5 percent.
Payout on investment: 5 years after taxes.
3. U. S. income plus state corporation taxes at 50 percent of
gross profit.
4. Incremental utility costs
Fuel: $1. 00 per million Btu net heat value. This is
equivalent to $5.50 per barrel of 32° API crude
oil.
Electricity: $ Per KWH
Fuel cost 0. 010
Other charges 0. 006
0. 016
Steam: $1.40 per 1,000 pounds corresponding to the
fuel cost of $1.00 per million Btu.
Cooling water: *0. 02 per 1,000 gallons circulation.
Treated boiler feeclwa'er: $0. 05 per 1, 000 pounds.
5. Operating manpower costs
Average costs for stillman and operators at $6.00 per
hour plus 30 percent fringe benefits. Sixty percent
overhead on operating manpower is added to allow
for supervision, laboratory, technical service and
instrument services.
, 130
-------
5. Operating manpower costs (Contd.)
Manpower Cost
Per Shift Position $/HR % $/YR
Rate 6.00 52,600
Fringe Benefits 30 15,800
Overhead 60 41,000
Total 109,400
6. Product prices
Incremental product yields were priced at the same price
as crude oil ($5.50 per barrel).
7. Royalties
CJas oil hydrodesulfurization:
Paid-up royalty $10.00 per BPCD feed rate.
Naphtha hydrodesulfurization:
Royalty-free. Royalty costs would be included in
catalyst costs or nominal know-how fee.
8. Hydrogen make-up
Assumed to be available in the reformer make-gas for
for hydrodesulfurization units.
9. Gasoline octane
Incremental gasoline octane priced at 2.0 cents per 6 octane
difference between premium and regular gasolines at the
1972 lead level of 2. 24 grams per gallon. This price is
equivalent to 0.333 cents per gallon per research octane
nuniber.
131
46
-------
APPENDIX B.
OIL EQUIVALENT OF UTILITIES
1. Fuel
Net heat value at 6. 1 million Btu per barrel fuel oil
equivalent.
2. Electricity
Net heat to generate electricity is assumed to be 10, 000
Btu per kilowatt-hour. This requires 0.04 BPCD F.O. E.
per kilowatt-hour.
3. Steam
Net heat to generate steam is assumed to be 1, 370 Btu
per pound of steam. This requires 5.4 BPCD F.O.E. per
1, 000 pounds per hour of steam.
;>
132
-------
APPENDIX C.
SOURCES OF INFORMATION
American Petroleum Institute
"Annual Statistical Review, U. S. Petroleum
Industry Statistics, 1972 "
U. S. Bureau of Mines, Mineral Industry Surveys
"Motor Gasolines, Summer 1972"
"Motor Gasolines, Winter 1972-1973"
"Aviation Turbine Fuels, 1972"
"Diesel Fuels, 1973"
"Burner Fuel Oils, 1973"
U. S. Federal Register
Enviromental Protection Agency
Part 80. Regulations of Fuels and Fuel Additives
Vol. 38, No. 6 - Jan. 10, 1973
Vol. 38, No. 234 - Dec. 6, 1973
Ethyl Corporation
"Yearly Report of Gasoline Sales by States, 1972"
Gulf Oil Corporation
"32.3° API Gravity South Louisiana Crude Oil (Ostrica Mix)"
"Kuwait Crude OilHandbook"
i
133
-------
PART 2
PRODUCTION OF LOW-SULFUR GASOLINES
(PHASE 2)
CHAPTER 1
INTRODUCTION
This part of the report covers work which was performed under Con-
tract No. 68-02-1308 for the Environmental Protection Agency,
(EPA) Office of Research and Monitoring, Task No. 10, Phase
2.
Automobile manufacturers indicate that some automobiles
will have catalytic mufflers for pollution control starting
with the 1975 model year. To avoid poisoning of the catalyst,
no-lead gasoline is required. The catalytic mufflers reduce
emissions of carbon monoxide and hydrocarbons; however, the
catalysts convert sulfur in the gasoline into sulfuric acid
mist in the exhaust.
The purpose of this work is to determine the impact of
producing low-sulfur gasolines on the refineries in the
United States. To show the impact on U.S. refineries it
was decided to select a "typical" refinery as a basis such
that plant capacity, capacities of individual process units,
yields of products, and properties of products about matches
the average of the total U.S. refineries. Desulfurization
facilities were then added to this refinery, using two pro-
cess schemes, to produce low-sulfur gasolines.
The results presented herein supersede the results pre-
sented in the Phase I study.
134
-------
CHAPTER 2
SUMMARY
This study shows how a "typical" U.S. refinery can pro-
duce no-lead, lor-'-sulfur gasoline and by installing new
hydrodesulfurization facilities produce the low sulfur gaso-
lines to include the no-lead, premium and regular gasolines.
Results of this study indicate that no-lead, low-sulfur
gasoline would have to be blended from normal butane, alky-
late, and reformate in the existing "typical" United States
refineries. Beyond 1975, the predicted demand of no-lead
(low-sulfur) and premium gasolines could not be met with
the EPA limits on lead anti-knocks in the total gasoline
pools.
Total gasolines could be made low sulfur by hydrodesul-
furization of the gas oil feedstock to catalytic cracking
and by hydrodesulfurization of the light virgin and light
coker (or thermal) gasolines. Economics for this scheme
(Case 2) show that the costs for producing gasoline would
be increased depending upon refinery size approximately as
follows:
Refinery Crude Desulfurization
Capacity, BPCD Costs, Cents Per Gallon
16,000 1.59
44,000 1.01
100,000 0.67
An alternate case considers hydrodesulfurization of the
catalytically cracked gasoline rather than the feedstock
to the catalytic cracker. Economics indicate that this
sche - (Case 3) to produce low-sulfur gasoline would add
a! ,ut 0.82 cents per gallon to the cost of gasoline pro-
-. 135
-------
duction for a 100,000 BPCD refinery. This cost includes
a penalty of 0.3 cents per gallon of gasoline debited to
the lower octane resulting from partial hydrogenation of
olefins in the FCC gasoline.
If new facilities were installed to desulfurize all the
U.S. gasolines by desulfurizing light virgin and themal
gasolines and desulfurizing the cat cracker feedstock, it
would require an investment of about 2.0 billion dollars
by U.S. refiners based on January, 1974 costs.
Based on the gasoline yields and properties in Case 2
for low-sulfur gasolines, no-lead, premium and regular
gasolines could be blended in the predicted sales volumes
and the total gasoline pool could meet the EPA regulations
on lead phase-down until 1979. Octane up-grading would be
required in 1979 to meet the limit of 0.5 grams of lead
per gallon.
"A" Typical U.S. Refinery is shown as Case 1 and con-
forms to the following criteria:
Median capacity of crude charges to U.S. refineries
Capacities of process units within the refinery
about matches the average percent of crude input
as the total U.S. refineries.
The crude charge produces about the average per-
cent yields and properties of products as the
total U.S. refineries.
136
-------
CHAPTER 3
EPA REGULATIONS ON GASOLINES
UNLEADED GASOLINE
Regulations by the Environmental Protection Ao~~"
(EPA) to limit the emissions of carbon monoxide and hydro-
carbons require most future automobiles to have catalyt;;r
mufflers.
General Motors announced plans to equip all its 1975
models with converters, compared to about 60 percent for
Ford. Thus about 80 percent of the 1975 automobiles will
have catalytic converters.
Unleaded gasoline to be used in automobiles equipped
with catalytic converters is to be generally available
in the United States at major service stations.
The EPA has issued regulations (January 10, 1973)
on unleaded gasoline (minimum 91 research octane) to
be supplied starting in July, 1974.
PHASE-DOWN OF LEAD IN GASOLINE
The EPA has ordered a phase reduction of lead anti-
knock additives in gasoline (Federal Register, Dec. 6,
1973). These regulations restrict the average lead
content in all grades of gasoline (including unleaded
gasoline) produced by any refinery as follows:
Lead Content
January 1 Grams per Gallon
1975 1.7
1976 1.4
1977 1.0
1978 0.8
1979 0.5
137
-------
CHAPTER 4
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE IN PRESENT
U.S. REFINERIES
DEFINITION OF "A" TYPICAL U.S. REFINERY
The purpose of this study is to determine the impact
of producing low-sulfur gasolines by the refineries in
the United States.
"A" Typical U.S. Refiner can be used to show the pro-
duction of no-lead, low-sulfur in the present U.S. re-
fineries and then develop the added costs to produce
gasolines by installing new hydrodesulfurization facil-
ities.
For this purpose, "A" Typical U.S. Refinery and the
crude charge should conform to the following criteria:
Median capacity of crude charges to U.S. refineries
Capacities of process units within the refinery
matches about the average percentage of crude in-
put as the total U.S. refineries
The crude charge produces about the average per-
cent yields and properties of products as the
total U.S. refineries
CASE 1: "A" TYPICAL U.S. REFINERY
The refinery process units selected for Case 1 were
as follows:
Crude and Vacuum Distillation
Catalytic Reformer with Hydrogen Pretreat Section
Fluid Catalytic Cracker with Vapor Recovery
Delayed Coker
138
-------
Alkylation
Sulfur Recovery
For calculations, the refinery feedstock was con-
sidered to be a 38.4° API mixture of Texas-Louisiana
crude oils containing 0.5 weight percent sulfur.
Figure 2-1 is a block flow diagram showing the yields
and properties of intermediate and final product streams.
Case 1 is based on 100,000 barrels per calender day
(BPCD) of crude oil. Thus, the volume percent yields
based on crude oil may be obtained by dividing the BPCD
flows by 1,000. The vapor pressures and octanes of the
gasoline component streams are shown in Figure 2-1. The
sulfur in the crude oil is shown distributed in the
i
product streams, recovered sulfur, and emissions to the
atmosphere.
To simplify the work, the following conditions were
assumed:
Production of alkyJLate was set at 5.8 volume per-
cent on crude input by taking propylene to LPG.
Reformer would produce reformate with 95 research
octane clear.
Catalytic cracker would operate at 75% conversion
with yields corresponding to riser cracking using
zeolite catalyst.
Unfinished asphalt would be produced from vacuum
tar.
Production of lubricants and waxes were not con-
sidered as these account for only 1.8 volume per-
cent on crude input.
1 139,
-------
Special naphthas and the benzene-toluene-xylenes
aromatics were considered to be part of re formate
and would be accounted in the total gasolines.
Comparisons o,f the results in Case 1 with the aver-
ages for the U.S. refineries from statistics are as
follows:
Table 2-1 - Comparison of Process Units in Case 1
with the U.S. Average
Table 2-2 - Comparison of Products and Yields -
1972 U.S. Production vs. Typical Refineries.
Figure 2-2 - Octane of Total Gasoline Pool - Typical
Refineries
The median quantity of crude refined in the United
States in 1973 was processed in refineries with a median
capacity of about 100,000 barrels per stream day (BPSD)
of crude oil. Capacities of refineries are usually
expressed in barrels per stream or operating day
(BPSD) whereas accounting of the annual production is
on a barrels per calendar day (BPCD) which considers
the down time.
These comparisons show that refinery and crude oil
in Case 1 may be considered to be "A" Typical U.S. Refin-
ery by conforming to the criteria stated previously in
this chapter.
Partner imports of foreign crudes with lower °API
gravities, higher sulfur content, and higher metals
content than domestic crudes will result in a somewhat
Different distribution of products with higher sulfur
140
-------
NOTES:
1. -A" TYPICAL U S. RUlMLS
Product yields are about avwrag« percentage
* total U.S. production in 1971 and 1972.
Properties ot oroducti are almoat typical
L.S. production in 1972 and 1973.
illion Btu per barrel fy
3. Net heat ,,I!UF at fe.l
equ.valent IF.O.L.).
4. GASOLINE OCTAHL5
RONC RESEARCH OCfAJJi JLL,>H,
RON + 3cc RESLARCH OCTANL PLuS JCC T
MONC HOTOR OCTANL CLEAR.
MON + 3cc MOT'JP OJVA.^l. Pl.l S Jet? T C I
5. RVP HEID VAPOR I'HLSSLl*!
"Si vr j i
Sulfur
(I/H).
