CORPORATION
ENERGY PENALTIES ASSOCIATED
WITH ENVIRONMENTAL REGULATIONS
IN PETROLEUM REFINING
VOLUME I: DISCUSSION
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325R78OO1
CORPORATION
Radian Project No. 100-134-02-04
EPA Project No. 68-01-4128-2
ENERGY PENALTIES ASSOCIATED
WITH ENVIRONMENTAL REGULATIONS
IN PETROLEUM REFINING
VOLUME I: DISCUSSION
April 1978
Presented to:
ENVIRONMENTAL PROTECTION AGENCY
Policy Planning Division
Washington, D.C.
EPA Project Officer: Robert H. Fuhrman
Prepared by:
J. D. Colley
G. E. Harris
W. R. Phillips
W. C. Micheletti
8500 Shoal Creek Blvd./P.O. Box 9948/Austin, Texas 78766/(512)454-4797
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ABSTRACT
This study was completed to provide the Environmental
Protection Agency with estimates of the energy penalties which
result from compliance by the petroleum refining industry with
federally enforceable environmental regulations. Energy con-
sumption and production capacity for the industry are estimated
for the baseline year of 1974. Projections of the energy con-
sumption and production of the industry are reported for the years
1980 and 1985 by using growth estimate models. Energy penalties
for the baseline year 1974, as-well as 1980 and 1985, are pre-
sented in summary form in the Discussion Volume and in detail in
the Appendices. The total penalties are compared with estimates
of the potential energy savings at refineries due to conservation
modifications. A general description of the petroleum refining
industry is given in the Discussion Volume.
The overall report is presented in two volumes.
Volume I, the Discussion, presents the objectives, the industry
description, the energy penalty calculation methodology, and
the results of the study. Volume II, the Appendices, presents
the industry energy consumption, production capacity, regu-
latory scenarios, control strategies, and energy penalties for
the three study years 1974, 1980, and 1985.
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TABLE OF CONTENTS
Page
Abstract i
List of Figures and Tables ...... vii
List of Abbreviations viii
1.0 EXECUTIVE SUMMARY 1
1.1 Results 1
1. 2 Conclusions 4
1. 3 Recommendations 5
2.0 INTRODUCTION 6
3. 0 INDUSTRY DESCRIPTION 8
3. 1 Major Manufacturing Processes 8
3.1.1 Petroleum Separation Processes 8
3.1.1.1 Atmospheric Distillation... 10
3.1.1.2 Vacuum Distillation 11
3.1.1.3 Light Ends Recovery 11
3.1.2 Petroleum Conversion Processes 12
3.1.2.1 Catalytic Cracking 12
3.1.2.2 Hydrocracking 14
3.1.2.3 Thermal Cracking 14
3.1.2.4 Catalytic Reforming 15
3.1.2.5 Alkylation 17
3.1.2.6 Isomerization 17
3.1.2.7 Polymerization 18
3.1.3 Petroleum Treating Processes 18
3.1.3.1 Hydrotreating 18
3.1.3.2 Sweetening 19
3.1.3.3 Acid Gas Removal 20
3.1.3.4 Crude Desalting 20
3.1.3.5 Acid/Caustic Treatment 21
3.1.3.6 Solvent Treating 21
3.1.3.7 Deasphalting 22
3.1.3.8 Aromatics Extraction 22
ii
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TABLE OF CONTENTS (Cont'd)
Page
3.1.3.9 Dewaxing/Deoiling 23
3.1. 3.10 Asphalt Blowing 23
3.1.4 Feedstock and Product Handling 24
3.1.4.1 Storage 24
3.1.4.2 Blending 24
3.1.4.3 Loading and Unloading 25
3.1.5 Auxiliary Facilities 25
3.1.5.1 Sour Water Strippers 25
3.1.5.2 Wastewater Treatment
Plant 26
3.1.5.3 Cooling Towers 27
3.1.5.4 Utilities Plant 27
3.1.5.5 Sulfur Recovery Plant 28
3.1.5.6 Hydrogen Plant 28
3.1.5.7 Slowdown System 29
3.1.5.8 Process Heaters 29
3.2 Typical Energy Requirements 30
3.3 Status and Geographic Distribution
for Base Year 30
3.4 Prospects for Growth Through 1985 33
4.0 INDUSTRY GROWTH PROJECTION METHODOLOGY 35
4.1 Sector and Subsector Definitions 35
4.2 Sources of Data 35
4.3 Industry Growth Models 36
4. 4 Maj or Assumptions 44
4. 5 Caveats and Limitations 45
5.0 BASELINE ENERGY CONSUMPTION METHODOLOGY 47
5.1 Calculation of Process Requirements 47
111
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TABLE OF CONTENTS (Cont'd)
Page
5 . 2 Allocation Among Fuel Types 49
5.3 Regionalization 50