100 000 BPCD
3b 4 'API
1,213.3701/H
1,924 BPCD
15,720 I/H
Lxyht
Vac Ta
11,512
14.5 "
162,640
Sulfur
(1,000
PCD
.9 Mtl
,0961/H
Sulfur 0 010 wtl 91/li
RVP >.6 RONC 69 1 RON+3CC 87 8
MONC 67 a MON+3CC 85.1
Fi 'X
19,«43 BPCD 53.7°API 222,030 I/H
bulfur 0.12 Wt% 194 |/H
12,317 BPCD 3fc"API 151,6201/H
Sulfur 0.24 Wti 3591'H
« Oil (600-1 ,000'F)
31,757 BPCD
28 : =API
409,930 I/H
Sulfur 0.55 Wt , -,
2,272 I/H ^
Light ua»olin« (Cs-200'r)
514 flPCD 73*API
5,1801/H
Sulfur 0.33 Htl 171/H
P"P 7.5 ROWC 82 6
RON+3cc 90.3
MONO 70.1 MOM+Jec 77.2
5,192 BPCO
71 3501/H
SJlfur 1,3961/H
l,- UOO-370-P)
.'0, '94 hl'CD
Najjht hiu (200-170^ )
83] BPCD WAI' I
9,5601/4'
faulfui 0.5 Ht» 431/
28 3'API
444,920 I/H
Sulfur O.S9 wtt
2,639 I/H
f
1
1
1
Gas Oil (370-EP)
2,736 BPCD 29.7'API
34,9901/h
C4 ». Llg.ite
rluu Catalytic
Cracking unit
^ r °"
2t> 610 I/H
Su fur 1.68 tvt*
i . ,'.t e
3U4. ^0 l/ri
*"\ 1,01 1 'H
Li jht ( YI r oil
(4JO-650* )
( " -e »rc
JJ 2' API
-------
4JJ
BPCU
DPCO
' 1,587
1,804
2,223 BPCn 18,950
Cg+ AlkyUte
5,800 BPCD 72 5°API 18,6101/H
RVP 3 3 RONC 94 6 RON+;cc 105 6
MONC 93.5 MON+3cc 107 6
Total Gasoline Po il
r 58, 306 BPCD 62 2 'API ^^^
620,560 I/H
Su fur 0 031 Wt% 191 't!
RV 11.0
Qc an* Research ^°*--?r
C i>ac 89 7 S; 3
c T.E.L. 98 3 5» -4
*2.24
97 .>
Xerasinc
d,500 BPCD 42^API
100,980 I/H
Sulfur 0 12 wt* 119
,*.-'
Cj»
C3
^
BPCJ).
1 ,753
1,756
3 , 5'o"9
*0 I/H
Vipor Recovery
Sulfur 1,992 I/H
8,217 BPCD
4,100 BP
k'7
B&D
fc>v
3,300 BP
, Hj Consumed
L 0. 39 MM SCF/D
CD>80I/H
r~
CD
^10 I/H Sulfur 383 I/H
67,610 I/H
nC4 2^103
C<* 2,866
FCC Gaao
3,219 BPCD
1 7S7 /« 1 (95*'
ir.e (C5-430-F)
7,400 BPCD
31.1 "API
n 93,840 I/H
Sulfur O.C72 Wt t
1 67 I/H
n
r
Reco
1ULJ
s
/
CUuB Plant
Sulfur B8I/H
Net Heat valu
413 3 MM Btu/
,f 1,626 BPCD F.
2,900 2,900 BPCD
f BPCD '
(Diese
2,400 8,200
BPCD 36.5"
100,5
5317
K
O.E.
1,669 I/H
20 Ton/ Day
14? |
BPCD° No 2 Futnace
16,023 BPCD 32 8
201 ,030 I/H
20,491 BPCD 58.9 'API 221,910 I/H Sulfur 1651/H
RVP 7 2 ROUC 91 5 RON*3cc 97 8
MONC 80 6 MON+3cc 86 8
bur.kt-r "C
5,32-) BPCI
10 9°AP
77,120
Sulfur
.82 Mtt
,403 I/H
y 170 Fuiol ''f
Unf inishe(i)
Bulfur I 9 i
U.S. refinery (Case 1),
. 142
-------
Table 2-1. COMPARISON OF PROCESS UNITS IN CASE 1
WITH THE U.S. AVERAGE
Vol. % of Crude Capacity
U.S. Refineries
Process Units in 1973 Case 1
Crude Distillation 100.0 100.0
Vacuum Distillation 36.8 37.8*
Cokers (Delayed and Fluid) 6.4 5.2
Catalytic Cracking 32.3 34.5
Naphtha Hydrodesulfurization 20.0 20.8
Catalytic Reformer 23.4 20.8
Mid-Distillate Hydrodesulfurization 7.9 7.4
Alkylation 5.8 5.8
* At 670°F TBP cut point in crude oil.
143
-------
Table 2-2. COMPARISON OF PRODUCTS AND YIELDS,
1972 U.S. PRODUCTION VERSUS TYPICAL REFINERIES
Total Gasolines
1972 U.S.
Production Case 1 Case 2 Case 3
Yield, vol%
°API
Sulfur, wt%
Research Clear
Research + 3cc TEL
Research + 2.24 g. lead/gal
Motor Clear
Motor + 3cc TEL
Motor + 2.24 g. lead/gal
Reid Vapor Pressure
Kerosine and Kerosine-Type Jet
Yield, vol%
°API
Sulfur, wt%
Diesel Fuel
Yield, vol%
°API
Sulfur, wt%
No. 2 Furnace Oil
Yield, vol%
°API
Sulfur, wt%
No. 6 Fuel Oil
Yield, vol%
"API
Sulfur, wt%
Viscosity, Furol at 122°F
Asphalt, vol% (5.5 bbl=l short.
C , , vol% (5 bbl=l short ton)
58.2
61.7
0.031
97.5
90.0
10.7
Fuel
8.5
42.3
0.066
8.2
36.5
0.21
14.4
35.1
0.22
6.8
11.0
1.6
170
ton) 3. 8
1.5
58.3
62.0
0.031
89 .7
98.3
97.2
82.3
91.4
90.3
11.0
8.5
42.0
0.12
8.2
36.5
0.15
16.0
32.8
0.28
5.3
10.9
1.8
170
3.1
1.0
58.7
62.1
0.006
89.3
98.9
97.8
82.2
92.2
91.1
11.0
8.5
42.0
0.12
8.2
36.5
0.13
15.7
33.1
0 .14
5.5
12.6
1.3
170
3.1
1.0
58.5
62.6
0.006
88.0
98.5
81.7
92.3
11.0
8.5
42.0
0.12
8.2
36.5
0.15
16.0
32.8
0 .28
5.3
10.9
1.8
170
3.1
1.0
144 i
-------
Table 2-2.(continued) COMPARISON OF PRODUCTS AND YIELDS,
1972 U.S. PRODUCTION VS. TYPICAL REFINERIES
1972 U.S.
Production Case 1 Case 2 Case 3
Liquefied Petroleum Gas (LPG) yvol% 1.9 3.4 3.7 3.4
Still Gas to Fuel, vol% 3.8 4.1 3.9 3.9
Other Products, vol% None None None
Lubricants 1.6
Wax (1 bbl-280 Ib.) 0.2
Road Oil 0.2
Miscellaneous 0.3
Notes:
1. Yields are volume percent on crude input.
2. Where 1972 yields were not available, they were
estimated from 1971 products. Petrochemical
feedstocks (aromatics) and special naphthas added
into total gasoline production.
145
-------
LEAD AI.KYI ANTIKNOCK SUSCEPTIBILII Y CHART
115
110 r~
r
o
Ob 10 15 2 0 2 5 3.0 4.0 5.0 6.0
ANTIKNOCK CONTENT, CRAMS METALLIC LEAD PER GALLON
dlent tc ' 0, .' i ; C d.^J 4 0 ml III. '(jo'U'i
Figure 2-2. Octanes of total gasoline pool.
2 0
I 0
100
ao
ct
Ld
00
/o
o
z
o:
o
u_
QL
LJ
Ci.
146
-------
content than shown in Case 1.
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE IN PRE-
SENT FACILITIES
The time to plan, finance and construct refining
facilities to upgrade gasoline blending components re-
quires two to three years from the date of a firm de-
cision to proceed. During the period until the additional
gasoline-upgrade facilities are onstream, the no-lead,
low-sulfur gasolines will have to be blended from low-
sulfur components which can be produced in the present
refining facilities.
Sulfur contents of various gasoline blending com-
ponents can be shown by the analyses of various samples
in Tables 2-3 and 2-4. The sulfur content is variable
and depends upon the crude source for catalytically
cracked gasoline, light straight-run gasoline, natural
gasoline and coker or thermal gasoline.
Reformate and alkylate can be considered sulfur-free.
The bi metallic reformer catalysts require that the
feed naphtha be desulfurized to less than 1.0 ppm sulfur.
The feedstocks to alkyiation are desulfurized or essentially
sulfur-free. In alkyiation, the hydrofluoric acid cata-
lyst or sulfuric acid catalyst quantitatively removes
any residual sulfur.
Production of sulfur-free gasolines generally will
require the desulfurization of thermally cracked gasoline,
catalytically cracked gasoline, and light straight-run
gasoline. However, until new desulfurization facilities
are installed, the requirements for no-lead, low-sulfur
147
-------
Table 2-3. SULFUR IN GASOLINE BLENDING COMPONENTS
Gasoline Blending Components* Sulfur, WT%
Catalytically Cracked Gasoline 0.055
0 .036
0 .034
0.07
0.327
0.039
0 .175
Alky late 0.001
0.008
0 .002
0.003
Catalytic Re formate 0.001
0.007
0 .013
0.006
0 .002
Coker Gasoline 0.089
0.19
1.43
0.59
Natural Gasoline 0.008
0 .010
0.027
*Analyses of miscellaneous samples
148
-------
Table 2-4. SULFUR IN LIGHT VIRGIN GASOLINES*
Sulfur, WT%
Crude Source In Light Gasoline*
East Texas 0.01
West Texas Intermediate Sweet 0.038
Ellenberger (Texas) 0.01
West Texas (0.31 wt% sulfur in crude) 0.01
West Texas Sour 0.15
Oklahoma City 0.011
Tinsley (Mississippi) 0.006
Corning (Ohio) 0.006
South Louisiana 0.006
Kuwait 0.006
Light Arabian (Saudi Arabia) 0.02
Light Iranian (Iran) 0.01
- 200°F TBP
149
-------
gasolines will have to be blended from low-sulfur blend
stocks, such as n-butane, reformate and alkylate.
Starting in July, 1974 the no-lead gasoline will
have to be available for the 1975 automobiles equipped
with catalytic mufflers. Gasoline blending components
presently available will be used to blend the no-lead,
premium, and regular gasolines. In future years as
more automobiles in service have catalytic mufflers
and the pre-1971 automobiles are increasingly junked,
more no-lead gasoline and less premium gasoline will be
required to satisfy automobile needs. The 1971 and
later automobiles without catalytic mufflers can use
regular gasoline.
Figure 2-3 shows a projected percent of sales of
premium and no-lead gasolines.
The potential production of no-lead, low-sulfur
gasoline together with premium and regular gasolines
was calculated attempting to meet the EPA regulations
on lead phase-down using the blending components pro-
duced in Case 1. These results (Table 2-5) indicate that
the projected percent of gasoline sales can be produced
through 1975. In 1976 and later years the EPA limit
on lead content would be exceeded. In 1977 and later
years the production of no-lead, low-sulfur and premium
gasolines would be less than the projected percent of
sales.
150
-------
C/5
W
W
I H
o
d
w
w
(X
100 - -
90 . .
80 - -
70 --
4J --
30 . :
20 --
10 . .
PREMIUM GASOLINE
- ' SALES
\
\
PREMIUM
GASOLINE
RECOMMENDED
FOR CARS
ON ROAD
/
/NC-LEAD GASOLINE
/
/
\
\
/
\
\
19S5
1975
1980
1985
1990
YEAR
Figure 2-3. Projected percent of sales of premium and no-lead gasolines.
151
-------
Table 275. POTENTIAL GASOLINE PRODUCTION IN CASE it1)
WITH LEAD PHASE-DOWN
Year
Lead Content, g./gal
Allowed by EPA
Total Gasoline Pool
Premium Gasoline
Regular Gasoline
Potential Gasoline, vol%
No-Lead, Low Sulfur
Premium (100 RON)
Regular (94 RON)
No-Lead Gasoline, vol%
N-Butane
Alkylate
Reformate
Premium Gasoline, vol%
N-Butane
Alkylate
Reformate
FCC Gasoline
Regular Gasoline, vol%
N-Butane
Light Virgin Gasoline
Light Coker Gasoline
FCC Gasoline
Alkylate
Reformate
Gasoline Octanes
No-Lead, Research
Motor
Premium, Research
Motor
Regular, Research
Motor
C~!rjnent - See Note
1972 1975 1976 1977 1978 1979
4.2V*
37
63
99.7
92.2
94.0
86.4
1 1.7
1.6
1.8
2.0
18
23
59
15
22
63
15
22
63
8
25
2
59
1
5
94.7
87.9
100.2
94.8
94.2
86.3
1.4
1.55
2.6
2.1
30
16
54
15
22
63
13
15
44
28
8
27
2
57
1
5
94.7
87.9
100.2
93.3
94.2
87.0
1.0
1.5
3.0
2.4
40
9
51
15
22
63
12
12
35
41
7
29
2
61
-
1
94.7
87.9
100.2
92.6
94.2
86.3
0.8
1.3
-
2.3
45
None
55
15
22
63
None
7
27
2
64
-
94.7
87.9
94.2
86.2
0.5
1.3
-
2.3
45
None
55
15
22
63
None
7
27
2
64
-
94.7
87.9
94.2
86.2
3.
4.
5.
6.
5
152
-------
Notes on Table 2-5:
(1) Potential gasoline blends are based on the gasoline
yields and properties from "A" Typical U.S. Refinery
(Case 1). The no-lead, low-sulfur gasoline would be
blended from normal butane, alkylate, and reformate.
(2) Legal limit was 4.2 grams lead content per gallon prior
to EPA regulations.
(3) Predicated sales demand of premium gasoline and no-lead,
low-sulfur gasoline precludes meeting the EPA limit on
lead content in 1976.
(4) Predicated sales demand of no-lead, low-sulfur gasoline
reduces the production of premium gasoline below pre-
dicted sales demand. Lead content in total gasoline
pool exceeds EPA regulation in 1977.
(5) In 1978 and 1979, the octanes of the gasoline components
limits the production of no-lead, low-sulfur gasoline
below predicted sales demand. The production of no-lead,
low-sulfur gasoline precludes the production of premium
gasoline. The lead content in the total gasoline pool
exceeds the EPA regulation in 1978 and 1979.
153
-------
CHAPTER 5
DESULFURIZATION OF GASOLINE
CASE 2: "A" REFINERY WITH HYDRODESULFURIZATION OF
CATALYTIC CRACKER FEED AND LIGHT GASOLINES
In order to calculate the costs of producing
low-sulfur gasolines, hydrodesulfurization of the
gas oil feedstock to catalytic cracking and hydro-
desulfurization of the light virgin and light coker
gasolines were considered.
In Case 1, the sulfur content in the light
virgin gasoline is 0.01 wt.%. However, hydrode-
sulfurization of light virgin gasoline should be
included for the "typical" refinery for cost pur-
poses because some of these gasolines, as shown in
Table IV, have high sulfur contents.
In Case 2, the refinery process units would be
same as in Case 1 of "A" Typical U.S. Refinery with
the following additions:
Gas Oil Hydrodesulfurization
Light Gasoline Hydrodesulfurization
New Capacity for Amine Treating and Sulfur
Recovery
Figure 2-4.is a block flow diagram of Case 2 show-
ing the yields and properties of the intermediate
and final product streams. The yields and product
properties are listed in Table 2-2 together with the
average U.S. production.
154
-------
Liqllt -,*=. U-na
ll,S 33 l/ll
Sulfur 24 I/H
1-- I U-.HT GASOLINE L_
I ItiDHnlil.Srl.FUHliAl ION 1
514 Bt'Lu M »AKI
5,180 -,'H
5-ulfar 0 ), wt* 17 I,H
HVI1 / HONL, U2 b
RON * 1. <- 1.1) (
MflNC TO 1 MHN , Vf 7;
Cf;
."'..':.1.'-L I
Figure 2-4. "A" typical U.S. refinery with hydrodesulfuriza-
155
-------
",'»! -I MM atu/l
i , i ' / BHi_D 1 ,1.
Debut ivcrhead
sulfur 47 0/1!
vaseline fc I.
f J 1 , luO r/ll
i.lijht (. ye If Oil
( 4 3 0 - u > J " D
2H 6 " AP L
89, iiJO I/H
Sulfur 0 1 7 wt%
1^0 I/H
.C .
i i.ittr
f
9
BPL.D
2J./10 '/H
I
334 ,210 I/H
Sulfur 3,01
C
17"1 BI'JL) 74 .* * PI J j , i", J i
/P ; 6 B Purchaat-d
3,599 BPCU
30,693 I/H
' . + RoCormute
' >Ni_ 3&.5 MON * 3t,c 'Jl. 1
BPCD
LPG^ C3- 1,845
Purchased 1,1,; J -CD 27,780 I/H 3«658
Isob'jtnne b.iej /H N-Butane
^^^ | J 2,593 BPCD 22,3SD I/H
^J U'"L 1 C * Alkylate
5,800 BPCD 71.8 "API 58,810 I/H
1-1,730 1 Bv-Product Oil MONC 94.6 KON + 3cc 137,7
C" 1,300 ^^^
4 4 BPCD 19 "APT
^ 30 I/H
2,yOO HPCD
H, Consumed
^0.17 MM SCF/D 2,487
T Sulfur- 0.33 v,t% BPCD
"" * ' 29 I/H
^ 2,859 BPCD
Stack Gas
r HHi^^ Sulfur 149 t/ll
AM1NE TRF.ATIJO ^
iu^i im »_iii t buL,UH HLU,J7tHy i ^^ .11 u IUL!
402 0 MM Btu/H
9 (/ll 1,581 BPCD F.O.t.
2,834 I/H
34 Tons/Day
23,183 BPJD 60.1 "API 217,233 */H
^ * Gas a line
ToCai Gaaol i te
58 ,670 BPCD 62 4 *Af 1 "
623,700 * 'H
Sul'ur 0 006 wt- '8 * A
RVP 11.0
CLEAR 89 '
+ 2 24 g/gal 'j .,i
8 , 500 HPCD 42 ° i 1
100,980 ./it
Sul fur ) .U wti
2,930 BP.U
2'400 UieaM Fa
> J6 -, °Ar
* luO ,623 u
BPCU
WJ 2 L P.. ,. 1 ^^
,6o3 »P-
Ifux 3 i
667 BP^-D 30 "API 7,533 I'll
RVP 3 RON 63 RON * J,c 32
MON 62 MON + 3cc 81
No 6 Iuul Oil
5, ^29 BPCU
12 6 "API
79.14LJ I/II
Sulfur 1.25 wt»
,100 BPCD
43,80) I/I!
tion of cal. cracker feed and light gasolines.
156 i
-------
For desulfurization of the gas oil, the calcu-
lations are based on 80 percent sulfur removal with
a hydrogen consumption of 42 standard cubic feet
per pound sulfur removed (3.5 mols hydrogen consumed
per mol sulfur removed). Above 85 percent sulfur
removal, the hydrogen consumption increases due to
saturation of polyaromatics and hydrocracking.
In Case 2, the hydrogen produced in the reformer
would be more than adequate to supply the refinery
needs. The sulfur content would be 0.008 weight
percent in the total gasolines.
Economics for producing low-sulfur gasoline
in Case 2 are summarized in Table 2-6 and estimated
investments for the desulfurization facilities are
shown in Table 2-7. The economic basis is presented
in the Appendix. The investment for the desulfuri-
zation facilities is assumed to pay out in five
years (20 percent rate of return.)
The total added costs to produce low-sulfur
gasolines (above Case 1) depends upon refinery size
as follows:
Added Costs to
Refinery Capacity, Produce Low-Sulfur
BPCD Gasoline, Cents Per Gallon
16,000
44,000
100,000
1.59
1.01
0.67
Table 2-8 shows a comparison of yields in
Case 1 and Case 2. Table 2-9 shows the estimated
157
-------
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159
-------
Table 2-8. COMPARISON OF YIELDS - CASE 1 AND CASE 2
BPCD
Charges
Crude Oil
Isobutane
N-Butane
Total Charges
Case 1
100,000
863
3,964
104,827
Case 2
100,000
1,103
3,599
104,702
Difference
(Case 2-Case 1)
240
-365
-125
Products
Fuel Gas, F.O.E.
LPG (Propane-Propylene)
Gasolines
Kerosine
Diesel Fuel
No. 2 Furnace Oil
No. 6 Fuel Oil
Delayed Coke (5 Bbl = 1 Ton)
Asphalt
Sulfur
4,060
3,391
58,306
8,500
8,200
16,023
5,324
1,008
3,100
3,908
3,698
58,670
8,500
8,200
15,663
5,529
1,008
3,100
-152
307
364
-360
205
(20 tons/day) (34 tons/day) (14 tons/da
Total Products (Excluding Sulfur) 107,912
108,276
364
Apparent Gain
(Products Minus Charges)
3,085
3,574
489
160
-------
Table 2-9. UTILITIES AND CATALYST REPLACEMENT - CASE 2*
Process Unit
Capacity
Light Gasoline FCC Feed
Hydro- Hydro- Sulfur
Desulfurization Desulfurization Recovery Total
9,700 BPSD 36,000 BPSD 15 TPD
Consumption of Utilities:
Electricity, KW
Fuel, MM Btu/Hr
Cooling Water, GPM
Boiler Feedwater, Ib/hr
Steam Consumed, Ib/hr
Steam Generated, Ib/hr
Wash Water, GPM
240
24
400
10
1,800
126
1,260
1,100
1,100
40
30
1
3,940
4,000
3,800
2,070
151
5,600
5,100
4,900
50
Cost of Utilities, 5/CD
5,720
Catalyst Replacement, $/CD
40
620
660
Fuel Equivalent of
Utilities, BPCD (F.O.E.)
650
*Utilities and catalyst replacement are incremental above those
in Case 1.
161
-------
utilities and catalyst replacement cost in Case 2.
The apparent liquid gain in products over
charges for Case 2 is 489 BPCD above Case 1. How-
ever, the utilities for the desulfurization facilities
would require 650 BPCD of fuel equivalent. Thus,
Case 2 would show a net loss of 161 BPCD in compari-
son to Case 1.
Investment to Produce Low-sulfur Gasolines in the
United States - Case 2
Based on the process scheme shown in Case 2,
a crude oil throughput at 15 million barrels per
day in 1978, and investment for the new desulfuri-
zation facilities at January, 1974 costs, the total
investment would add about 2.03 billion dollars to
U.S. refinery facilities. This investment would be
portioned depending upon refinery size as follows:
Range of Refinery % of Investment,
Crude Capacity, BPSD Crude Capacity Million Dollars
0 to 25,000
25,000 to 75,000
75,000 and larger
7.5
20.4
72.1
100.0
310
520
1,200
2,030
This investment applies to the typical U.S.
refineries and could be higher depending upon
future imports of high sulfur crude oils. Increased
imports of high sulfur crude oils would require de-
sulfurization at increased severities for streams
presently being desulfurized and installation of de-
sulfurization facilities for other refinery streams.
162
-------
In this event hydrogen for the refinery needs may
not be sufficiently available from the reformer and
new hydrogen production facilities may be required.
Potential Gasoline Production in Case 2 with Lead
Phase-Down
The potential production of no-lead, premium,
and regular gasolines was calculated attempting to
meet the EPA regulations on lead phase-down using
the blending components produced in Case 2. All
the gasolines would be low-suifur. These results
(Table 2-10) indicate that the projected percent of
gasoline sales and EPA regulations on lead phase-
down can be met through 1978. In 1979, octane up-
grading would be required to meet the EPA regulations
on lead content.
163
-------
TabJi- 2-10. POTENTIAL GASOLINE PRODUCTION IN CASE 2
WITH LEAD PHASE-DOWN
(I)
Year
1976
1977
1978
1979
(2)
Lead Content, a/gal
Allowed by EPA 1.
V o t a 1 G a .-; o 1 1 n e P oo 1 1 .
P r e m i arc G a s o 1 i ne i .
.-"eguiau Garo^ in-. 1 ,
Potential Gasoline, volfe
-_,.^..;^_.._^ p^~,- ^fff* 3f,
Jr -:TU i..'!1 ' j O'"1 '(ON) .1 8
\v-jLu;ir '94 -xOiJ) W.
N-'i- LeiKJ M-M.TOJ Lr.e, vo.1%
N-B'atan'5. 11
A ' i. '/ i d ':-. 1 1
(->( » r n -rrp 4 -' 33
FCC Get so l.i. tie 40
i'.iqht Gr. so lino 3
L t.' .n ..,'.. Ga..oli>v_ , vol%
N- Butane 12
A Ik via to 36
R.ifOT-Tiat..:! 19
;;TC Gasoj i i'. : 3 <
:.-. --.-r,-jl i'^
. > -'7 'i 1 ar <".. !!-< \o ': t
M-Hiui-a,v- 10
- I xy la r^
;?,» <" r iT-TTI ^ '--> 29
M?0 GJ/-O ' ip.^ 32
,.. ;ht G.J-- ..:,. :!'y
I r>1? Ga s o I i n e ?
, n S.">1 mt? O; ''.(jlij..r-
\'o - .Ix-i sc3 , i1-"- se a r / h * '
M«'»tOT «--i
,J -"\-»m \ un ? RM -
content of total gasoline pool would exceed
164
-------
"A" REFINERY WITH HYDRODESULFURIZATION OF CATALYI
ICALLY CRACKED AND LIGHT GASOLINES (CASE 3)
Case 3 considers the cost to produce low-sulfur
gasolines by hydrodesulfurization of the catalyti-
cally cracked gasoline rather than the feedstock to
the catalytic cracker.
The refinery process units in Case 3 would be
the same as in Case 1 with the following additions:
FCC Gasoline Hydrodesulfurization
Light Gasoline Hydrodesulfurization
Figure 2-5 is a block flow diagram of Case 3 show-
ing the yields and properties of the intermediate
and final product streams. The yields and product.
properties are compared with those for the U.S.
average and Cases 1 and 2 in Table 2-2.
Sulfur removal from tne FCC gasoline of about
80 percent was selected since this yields about the
same sulfur content in the total gasolines as in
Case 2. At this desulfurization severity, 45 per-
cent of the FCC gasoline would be hydrogenated,
which would result in decreased research octane.
The octane debit and other results are summarized
as follows:
Table 2-11 - Octane Debit
Table 2-12 - Economics ol Producing Low-Sulfur
Gasoline
,165
-------
Table 2-13 - Investment for Desulfurization
Facilities
Table 2-14 - Comparison of Yields, Case 1 versus
and Case 3
Table 2-15 - Utilities and Catalyst Replacement
Requirements
The apparent gain (difference between products
and charges, Table 2-14 for Case 3 would be 6 BPCD
above the apparent gain for Case 1. However, the
utilities for the desulfurization facilities
would require 501 BPCD of equivalent fuel oil
(Table XV). Thus Case 3 would result in a net loss
of 495 BPCD compared to Case 1.
Economics as shown in Table 2-12 indicate that .
»
the total added costs (above Case 1) would be 0.82
cents per gallon to produce low sulfur gasolines.
These costs include the penalty of 0.30 cents per
gallon of gasoline debited to the lower octanes
which result from partial hydrogenation of olefins
in the FCC gasoline.
166
-------
CRUDE b VACUUM UNIT
10J.OOO UPCD
38.4 "API
1,211,370 I/H
Sulfur 0 5 wt»
6,014 I/H
MIX OF CRUDti. FROil
TE.XAS ANU LOUISIANA
(( -.'JOT)
y,(74 BPCU
74.3 'API
/ 91 ,64 J »/H
\
11 , 30 I/H
fa($Lfur ^4 I/H
1,924 HPCU
15,720 I/H
vac Tar (1,000 - *I)
11,512 ilPL^
14,5 "API
162,640 l/il
Sulfur 1.9 wt*
3,0*6 »/H
I I.TOUT r.ASOL INI. I
HYDI«H>I SOi.t UH17ATION |
Gas to Fu«l
22,560 I/H
Net Heat Val-je
2,241 ill- (, i o
Sulfur b', K/II
8,6^0 im U 75 "Al'i 86,463 I/H
Sulfur 0.010 wt* 9 I/H
RVP 7 & IJO.JC f>9 J KON « 3CC 87 .8
.40 4,970 I/H I
Sulfu 0.12 wtU 194 I/H I
Uiese (jOO-r,TO°M '
12, 31 uPCU 3f, "API 1 SI ,620 »/H x
i,ul£u U 24 wt* 359 I/H
(,as> Oi 1 !fcOO-l, .j(JO'F)
31 7'i7 HPCU
23.2 "API
409,930 I/H
Sulfur ^ 15 wt*
Liqht Gasoline d-, 2UO°F)
'j!4 BPLU 73°AI*I
5,180 l/ll
Silfur 'J 33 wt% 17 »/li
RVP 7 j RONL 32 6
RON * 3cc '>0 )
MONC 7>J 1 ^ON + 3cc 77 2
5 , l^i BHi_U
7 3 , 1 j 0 * / H
Sulfur 1 , J'Jj I/H
34,493 BPCD
2S i "API
444,920 »/M
Sulfur U S9 wtt
Gas Oi1 I 370-tP)
2,73b liPCD 29.7 V-l'I
34,990 »/!'
-Sulfur 1.00 wtt
3.i-7 l/ll
6,SI') Hl'(.)
86 , 3 5i) I/H
Sulfur fi'jl I/H
bulfur 481) I/H
C.OKL
I. 16,800 I/It
^202 Short nms/Uaj
Sulfur 2.8fi wt*
484 I/H
I
Decant (.1 1 K.50 * " [ )
1 ,720 »!'( 1) / 2 VIM
2fi ,(.10 »/H
Sulfur 1 RB wt*
490 I/H
3,220 BPCD
45,490 l/ll
Sulfur 866 I/H
j, J2
, 10. J
77,J
Af.,-1 o I t ( , ni i nishci
J, ioj ui'cn
14.: 'API
43,800 t-'ll
Sulfur 1 'i wt* 8 J4
Figure 2-5. A typical U.S. refinery with hydrodesulfurizati<
167
-------
of cat cracked and light gasolines.
,168
-------
Table 2-11. OCTANE DEBIT FOR CASE 3*
Case 1
Research
Motor
Research + Motor
Octane at 0.5 g/gal
93.1
85.9
89.5
Case 3
Research
Motor
Research + Motor
92.2
85.9
89.1
Research Octane Penalty =93.1-92.2= 0.9 Octane
Octane Debit =0.9 Octane / $0.02 /58,520 Bbls / 42 Gal / 365 Days
/ $0.02 /58, 520 Bbls / 42 Gal/
/ 6 Octane,Gal /Day7Bbl7~
Year
= $2.69 million/year
or 0.30 cents per gallon of gasoline.
*Compared to Case 1
169
-------
Table 2-12. COST FOR GASOLINE DESULFURIZATION - CASE 3*
Refinery Capacity 100,000 BPCD
Investment for Desulfurization Facilities $8.3 million
Years to Payout 5
Million Dollars Per Year:
Cash Flow 1.66
Depreciation 0.55
Net Profit 1.11
Income Tax 1.11
Gross Margin 2.22
Operating Costs:
Depreciation 0.55
Operating Manpower 0.22
Utilities 0.91
Catalyst Replacement 0.04
Interest 0.42
Maintenance 0.29
Local Taxes and Insurance 0.01
Credit for Added Products -0.06
Cost for Added Butane 0.04
Debit for Lower Octane 2.69
Total Operating Costs 5.11
Total Added Cost for Low-Sulfur Gasolines
(Gross Margin + Operating Costs) 7.33
Cents Per Gallon Gasoline 0.82
170
*Compared to Case 1
-------
Table 2-13. INVESTMENT FOR DESULFURIZATION FACILITIES - CASE 3
Investment *
Capacity Million Dollars
Refinery 100,000 BPCD
Light Gasoline Hydrodesulfurizer Unit 9,700 BPSD 2.8
FCC Gasoline Hydrodesulfurizer Unit 21,600 BPSD 3.6
Onsite Subtotal 6.4
Offsite 1.9
7
171 ,
Total Investment 8.3
-------
Table 2-14. COMPARISON OF YIELDS - CASE 1 AND CASE 3
BPCD
Charges
Crude Oil
Isobutane
N-Butane
Total Charges
Case 1
100,000
863
3,964
104,827
Case 3 Difference
(Case 1-Caso 1)
100,000
863
3,979
104,842
15
15
Products
Fuel Gas, F.O.E.
LPG (Propane-Propylene)
Gasolines
Kerosine
Diesel Fuel
No. 2 Furnace Oil
No. 6 Fuel Oil
Delayed Coke (5 Bbl = 1 Ton)
Asphalt
Sulfur
Total Products (Excluding Sulfur)
4,060
3,391
58,306
8,500
8,200
16,023
5,324
1,008
3,100
3,867
3,391
58,520
8,500
8,200
16,023
5,324
1,008
3,100
-193
214
(20 ton/day) (22 ton/day)(2 ton/day)
Apparent Gain (Products Minus Charges)
107,912
3,085
107,933
3,091
21
172 ,
-------
Table 2-15. UTILITIES AND CATALYST REPLACEMENT - CASE 3*
Process Unit
Capacity
Light Gasoline
Hydro-
Desuifurization
9,700 BPSD
Light Gasoline
Hydro-
Desulfurization
21,600 BPSD
Total
Consumption of Utilities
Electricity, KW
Fuel, MM Btu/H
Cooling Water, GPM
Wash Water, GPM
240
24
400
10
1,070
90
1,430
30
1,310
114
1,830
40
Cost of Utilities, $/CD
Catalyst Replacement, $CD
40
70
2,490
110
Fuel Equivalent of
Utilities, BPCD (F.O.E.)
501
'Utilities and catalyst replacement are incremental above those
in Case 1.
173
-------
SULFUR DISTRIBUTION
The sulfur contained in the crude oil to the refinery
is distributed in the products, recovered as elemental
sulfur, and emitted as S02 to atmosphere as shown in
Table 2-16 for all three cases studied.
Sulfur contained in the gasoline is only a small
fraction of the sulfur in the crude oil. Sulfur in the
products used as fuels eventually will be emitted as
sulfur oxides to the atmosphere as products of combus-
tion unless stack gas scrubbing or other types of
controls are used. The sulfur in delayed coke may be
emitted as sulfur oxides to the atmosphere or be com-
bined in metallurgical slag, depending upon the use
of the delayed coke.
From the values tabulated in Table 2-16, it is seen
that hydrodesulfurization of the gas oil feedstock to
catalytic cracking (Case 2) results in:
gasoline with the same sulfur content as Case 3
but lower than Case 1
diesel fuel, No. 2 furnace oil and Banker "C" with
lower sulfur than either Case 1 or 3
increased recovery of elemental sulfur
174
-------
Table 2-16. SULFUR DISTRIBUTION
Sulfur Content, Lb/hr Case 1 Case 2 Case 3
Crude Oil
Products:
Gasoline
Kerosine
Diesel Fuel
No. 2 Furnace Oil
Bunker C
Asphalt
Delayed Coke
Recovered as Elemental Sulfur
Emitted as S02 to Atmosphere
Total
Sulfur Distribution, %*
Gasoline
Kerosine
Diesel Fuel
No. 2 Furnace Oil
Bunker C
Asphalt
Delayed Coke
Recovered as Elemental Sulfur
Emitted as S02 to Atmosphere
6,014
191
119
148
554
] ,403
834
484
1,669
612
6,014
3.2
2.0
2.5
9.2
23.3
13.9
8.0
27.7
10.2
6,014
38
119
135
271
987
834
484
2,834
312
6,614
0.6
2.0
2.2
4.5
16.4
13.9
8.0
47.2
5.2
6,014
38
119
148
554
1,403
834
484
1,814
620
6,014
0.6
2.0
2.5
9.2
23.3
13.9
8.0
30.2
10.3
Total 100.0 100.0 100.0
*As percent of sulfur in crude oil
175
-------
APPENDIX A
GENERAL SITUATIONS OF REFINERIES IN THE UNITED STATES
No two crude oils or two refineries are the same.
Furthermore, no two refineries will produce and have the
same product demand. Depending upon the crude properties
and refinery process capabilities, different refineries
are geared to the following categories or combinations
thereof:
Production of gasolines, mid-distillates and residual
oil
Petrochemical production
Lubricant production
Asphalt production
United States refineries produce petroleum products in
relation to the market demands for quantities and properties.
Each refinery bases its operations on market demands and
availability of crudes within the limitations of its refinery
process units and the flexibility of operating conditions.
In crude topping and vacuum operations, crude oils can
be distilled into fractions with true boiling cut points
approximately as follows:
Butanes and lighter components to gas recovery
Pentanes to 200°F light gasoline for blending to
gasoline or isomerization of the pentanes and hexanes
to upgrade the octane number
200°F - 370°F naphtha for reformer feedstock to up-
grade the octane number or produce aromatics
i 176
-------
600°F - 1,000°F gas oil feedstock to catalytic crack-
ing, thermal cracking or hydrocracking
Heavier than 1,000°F residuum for blending No. 6
fuel oil or to asphalt or produced as feedstock for
visbreaking, delayed coking, fluid coking or solvent
deasphalting
Tyipcal ASTM distillations of refined products to sales
are shown in Figure A-l. Gasolines distill in the range of
80°F to 400°F, kerosine and jet fuel (kerosine-type) distill
in the range of 340°F to 530°F and diesel fuel and No. 2 fuel
oil distill in the range of 350°F to 650°F. The term "mid-
distillates" refers to the distillates boiling between
gasoline and No. 6 fuel oil and comprises the kerosine,
aviation jet fuel, diesel fuels and No. 2 heating oil. Kero-
sine, aviation jet fuel and No. 1-D diesel fuel are produced
from the distillates boiling between 370°F and 500°F true
boiling cut points. No. 2 heating oil and No. 2-D diesel
fuel are blends of essentially 50 percent of the 370°F to
500°F fraction with 50 percent of the 500°F to 600°F fraction,
I
177
-------
DATA SOURCE:
700"
U.S. BUREAU MINES
PETROLEUM PRODUCTS SURVEYS
Figure A-l. Typical ASTM Distillations
of Petroleum Products.
178
-------
APPENDIX B
U.S. PRODUCTION OF PETROLEUM PRODUCTS
Table B-l shows the range of crude capacities in U. S.
refineries in 1973. Refineries larger than 25,000 BPSD
have 92.5% of the U.S. crude capacity. The median quantity
of crude is processed in U.S. refineries of about 100,000
BPSD crude capacity.
Table B-2 shows the charge capacity of U. S. refineries
in 1973 by types of processing units.
Table B~3 shows the production U. S. refinery products
in 1971. Table B-4 shows the U. S. demand for mid-distillates
by use in 1973.
Table B-5 shows typical properties of the petroleum
products sold in the United States in 1972 and 1973.
The 1972 properties of the total U.S. gasoline pool were
estimated from U.S. Bureau of Mines surveys and Ethyl Corp-
oration sales data as follows:
Research Octane 97.5
Motor Octane 90.0
Lead, g/gal. 2.24
Sulfur, wt% 0.031
The response of lead content in the total U.S. gasoline
pool was estimated from the lead response of various premium
and regular gasoline blends. Figure B-l shows the research
and motor octanes of the total U.S. gasoline pool in 1972
as a function of lead content.
179
-------
Table B-l. CRUDE CAPACITIES OF U.S. REFINERIES IN 1973
Range of Crude
Capacities, BPSD
0-10,000
10,000-25,000
25,000-75,000
75,000-125,000
125,000-200,000
200,000-300,000
Larger Than 300,000
Total
Refineries Larger
Than 25,000 BPSD 125 12,848,000 103,000 92.5
Number
of
Refineries
76
43
64
31
15
8
7
Crude Capacity , BPSD
Total
340,000
702,000
2,826,000
3,033,000
2,298,000
2,145,000
2,546,000
Average
4,500
16,000
44,000
98,000
153,000
268,000
364,000
244 13,890,000
% of
U.S. Crude
Capacity
2.4
5.1
20.4
21.9
16.5
15.4
18.3
100.0
180
-------
Table B-2. CAPACITY OF PROCESS UNITS IN UNITED STATES IN 1973
Process Unit
Crude Distillation
Vacuum Distillation
Delayed Cokers
Fluid Cokers
Visbreakers
Hydrogen Desulfurization:
Naphtha
Mid-Distillates
FCC Feedstock
Heavy Gas Oil
Reduced Crude
Cat Crackers (Fresh Feed)
Hydrocrackers
Cat Reformers
Alkylation (Sulfuric Acid)
Alkylation (Hydrofluoric Acid)
Aromatics (Benzene-Toluene-Xylenes)
Isomerization
Butane
Pentane
Pentane-Hexane
Lubes
Asph I
Coke
Charge
Capacity, BPSD
13,890,000
5,150,700
776,900
118,200
237,300
2,798,800
1,109,700
279,800
184,000
19,500
4,512,600
865,100
3,278,100
531,300
280,600
Vol. % o
Crude Cap
100.0
36.8
5.6^
o.sj
1.7
20.0
7.9
2.0
1.3
0.14
32.3
6.2
23.4
3.8}
2.0J
188,500
49,600
34,100
37,500
221,900
644,300
1.3
0.35
0.24
0.27
1.6
4.6
6.4
5.8
(42,700 ton/day) (0.00305 tons
coke per barrel
crude)
181
-------
Table B-3. U. S. REFINERY PRODUCTS IN 1971
Refinery Input
Crude Runs to Still
Natural Gas Liquids
Refinery Production
Motor Gasoline
Aviation Gasoline
Naphtha in Naphtha-Type Jet Fuel
Special Naphthas
Petrochemical Feedstocks
Total Gasoline-Naphtha
Ethane-Ethylene
Liquefied Petroleum Gas (LPG)
Propane- Propylene
C3-C4 Mix
Total Light Components
Kerosine
Kerosine-Type Jet Fuel
Kerosine in Nahptha-Type Jet Fuel
Total Kerosine
Distillate Fuel Oil
Residual Fuel Oil
Asphalt (5.5 bbl = 1 short ton)
Road Oil
Total Residual Oil
Lubricants
Wax (1 bbl = 280 Ib)
Coke (5 bbl = 1 short ton)
Miscellaneous Products
Still Gas to Fuel
C3 to Fuel
C4 to Fuel
LPG to Fuel
Accounted Yield
Difference (Accounted Minus Input)
Million
4,088
359
4,447
Million
2,179
18
43
28
111
9
32
12
3
87
219
42
275
157
9
65
7
157
5
14
3
Barrels
Barrels
2,379
56
348
911
441
72
62
14
179
4,462
15
Input,
100.0
8.8
108.8
Yield,
53.3
0.4
1.1
0.7
2.7
0.2
0.8
0.3
0.1
2.1
5.4
1.0
6.7
3.8
0.2
1.6
0.2
3.8
0.1
0.3
0.1
%*
%*
58.
1.
8.
22.
10.
1.
1.
0.
4.
109.
0.
2
4
5
3
8
8
5
3
3
1
3
*Voluine percent on crude input
182
-------
Table B-4. U.S. DEMAND FOR MID-DISTILLATES BY USE IN 1973
Kerosine
Kerosine-type Jet Fuel
Kerosine Content of Naphtha-type Jet Fuel
No. 1 Range Oil
Diesel Fuel Used on Highways
Industrial Uses
Oil Company Fuel
Railroads
Vessel Bunkering
Military Uses
Million Barrels %
80
233
38
15
6.1
17,6
2.9
1.1
164
50
14
86
21
17
366
12.4
3,8
1.1
6.5
1.6
1.3
2777
352
Heating Oil
Gas and Electric Company Public
Utility Power Plants
509
35
544
38.5
2.6
41.1
Miscellaneous and Unaccounted
60
4.5
Total Mid-distillates
1,322
100.0
183- '
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LEAD ALKYL ANTIKNOCK SUSCEPTIBILITY CHART
100
TOTAL U.S. GASOLINE POOL IN 1972
LEAD, g/gal. 2.24
RESEARCH OCTANE 97.5
MOTOR OCTANE 90.0
SULFUR, WT% 0.031
H 105
100
u 5 i l : - 2.0 2 5 3.0
ANTIKNOCK CONTENT GRAMS MtfAUiC IEAO PER GALLON
Figure B-l. Octane of Total U. S. Gasoline Pool in 1972.
4 o
6.0
80
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QC.
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185
-------
APPENDIX C
COSTS
1. All costs and capital are based on January, 1974
levels.
2. Capital related charges
Straight-line depreciation for 15 year life
Interest at 10 percent per year. This is equivalent
to 5 percent per year over the average payout period,
Maintenance: onsite, 4 percent; offsite, 2 percent
Local taxes and insurance: 1.5 percent
Payout on investment: 5 years after taxes
3. U.S. income plus state corporation taxes at 50 per-
cent of gross profit.
4. Incremental utility costs for new facilities
Fuel: $1.40 per million Btu net heat value. This
is equivalent to $7.50 per barrel of 38°API
crude oil.
Electricity: $ Per KWH
Fuel cost 0.014
Other charges Q .006
0.020
Steam:
$1.90 per 1,000 pounds corresponding to the
fuel cost of $1.40 per million Btu.
Cooling Water:
$0.20 per 1,000 gallons circulation
Treated boiler feedwater:
$0.05 per 1,000 pounds
5. Operating manpower costs
Average costs for stillman and operators at $6.00
per hour plus 30 percent fringe benefits. Sixty
percent overhead on operating manpower is added to
allow for supervision, laboratory, technical service
'186
-------
and instrument services.
Manpower Cost
Per Shift Position $/HR %_ $/YR
Rate 6.00 52,600
Fringe Benefits 30 15,800
Overhead 60 41,000
TOTAL 109,400
Product prices
Incremental product yields were priced at the same
price as crude oil ($7.50 per barrel).
Royalties
Gas oil hydrodesulfurization:
Paid-up royalty $10.00 per BPCD feed rate
Naphtha hydrodesulfurization:
Royalty-free. Royalty costs would be included in
catalyst costs or nominal know-how fee.
Hydrogen make-up
Assumed to be available in tne reformer make-gas for
hydrodesulfurization units.
Gasoline octane
Incremental gasoline octane priced at 2.0 cents per
6 octane difference between premium and regular
gasolines at the 1972 lead level of 2.24 grams
per gallon. This price is equivalent to 0.333 cents
per gallon per research octane number.
187
-------
APPENDIX D
OIL EQUIVALENT OF UTILITIES
1. Fuel
Net heat value at 6.1 million Btu per barrel fuel
oil equivalent. (F.O.E.)
2. Electricity
Net heat to generate electricity is assumed to be
10,000 Btu per kilowatt-hour. This requires 0.04
BPCD F.O.E. per kilowatt-hour.
3. Steam
Net heat to generate steam is assumed to be 1,370
Btu per pound of steam. This requires 5.4 BPCD
F.O.E. per 1,000 pounds per hour of steam.
188,
-------
APPENDIX E
SOURCES OF INFORMATION
American Petroleum Institute
"Annual Statistical Review, U.S. Petroleum
Industry Statistics, 1972"
U.S. Bureau of Mines, Mineral Industyr Surveys
"Motor Gasolines, Summer 1972"
"Motor Gasolines, Winter 1972-1973"
"Aviation Turbine Fuels, 1972"
"Diesel Fuels, 1973"
"Burner Fuel Oils, 1973"
"Crude Petroleum, Petroleum Products, and Natural-
Gas-Liquids; 1971 (Final Summary)"
U.S. Federal Register
Environmental Protection Agency
Part 80. Regulations of Fuels and Fuel Additives
Vol. 38, No. 6 - Jan. 10, 1973
Vol. 38, No. 234 - Dec. 6, 1973
Ethyl Corporation
"Yearly Report of Gasoline Sales by States, 1972"
Oil and Gas Journal (Petroleum Publishing Company)
"1973-74 Worldwide Refining and Gas Processing
Directory"
\
189
-------
CHAPTER 1
INTRODUCTION
This part of the report covers work which was performed under Cor tra-t
68-02-1308 for the Environmental Protection Agency (EPA), Office of
Research and Monitoring, Task 10, Phase 3.
The purpose of this work is to determine the impact of producing low-sulfur
gasolines on the refineries supplying California and the Los Angeles area.
Refineries in the Los Angeles area account for 56% of the crude capacity in
California. For this work, the basic refinery was considered to have process
units with capacities based on percent of crude input to be the average of
refineries within California charging a crude mix with the average composi-
tion of crudes now being processed in California. Desulfurization facilities
were then added to this basic refinery, using two processing schemes, to
produce low-sulfur gasolines.
Refineries in California process crude mixes averaging 53% domestic crudes
and 47% foreign crudes. The California crude oils are heavy crudes with
high sulfur content. As the results of the heavy high sulfur charge stocks
and the market demands in California, these refineries have more residual
oil processing, more hydrogen treating of products, and more hydrocracking
of gas oils than the "typical refineries in the United States.
In order to show the maximum costs for producing low-sulfur gasolines, it
was assumed that new facilities would be necessary to provide the incremen-
tal hydrogen, remove hydrogen sulfide and recover sulfur.
Part 2 of this report (Phase 2) presented a similar study based on a
"typical" U. S. refinery and crude oil mix. The Phase 3 work supple-
ments the Phase 2 report.
190
-------
CHAPTER 2
SUMMARY
This study shows how a model of the average refineries in Calii^r . - can
produce no-lead, low-sulfur gasoline and by installing new hyc'rodes Ifru i-
zation facilities can produce low-sulfur gasolines to include th(> n '._ t ,
premium, and regular gasolines.
Results of this study show that the existing large California refineries can
produce no-lead, low-sulfur gasoline at the projected percent of gpsolines
sales through 1979, blended from normal butane, light, hydrocrackate, re-
formate, and alkylate. Beyond 1976, the predicted demand of no-lead and
premium gasolines could not be met with EPA limits on lead anti-knock in
the total gasoline pool.
Total gasolines can be made low-sulfur by hydrodesulfurization of the gas
oil feedstock to catalytic cracking and by hydrodesulfurization of the light
virgin gasoline and light thermally cracked gasolines. Economics for this
scheme (Case 2) show that the costs** for producing low-sulfur gasoline
would add 1.1 cents per gallon to the costs of manufacturing the present gaso-
lines in refineries of 100,000 barrels per calender day (bpcd) capacities.
An alternate case considers hydrodesulfurization of the catalytically cracked
gasoline rather than the feedstock to the catalytic cracker. Economics in-
dicate that this scheme (Case 3) to produce low-sulfur gasoline would add
about 1. Ocent per gallon to the present cost** of manufacturing gasolines
in refineries of 100, 000 bpcd capacities.
In California, there are eleven refineries which are larger than 75, 000 bpsd."
The crude capacities for these eleven refineries total 1,402, 000 bpsd which
is 78% of the total crude capacity of all refineries in California. If new
facilities were installed to produce low sulfur gasolines in these eleven re-
fineries by desulfurizing the light virgin gasoline, light thermal gasolines,
and catalytic cracker feedstock (Case 2), an investment of about 250 million
dollars would be required based on May, 1974 costs.
Based on the gasoline yields and properties in Case 2 for low-sulfur gaso-
lines, the predicted sales ratios of no-lead, premium, and regular gaso-
lines could be blended and meet the EPA regulations on lead phase-down for
1975 and 1976. Additional processing for octane up-grading would be re-
quired starting in 1977 to meet the EPA regulations on further lead phase-
down.
bpsd - Barrels per stream day
bpcd - Barrels per calander day
Costs include 5 years payout on investment (20% rate of return) after
taxes.
191
-------
CHAPTER 3
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE IN
PRESENT CALIFORNIA REFINERIES
CRUDE OILS RUN IN CALIFORNIA REFINERIES
At present. California refineries process about 53% domestic
crudes and 47% imported crudes. Table 3-1 shows the origins of
crudes processed in District 5 which includes California. The Cali-
fornia crude oils are typically heavy and high sulfur crudes. The
Middle East are also typically high sulfur crudes. Therefore, the
average mixture of crudes processed in California refineries is
heavier and has higher sulfur content than the crudes processed in
the average U.S. refinery.
Table 3-2 lists the crude mix selected for this study. This crude mix
would be 28°API. 1. 27 wt% sulfur, and 4.1 wt% Conradson carbon.
When the Alyeska pipeline begins delivering North Slope crude oil in
1977, this crude will probably be processed by the West Coast refin-
eries and reduce their imports of foreign crude oils.
Addition of Alaskan North Slope crude oil to the West Coast crude mix
will not materially effect the crude mix as the North Slope crude is
26°API, 1.1 wt% sulfur, and 6.0 wt% Conradson carbon.
AVERAGE OF CALIFORNIA REFINERIES - CASE 1
As the results of processing heavy crude oils with high sulfur contents
and sales demands, the California refineries have more residual oil
processing, more hydrogen treating of products, and more hydro-
cracking of gas oils than the "typical" refineries in the United States.
Table 3-3 shows the capacities of processing units in California re-
fineries. '
The refinery process units selected for Case 1 for an "Average of
California Refineries" were as follows:
- Crude and Vacuum Distillation
- Catalytic Reformer with Hydrogen Pretreat Section
- Fluid Catalytic Cracker with Vapor Recovery
- Catalytic Hydrocracker
- Jet Fuel Hydrotreater
- Diesel Hydrotreater
- Alkylation
- Delayed Coker
- Visbreaker
- Solvent Deasphalting
- Amine Treating and Sulfur Recovery
192
-------
Table 3-1. CRUDE OILS FOR DISTRICT 5
THOUSAND BARRELS VOL% OF
PER DAY TOTAL
From: Oil & Gas Journal, March 18, 1974
Domestic Crudes:
California 910 42. 2
Alaska 190 8.8
Four-corners Pipeline 30 1.4
Rail From Utah 15 0.7
1, 145 53.1
Foreign Crudes:
Canada 250 11.6
Venezuela 20 0.9
Ecuador, Peru 70 3. 2
Middle East 470 21.9
Indonesia 200 9.3
1,010 46.9
Total Crude Oils 2, 155 100.0
193
-------
Table 3-2. SELECTED CRUDE MIX
THOUSAND BARRELS
PER DAY
California:
Midway- Sunset
Huntington Beach
Wilmington
Alaska
Canada
Middle East (Arabian)
Indonesia (Minas)
Total
910
190
250
470
200
2,020
VOL% OF
TOTAL
13
7
25
194
-------
Table 3-3. PROCESSING UNITS IN CALIFORNIA REFINERIES
PROCESS UNIT
Crude Distillation
Vacuum
Catalytic Cracking
Catalytic Hydrocracking
Thermal Cracking Gas Oil
Catalytic Reforming
Hydrotreating:
Naphtha
Mid-Distillate
Other
Delayed Coking
Fluid Coking
Visbreaking
Alkylation, HF
Sulfuric Acid
Aromatics, BTX
Isomerization, C
C
Lubes
Asphalt
Solvent Deasphalting
C6
FEED CAPACITY
BPSD
Los Angeles
Area
996.000
509, 500
284, 500
134, 200
23,000
245,700
234, 000
149,000
210,000
-
86.000
15,800
33,600
4,000
5,000
13,000
-
47, 100
-
Total
California
1.785. 200
930.000
473, 500
312.100
32.500
463,700
425,400
202,800
64,000
252,500
71,000
95,600
15, 800
73,000
5, 500
9,700
13,000
23,800
96,400
45,000
FEEDCAPAC
VOL% ON CRUDE
Los Angeles
Area
100.0
51. 2
28.6
13. 5
2.3
24. 7
23.5
15.0
-
21.1
-
8.7
1.6
3.4
0.4
0.5
1.3
-
4.7
-
:ITY
CAPAC ITY
Total
California
100.0
52. 1
26. 5
17. 5
1. 8
26. 0
23. «
11.4
3.6
14.1
4.0
5.4
0.9
4.1
0.3
0.5
0.7
1.3
5.4
2.5
r195
-------
Figure 3-1 shows the flow scheme for this "Average of California
Refineries".
To calculate the refinery yields, the following conditions were
assumed:
- Crude input to basic California refinery (Case 1) would be
100,000 bpcd crude oil.
- Catalytic cracker would operate at 75% conversion with yields
corresponding to riser cracker with zeolite catalysts.
- Production of alkylate was set at 5.0 vol% on crude input by
taking propylene to LPG.
Reformer severity would produce 95 research octane clear.
- Unfinished asphalt would be produced from vacuum residuum and
asphalt from solvent deasphalting.
- Production of lubricants and waxes were not considered as these
account for only 0. 9 vol% on crude input.
- Special naphthas and the benzene - toluene - xylenes aromatics
were considered to be part of reformate and would be accounted
in the total gasolines.
Capacities of the process units required to process the streams from
the selected crude mix in Case 1 are compared in Table 3-4 with the
average of California refineries based on percent of crude input.
Product yields and properties in Case 1 are compared in Table 3-5
with products produced in California refineries.
The comparisons in Table 3-4 and Table 3-5 show that refinery
model and crude mix used in Case 1 may be considered an average
of the California refineries.
For Case 1, the overall material balance is shown in Table 3-6 and
the gasoline pool is shown in Table 3-7.
The volumetric blended octanes shown in Table 3-7 were corrected
for sensitivities, olefin content and aromatic content. The correc-
ted octanes are shown in Figure 3-2.
SALES OF PREMIUM AND NO-LEAD GASOLINES IN CALIFORNIA
During the period 1953 to 1972, the premium gasoline sales as per-
cent of total gasoline sales in California has been 16 to 20% higher
than the average for the United States.
Figure 3-3 shows a projected percent of sales of premium gasoline
and no-lead gasoline in California. It was assumed that the premium
gasoline would be 25% of sales in 1977. The sales requirements for
premium gasoline will continue to decrease as the pre-1971 high
196
-------
D
^ ^.xftfrt. T~
\ * r
Figure 3-1. Flow schemes for
197
-------
tJf&t/r
c >^^"- .a£>«_S~
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of California refineries.
198
-------
Table 3-4. CAPACITIES OF PROCESS UNITS IN CASE 1
COMPARED WITH CALIFORNIA REFINERIES
PROCESS UNITS
Crude Distillation
Vacuum Distillation
Catalytic Cracking
Catalytic Hydrocracking
Thermal Cracking Gas Oil
Catalytic Reforming
Hydrotreating:
Naphtha
Mid-Distillate
Other
Delayed Coking
Fluid Coking
Visbreaking
Alkylation, HF
Sulfuric Acid
Aromatics, BTX Production
Isomerization, C%
C5 & C 6
Lube Production
Asphalt Production
Solvent Deasphalting
VOL% OF CRUDE CAPACITY
Average of California
Refineries in 1973
100.0
52. 1
26. 5
17. 5
1.8
26.0
23. 8
11.4
3.6
14.1
4.0
5.4
0.9
4.1
0.3
0. 5
0.7
1.3
5.4
2.5
Case 1
100.0
51. 5::
24. 4
17. 1
24.0
15. 8
11.4
12.3
3.7
5. 0
2. 2
1.7
-At 670° F TBP cut point in crude oil
199
-------
Table 3-5. COMPARISON OF PRODUCTS AND YIELDS
Basis: Yields are Vol"'> on crude input and for West (Oast (PAD District
5) for January 1D72-September, 1973. Properties of products are
from 1973 sales in California.
TOTAL GASOLINES
Yield, Vol % on Crude Input
°API
Sulfur, wt%
Lead Anti-knock, Grams Per Gal.
Research Octane
Motor Octane
Reid Vapor Pressure
JET FUEL AND KE ROSIN K
Yield, Vol% on Crude Input
CAPI
Sulfur, wt%
Aniline Point, ° F
DIESEL AND NO. 2 FURNACE OIL
Yield, Vol% on Crude Input
"API
Sulfur, \vt%
Cetane Index
NO. 6 FUEL OIL
Yield, Vol% on Crude Input
°API
Sulfur, wt%
Carbon Residue, wt%
OTHER PRODUCTS
Yield, Vol% on Crude Input:
Coke (5 bbl = 1 Short Ton)
Asphalt and Road Oil
Still Gas to Fuel
Liquefied Refinery Gas
Lube Oil, Wax, & Miscellaneous
AI .xRENT PROCESSING GAIN
Vol% on Crude Input
LPG INPUT
West Coast
Production
51.0
58. 5
0.046
2. 1
97.2
89.0
10.0
11.0
42.9
0.045
143
13.7
35.0
0. 27
50.0
17.4
11.0
1.5
11.2
4.5
3.3
4.7
2. 5
1. 2
6.4
Case 1 Case 2 Case
55. 5
61. 5
0.053
2.1
97.1
89.6
10.0
11.6
39.0
0.049
139
14.8
35.7
0.26
48.8
14.6
10.8
2.4
9.1
3.1
2. 2
3.8
2.9
None
55.5
62.6
0.006
2.1
H7.4
! 0.4
10.0
11.6
39.0
0.049
139
14.8
35.6
0. 26
48.8
14.6
11.3
1.7
9.1
3.1
2.2
3.7
3.3
None
55.5
61.6
0.006
2.1
96.0
90. 8
10.0
11.6
39.0
0.049
139
14.8
35.7
0.26
48.8
14.6
10.8
2.4
9.1
3.1
2.2
3.8
2.9
None
Vol% on Crude Input
1.0
6.4
1.2
7.0
0.8
6.4
1.2
200
-------
Table 3-6. OVERALL REFINERY MATERIAL BALANCE - CASE 1
INPUT BPCD #/H SULFUR CONTENT. tf/H
Crude Oil 100,00 1,292,720 16,377
Purchased N-Butane 1,204 10,250
H2Plant: Nat. Gas-FOE 848 10,020
Water 22. 550
Total Input 102,052 1, 335, 540
OUTPUT
Gas to Fuel - FOE 3,769 46,210 182
HoS to Sulfur Recovery - 7,030 6,613
LPG 2,874 21,360
Gasolines 55,519 592,760 315
Alkylation By-product Oil 6 80
Jet Fuel & Kerosine 11,582 140,060 68
Diesel & Distillate Fuel Oil 14,787 182,400 472
No. 6 Fuel Oil 14,629 212,010 5,167
Asphalt 2,200 33,540 1,017
Delayed Coke (5 bbl = 1 Short
Ton) 3,100 51,660 1,723
Catalytic Cracker Coke
Burned - 20,450 820
CO2 From H2 Plant - 27,560
NH3 From Hydrocracker - 420
Total 108.466 1,335.540 16.377
Apparent Gain 6,414
201
-------
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°'5 1-0 1.5 2.0 2.5 3.0
ANTIKNOCK CONTENT, GRAMS METALLIC LEAD PER GALLON
Figure 3-2. Octanes oi Total Gasoline Pod
105
h J.5
h 1.0
0.5
100
100
90
95
h 8C
90
70
h 60
80
4.0
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203
-------
1986
Figure 3-3. Projected Percent of Sales of Premium
and No-Lead Gasoline; in California-
204
-------
compression cars are junked. The projected sales percent of
no-lead gasoline is assumed to follow the projected sales of new cars
which require no-lead gasolines.
PRODUCTION OF NO-LEAD, LOW-SULFUR GASOLINE IN PRESENT
CALIFORNIA REFINERIES
The time to plan, finance, and construct refining facilities to up-
grade gasoline blending components requires about three years
from the date of a firm decision to proceed. During the period un-
til the additional gasoline-upgrade facilities are onstream, the no-
lead, low-sulfur gasolines will have to be blended from low-sulfur
components which can be produced in the present refining facilities.
In the California refineries, the presti.1: low-sulfur gasoline compon-
ents are normal butane, reformate, light hydrocrackate and alkylate.
The potential production of no-lead, low-sulfur gasoline together
with premium and regular gasoline were calculated attempting to
meet the EPA regulations on lead phase-down using the blending
components produced in Case 1. The results (Table 3-8) indicate
that the projected percent of gasoline sales can be met in 1975 and
and 1976. In 1977 and later years, the EPA limit on lead content
would be exceeded.
No-lead gasoline and premium gasoline utilize the same gasoline
blending components such as reformate and light hydrocrackate or
alkylate. Regular gasoline will contain the lower-octane blending
components which cannot be utilized in no-lead or premium gasoline
blends. Therefore if the projected sales demand for no-lead or pre-
mium gasoline significantly increased from the projected sales,
shortages of premium and no-lead gasoline may occur.
In 1977 and later years, octane up-grading will become necessary
to meet the EPA regulations on lead phase-down. In 1977, it may be
possible to increase the reformer severity. In the later years, new
octane up-grading facilities will need to be installed. The processes
for octane up-grading include isomerization of normal pentane arid
hexanes and reforming of heavy catalytic cracked naphtha.
In producing no-lead, low-sulfur gasoline, Table 3-8 shows that the
sulfur contents by 1979 in the premium and regular gasolines will
be about twice the present sulfur levels. In 1979, regular gasoline
and premium gasoline would respectively contain 0.11 and 0.07 wt%
sulfur.
205
-------
Table. 3-BIOPOTENTIAL GASOLINE PRODUCTION IN CASE 1
WITH LEAD PHASE-DOWN
Y >ar
Lead Content, Grams/Gal
Allowed by EPA
Total Gasoline Pool
Premium Gasoline
Regular Gasoline
Potential Gasoline. Vol%
No-Lead, Low-Sulfur
(92 RON)
Premium (99. 5 RON)
Regular (93.5 RON)
No-Lead Gasoline, Vol%
N-Butane
Light Hydrocrackate
Reformate
Alkylate
Premium Gasoline, Vol%
N-Butane
Alkylate
Reformate
FCC Gasoline
Light Hydrocrackate
Regular Gasoline, Vol%
N-Butane
Isobutane
Light Coker & VB
Gasoline
Reformate
FCC Gasoline
Light Hydrocrackate
Light Virgin Gasoline
HDS Gasoline
Alkylat^
1972
1975
1976
1977
1978
197!!
4.2V"
2. 12
2.65
1.32
1.7
1. 56
2.91
0.92
1.4
1.07
2.00
0.92
1.0
1.01
2.07
1.07
0.8
1.03
2.75
1.17
0. r,
0.93
3.00
1 . 36
54
46
11
37
52
20
31
49
29
25
46
38
19
43
47
13
40
9
18
73
-
9
18
73
-
9
18
73
-
9
18
73
-
9
17
70
4
9
17
40
25
9
8
20
33
23
16
9
29
26
21
15
9
22
31
26
12
9
22
31
31
7
9
21
24
46
-
6
0. 5
4
31
28
7
23
0. 5
-
7
0.5
4
30
34
-
21
0. 5
3
6
0. 5
4
27
40
_
22
0. 5
-
6
0.5
4
15
43
_
23
0.5
8
5
0.5
5
5
48
_
25
0.5
11
5
0.
5
_
51
_
27
0.
11
5
5
206
-------
Table 3~8 (continued) . POTENTIAL GASOLINE PRODUCTION IN CASE 1
(1)
WITH LEAD PHASE-DOWN
Year 1972 1975 1976 1977 1978 1970
Gasoline Octanes
No-Lead, Research
Motor
Premium, Research
Motor
Regular, Research
Motor
Sulfur, Wt%
No-Lead, Low-Sulfur - -
Premium 0.033 0.037 0.034 0.043 0.050 0.074
Regular 0.058 0.076 0.087 0.094 0.104 0.112
Comment - See Note (3) (3) (3)
-
99.6
92.4
93.9
86.3
92.4
85.0
99. 5
93.5
93.5
85.5
92.4
85.0
99.5
96.8
93.5
84.9
92.4
85.0
99.5
95. 2
93. 5
85.7
92.4
85.0
99.5
92.6
93. 5
85.8
92. 5
85. 2
99. 5
91.7
1)3. 5
85. 9
NOTES:
(1) Gasoline blends are calculated at 10 pounds Reid vapor jjressure using the
gasoline components with the yields and properties from Case 1 for the
Average" of California refineries.
(2) Legal limit was 4. 2 grams lead content per gallon prior to EPA regulations.
(3) In 1977, 1978 and 1979, the lead content in the total gasolines would exceed
the EPA limits on lead content. Additional octane upgrading refining facili-
ties will be required to meet the EPA limits on lead content.
207
-------
CHAPTER 4
DESULFURIZATION OF GASOLINES
GENERAL
In order to calculate the costs of producing low-sulfur gasolines, the
"Average of California Refineries" was taken as the basic refinery
and then low-sulfur gasoline produced by two types of process addi-
tions:
- Hydrodesulfurization of catalytic cracker feedstock and hydrode-
sulfurization of the light virgin, light coker, and light visbreaker
gasolines (Case 2).
- Hydrodesulfurization of catalytic cracker gasoline and hydrode-
sulfurization of the light gasolines (Case 3).
In this study, the costs were purposely made on the conservative
(i. e. higher capital) side as follows:
Investments included new units to provide the incremental capa-
cities for hydrogen, amine treating and sulfur recovery. In Case
3, these units are small and may not be required.
- In Case 2, the catalytic cracker conversion was kept at 75% as in
Case 1. Depending upon the whether the refinery catalytic cracker
severity is coke limited or gas limited, it may be practical in Case
2 to increase the catalytic cracker conversion to make this case
more attractive.
In Case 3, the octane of the catalytic cracked gasoline would be lower
after hydrotreating due to partial olefin saturation. Economics deb-
ited the lower octane by penalizing the production of premium gaso-
line using the price differential between premium and regular gaso-
lines. If additional octane up-grading were necessary the costs
would further penalize Case 3.
CASE 2: AVERAGE CALIFORNIA REFINERY WITH HYDRODESULFURIZATION
OF CATALYTIC CRACKER FEED AND LIGHT GASOLINES
In Case 2, the crude oil and refinery process units would be the same
as Case 1 of the "Average cf California Refineries" with the following
additions:
- Hydrodesulfurization of catalytic cracker feedstock.
Light gasoline hydrodesulfurization.
- New units for incremental needs for hydrogen, amine treating,
and sulfur recovery.
The flow scheme for "Average of California Refineries" shows the
_dded hydrodesulfurization unit. The yields and product properties
are listed in Table 3-5 together with the information for the West Coast
production and Case 1. For Case 2, the overall material balance
208
-------
is shown in Table 3-9 and the gasoline pool is shown in Table 3-10
The sulfur content of the total gasolir.^o would be 0.006 weight percent.
The incremental investment to product low-sulfur gasolines is esti-
mated to be 18.7 million dollars (Table 3-11) in Case 2 for a 100,000
bpcd refinery.
In California, there are eleven refineries which are larger than
75,000 bpsd. The crude capacities of these eleven refineries total
1,402,000 bpsd which is 78% of the total crude capacity of all re-
fineries in California. If new facilities were installed to produce
low-sulfur gasolines in these eleven refineries by desulfurizing light
virgin gasoline, light thermal gasolines, and catalytic cracker feed-
stock (Case 2), an investment of about 250 million would be required
based on May, 1974 costs.
Economics show that this desulfurization scheme would add 1.1 cents
per gallon to the costs of producing gasoline (Table 3-16) .
The potential production of no-lead, premium and regular gasolines
were calculated attempting to meet the EPA regulations on lead
phase-down using the blending components produced in Case 2. All
the gasolines would be low-sulfur. The results (Table 3-12) indi-
cate that the projected percent of gasoline saies can be met in 1976.
In 1977 and later years, the EPA limit on lead content would be ex-
ceeded.
Results in Table 3-16 for Case 2 and in Table 3~8 for Case 1 indi-
cate that refiners should start planning installation of new octane
up-grading facilities or that EPA should relax the lead phase-
down regulations to about the 1.4 grams per gallon for 1976 and
later years.
CASE 3: AVERAGE CALIFORNIA REFINERY WITH HYDRODESULFURIZATION
OF CATALYTIC CRACKED GASOLIXE AX, LIGHT GASOLIXES
In Case 3, the crude oil and refinery process units would be the same
as Case 1 of the "Average of California Refineries" with the follow-
ing additions:
- Hydrodesulfurization of catalytic cracked gasoline.
- Light gasoline hydrodesulfurization.
- New units for incremental needs for hydrogen, amine treating,
and sulfur recovery.
209
-------
Table 3-9. OVERALL REFINERY MATERIAL BALANCE - CASE "'
INPUT BPCD £/H_ SULFUR CONTENT, #/H
Crude Oil 100,000 1,292,720 16,377
Purchased N-Butane 796 6,770
H2 Plant: Nat. Gas-FOE 1,076 12,720
Water 28,620
Total 101,872 1,340,830 16,377
OUTPUT
Gas to Fuel - FOE 3,746 46,120 183
H2 S to Sulfur Recovery 9,670 9, 100
L,PG 3,335 24,860
Gasoline 55, 536 589, 860 36
Alkylation 5 70
Jet Fuel & Kerosine 11,582 140,060 68
Diesel & Distillate Fuel Oil 14,821 182,860 473
No. 6 Fuel Oil 14,587 210,660 3,673
Asphalt 2,200 33,540 1,017
Delayed Coke (5 bbl=l Short
Ton) 3,100 51,660 1,723
Catalytic Cracker Coke
Burned 16,070 104
CO 2 From H2 Plant 34,980
NH 3 From Hydrocracker 420
Total 108,.--." 1,340,830 16,377
Apparent Gain 7,040
210
-------
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211
-------
Table 3-11. INVESTMENT FOR DESULFURIZATION FACILITIES - CASE 2
FACILITY
CAPACITY
Refinery Size 100,000 BPCD
Light Gasoline Hydrodesulfurizer 7.400 BPSD
Catalytic Cracker Feed
Hydrodesulfurizer
A mine H_ S Removal
Sulfur Recovery (Claus Plant)
Hydrogen Plant
Onsite
Offsite (at 30% of Onsite)
Total Investment
25,700 BPSD
Amine Circulation
193GPM
INVESTMENT,
MILLION DOLLARS
3.2
6.2
30 Short Tons/Day
8. 3 MM SCF/D
1.0
0.5
3.5
14.4
4.3
18. 7
* Investment includes paid-up royalties (if applicable) plus
initial charges of catalysts. Investment at May, 1974 levels.
212
-------
Table 3-12. POTENTIAL GASOLINE PRODUCTION IN CASE 2
WITH LEAD PHASE-DOWN
1.4
1.24
2.41
1.00
1.0
1.03
2.28
1.00
0.8
0.93
2.38
1.11
0. 5
0.76
1.87
1. 28
Year 1976 1977 1978 1979
Lead Content, Grams/Gal
Allowed By EPA
Total Gasoline Pool
Premium Gasoline
Regular Gasoline
Potential Gasoline. Vol%
No-Lead, Low-Sulfur (92 RON) 20 29 38 47
Premium (99. 5 RON) 31 25 19 13
Regular (93. 5 RON) 49 46 43 40
No-Lead Gasoline, Vol%
N-Butane 8999
Light Hydrocrackate 13 18 18 17
Reformate 38 73 73 72
FCC Gasoline 28 - - 2
Alkylate 13
Premium Gasoline. Vol%
N-Butane 8799
Alkylate 12 22 22 35
Reformate 41 15 29 16
FCC Gasoline 30 44 33 40
Light Hydrocrackate 9 12 7
Regular Gasoline, Vol%
N-Butane 5543
Isobutane 1111
HDS Light Gasoline 26 28 30 32
Reformate 32 24 6
Alkylate 5 8 11 10
Catalytic Cracked Gasoline 24 33 47 53
Light Hydrocrackate 6
HDS Gasoline 1111
213
-------
Table 3-12 (continued). POTENTIAL GASOLINE PRODUCTION IN CASE 2
WITH LEAD PHASE-DOWN
Year
Gasoline Octanes
No-Lead, Research
Motor
Premium, Research
Motor
Regular, Research
Motor
Sulfur. Wt%
No-Lead, Low-Sulfur
Premium
Regular
Comments - See Note
1976
92.3
84.6
99. 5
91. 5
93. 5
86.7
0.006
0.006
0.006
1977
92.4
85.1
99. 5
92. 2
93. 5
86.3
0.000
0.010
0.008
(2)
1978
92.4
85.1
99.5
92. 5
93.5
86.5
0.000
0.007
0.011
(2)
1979
92.5
85. 1
99.5
92.9
93. 5
85.8
0.000
0.009
0.013
(2)
NOTES:
(1) Gasoline blends are calculated at 10 pounds Reid vapor pressure
using the gasoline components in Case 2.
(2) In 1977, 1978 and 1979, the lead content in the total gasolines
would exceed the EPA limits on lead content. Additional octane
upgrading refining facilities will be required to meet the EPA
limits on lead content.
-------
Table 3-13. OVERALL REFINERY MATERIAL BALANCE - CASE 3
INPUT BPCD #/H SULFUR CONTENT, tf/H
Crude Oil 100,000 1,292,720 16,377
Purchased N-Butane 1,176 10,010
H2 Plant: Nat. Gas- FOE 929 10,980
Water - 24. 710 -
Total 102, 105" 1, 338,420 16, 377
OUTPUT
Gas to Fuel-FOE 3,769 46,210 182
H2S to Sulfur Recovery - 7,320 6,892
LPG 2,874 21.360
Gasoline 55,533 592,710 36
Alkylation By-Product Oil 6 80
Jet Fuel & Kerosine 11,582 140,060 68
Diesel & Distillate Fuel Oil 14,787 182,400 472
No. 6 Fuel Oil 14,629 212,010 5,167
Asphalt 2,200 33,540 1,017
Delayed Coke (5 bbl= 1 Short
Ton) 3,100 51,660 1,723
Catalytic Cracker Coke
Burned - 20,450 820
CO2 From H2 Plant - 30, 200
NH3 From Hydrocracker - 420
Total 108,480 1,338,420 16.377
Apparent Gain 6,375
215
-------
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216
-------
The yields and product properties foi case 3 are listed in Table 3-5
together with the information for the West Coast production and
Cases 1 and 2.
In removing sulfur from catalytic cracked gasoline, 87% desulfuri-
zation was selected since this yields about the same sulfur content
in the total gasolines as in Case 2 (0.006 wt% sulfur). At this
desulfurization severity, 55% of the olefins in the catalytic cracked
gasolines would be hydrogenated and lower the octane. In the eco-
nomics, the lower octane shows a penalty of 0.1 cent per gallon
of gasoline for 0.3 octane (Research/ 2+Motor/ 2) difference at 1.0
gram lead per gallon.
In Case 3, the incremental investment to produce low-sulfur gaso-
lines is estimated to be 13. 5 million dollars (Table 3-15) for a
100,000 bpcd refinery. Economics show that this desulfurization
scheme would add 1.0 cents per gallon to the costs of producing
gasoline (Table 3-16).
SULFUR DISTRIBUTION IN REFINERY PRODUCTS AND EMISSIONS
Sulfur contained in the crude oil to the refinery is distributed in the
products, recovered as elemental sulfur, and emitted as SQ2 to the
atmosphere as shown in Table 3-17.
In Case 1, the sulfur in the crude oil is distributed 37. 8% to re-
sidual fuel oil and asphalt, 38.0% recovered as elemental sulfur
and 8. 5% emitted as SO2 to the atomosphere. By desulfurizing the
catalytic cracker feedstock in Case 2, the recovery of elemental
sulfur can be increased to 52. 3% and the emission decreased to
5. 1%.
DISCUSSION
This study was based on a refinery model which represents an
average of the refineries in California. However, each refinery
in California may be distinctly different from this refinery model
in both the process units, crude mix charged, operating conditions
and products. Each refinery bases its operations on market de-
mands, availability of crudes, limitations of process units, and
flexibility of operating conditions. If it becomes mandatory to
produce only low-sulfur gasolines, each California refinery should
prepare their own economics as to which process scheme best suits
its refinery or refineries.
It is believed that desulfurization of the catalytic cracker feed will
generally be the most attractive.
217
-------
Table 3-15. INVESTMENT FOR DESULFURIZATION - CASE 3
FACILITY CAPACITY INVESTMENT,
MILLION DOLLARS
Refinery Size 100, OOOBPCD
Light Gasoline Hydrodesulfurizer 7,400 BPSD 3. 2
FCC Gasoline Hydrodesulfurizer 15,400 BPSD 4.4
Amine H2S Removal Amine Circulation
19GPM 0.3
Sulfur Recovery (Claus Plant) 3. 5 Short Tons/Day 0.1
Hydrogen Plant 4.0MMSCF/D 2.4
Onsite 10.4
Offsite (at 30% of Onsite) 3.1
* Investment includes paid-up royalties (if applicable) plus
initial charges of catalysts.
Total Investment 13.5
218
-------
Table 3-16. COSTS FOR GASOLINE DESULFURIZATION*
Case 2 3
Refinery Capacity, BPCD 100,000 100,000
Investment for Gasoline Desulfurization,
Million Dollars 18.7 13.5
Years to Payout 5 5
Return, Percent Per Year 20 20
Million Dollars Per Year:
Cash Flow 3. 74 2.70
Depreciation 1.05 0.90
Income After Tax 2.69 1.80
Income Tax at 48% 2.48 1.66
Tax Base 5. 17 3.46
Operating C6sts:
Depreciation 1.05 0.90
Operating Manpower 0.33 0.33
Utilities 3.10 1.45
Catalyst Replacement 0.14 0.04
Interest 0.94 0.68
Maintenance 0.66 0.48
Local Taxes & Insurance 0. 28 0.20
Incremental Product Credits -2. 28 0. 15
Debit for Lower Gasoline
Octane - 0. 85
Total Operating Costs 4. 22 5.08
Total added Costs for Gasoline Desulfurization:
Million Dollars Per Year (Tax Base + Oper.
Costs) 9.39 8.54
Cents Per Gallon Gasoline 1.10 1.00
* Incremental costs above Case 1.
219
-------
Table 3-17. SULFUR DISTRIBUTION IN REFINERY PRODUCTS AND EMISSIONS
SULFUR DISTRIBUTION, %
Case 1 Case 2 Case 3
Gasoline 1.9 0.2 0.2
Jet Fuel & Kerosine 0.4 0.4 0.4
Diesel & Distillate Fuel Oil 2.9 2.9 2.9
No. 6 Fuel Oil 31.6 22.4 31.6
Asphalt 6.2 6.2 6.2
Delayed Coke 10.5 10.5 10.5
Recovered as Elemental Sulfur 38.0 52.3 39.6
Emitted as SO2 to Atmosphere 8. 5 5. 1 8. 6
Total 100.0 100.0 100.0
As percent of sulfur in crude oil.
220
-------
Table 3-18. REFINERY RUNS - PAD DISTRICT 5 (WEST COAST)
Basis: Bu Mines Statistics for January, 1972 through September, 1973.
INPUT MILLION BARRELS VOL% ON
CRUDE INPUT
Crude Oil - Total 1,222 100.0
U.S. 757 61.9
Foreign 465 38. 1
Natural Gas Liquids - Total 35 2. 9
LPG 12 1.0
Nat. Gas. 23 1. 9
Total Input 1, 257 102. 9
OUTPUT
Gasoline (1) 623 51.0
Liquefied Refinery Gas (2) 30 2. 5
Jet Fuel and Kerosine (3) 1P4 11.0
Diesel and Distillate Fuel Oil 167 13. 7
Residual Fuel Oil 213 17.4
Lube Oil and Wax 11 0.9
Coke (5 bbls = 1 short ton) 55 4. 5
Asphalt and Road Oil 40 3. 3
Still Gas to Fuel 58 4.7
Miscellaneous 4_ 0.3
Total Output 1,335 109.3
Processing Gain 78 6.4
NOTES:
(1) Includes motor gasolines, aviation gasolines, petrochemical
feedstocks (aromatics) and special naphthas.
(2) Includes ethylene-ethane and liquefied refinery gas for fuel
and chemical uses.
(3) Includes jet fuel (kerosine type) and 50% of naphtha-type
jet fuel.
221
-------
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222
-------
APPENDIX A
SURVEY OF REFINERIES
IN CALIFORNIA
223
-------
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APPENDIX B
SOURCES OF INFORMATION
American Petroleum Institute
"Annual Statistical Review, U. S. Petroleum Industry Statistics,
1956-1972", (April, 1973).
U. S. Bureau of Mines, Mineral Industry Surveys
"Crude Petroleum, Petroleum Products, and Natural-Gas-Liquids:"
January - December, 1973 and Final Summary, 1972
Motor Gasolines, Winter 1972-1973 and Summer 1973
Aviation Turbine Fuels, 1973
Diesel Fuel Oils, 1973
Bunker Fuel Oils, 1973
Ethyl Corporation
"Yearly Report of Gasoline Sales by States - 1972"
Oil and Gas Journal (Petroleum Publishing Company)
"1973-74 Worldwide Refining and Gas Processing Directory"
"Forecast Review - Here's Where the Big Reserves Are In U. S. "
January 28, 1974
"Where District 5 Now Gets Crude, Products"
March 18, 1974
226
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(I l< asc rcail InUradi'iin 'en n'ir
c\>ini'trt»i£)
i REPORT NO. 2. I
EPA-600/3-75-010h
.1. TITIE ANOSUBTITLE
ANNUAL CATALYST RESEARCH PROGRAM REPORT
Appendices, Volume I ..
7. AUTHOR(S) «
Criteria and Special Studies Office
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Health Effects Research Laboratory
Office of Research & Development
U.S. Environmental Protection Agency
Research Triangle Park, N.C. 27711
17. SPONSORING AOENCV NAME AND ADDRESS
Same as above
1. H6CIPIKNTT' ACCESSION-NO.
5. REPORT DATE
September 1975
6. PERFORMING ORGANIZATION "f
0. PE/VORMING ORGANIZE f.ON RE '' '
10. PROGRAM ELEMEN r NO.
1AA002
11. CONTRACT/GRANT NO. |
13. TYPE OF RE PORT AND PERIOD CO VERCD
Annual Program Status 1/74-9/7
14. SPONSORING AGENCY CODE
EPA-ORD
1!>. SUPPLEMENTARY NOTES
This is the Summary Report of a set (9 volumes plus Summary).
See EPA-600/3-75-010a and niOc throuqh OlO.i. Report to Congress.
16. ABSTRACT
This report constitutes the first Annual Report of the ORU Catalyst Research
Program required by the Administrator as noted in his testimony before the
Senate PUblic Works Committee on November 6, 1973. It includes all research
aspects of this broad multi-disciplinary program including: emissions charac-
terization, measurement method development, monitoring, fuels analysis,
toxicology, biology, epidemiology, human studies, and unregulated emissions
control options. Principal focus is upon catalyst-generated sulfuric acid
and noble metal particulate emissions.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
Catalytic converters
Sulfuric' acid
Desulfurization
Catalysts
Sul fates
Sulfur
Hr .1th
li. IDENTIFIERS/OPEN ENDED TERMS
Automotive emissions
Unregulated automotive
emissions
Health effects (public)'
C. COSATI I i
'I. Ol' UOUriON STATEMENT
Available to public
19. SECURITY CLASS ( /)«.» llrport)
21. NO. OF PAGES
232
Unclassified
72. PRICE
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