5 . 4 Proj ected Changes Through 1985 50
5 . 5 Caveats and Limitations 51
6. 0 ENERGY PENALTY METHODOLOGY 53
6.1 Identification of Major Environmental
Regulations and Standards 53
6.1.1 Particulate Regulations 54
6.1.2 . Sulfur Dioxide Regulations 55
6.1.3 Nitrogen Oxides Regulation 56
6.1.4 Carbon Monoxide Regulations 57
6.1.5 Hydrocarbon Regulations 58
6.1.6 Lead Regulations 59
6.1.7 Water Regulations ." 60
6 . 2 Control Strategies 61
6.2.1 Particulates 61
6.2.2 Sulfur Dioxide 68
6.2.3 Nitrogen Oxides Control Strategies... 70
6.2.4 Hydrocarbon Control Strategies 71
6.2.5 Lead Control Strategies 73
6.2.6 Water Control Strategies 77
6.3 Engineering Calculation Methodology 78
6.3.1 Particulates 78
6.3.2 Sulfur Dioxide ' 79
6.3.3 NOX - Engineering Calculation
Methodology 82
6.3.4 Hydrocarbon-Engineering
Calculation Methodology 83
6.3.5 Lead-Engineering Calculation
Methodology 84
IV
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TABLE OF CONTENTS (Cont'd)
Page
6.3.6 Water-Engineering Calculation
Methodology 92
6.4 Regionalization 95
6. 5 Allocation Among Fuel Types 95
7.0 SUMMARY OF RESULTS 97
7 .1 Minimum Energy Penalty Case 97
7 . 2 Maximum Energy Penalty Case 99
7.3 Most Likely Energy Penalty Case 99
8.0 SECONDARY IMPACT INDICATORS 100
8.1 Particulate Secondary Impact Indicators.... 103
8.2 Sulfur Dioxide Secondary Impact Indicators. 104
8.3 NO^ Secondary Impact Indicators 105
8.4 Hydrocarbon Secondary Impact Indicators.... 105
8.5 Lead Secondary Impact Indicators 106
8.6 Water Secondary Impact Indicators 107
9.0 DISCUSSION. 108
9.1 Possible Changes in the Refining
Industry Makeup 108
9.2 Possible Changes in Environmental
Regulations 109
9.3 Possible Changes in Control Methods 110
9.3.1 Particulates Control Changes Ill
9.3.2 S02 Control Changes Ill
9.3.3 N0x Control Changes Ill
9.3.4 Hydrocarbon Control Changes 112
9.3.5 Lead Control Changes 112
9.3.6 Water Control Changes 112
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TABLE OF CONTENTS (Cont'd)
Page
10. 0 CONCLUSIONS AND RECOMMENDATIONS 113
10.1 Conclusions 113
10.2 Refinery Conservation Opportunities 114
10 . 3 Recommendations 115
BIBLIOGRAPHY 117
VI
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LIST OF FIGURES
Number Page
3.1-1 Schematic of a Typical Integrated
Petroleum Refinery 9
6.2-1 Reformer Yield/Severity Relationship 75
6.3-1 Gasoline Consumption by Grades 93
LIST OF TABLES
3.2-1 Typical Energy Requirements of Basic Processes.. 31
~3.3-l Summary of the 10 Largest Refineries 32
4.2-1 Announced Refining Expansion Plans, 1976 37
4.3-1 Summary of Crude Oil Demand Projections 42
5.1-1 Baseline Energy Consumption 48
6.2-1 Summary of Control Strategies 62
6.3-1 Typical Energy Requirements for Pollution
Control Equipment 80
6.3-2 A. D. L.'s L. P. Model Results - Processing
and Variable Outputs 86
6.3-3 A. D. L.'s L. P. Model Results - Gasoline
Blending 87
6.3-4 Utility Requirements 90
7.1-1 Minimum Energy Penalties 98
7.2-1 Maximum Energy Penalties for 1980 and 1985 100
7.3-1 Most Likely Energy Penalties for 1980 and 1985.. 101
8.2-1 Chemical and Catalyst Requirements for
SO 2 Control 105
10.2-1 Example Refinery Energy Consumption Breakdown... 114
VI1
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LIST OF ABBREVIATIONS
AQCR - Air Quality Control Region
bbl - barrel
BOM - Bureau of Mines
BOD - biological oxygen demand
BPD - barrels per day
G! - methane
C2 - ethane
C^ - ethylene
C3 - propane
C7 - propylene
iCiv - normal butane
(\ - butylene
Cs - light naphtha
cc - cubic centimeter
CD - calendar day
COB - carbon monoxide boiler
CRU - catalytic reformer unit
DFA - direct flame afterburner
dscf - dry standard cubic foot
ESP - electrostatic precipitator
FCCU - fluid (fluidized-bed) catalytic cracking unit
FEA - Federal Energy Administration
HDS - hydrodesulfurization
Heavy S.R. Gasoline - heavy straight run gasoline
viii
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LIST OF ABBREVIATIONS (Cont'd)
HTR - high temperature regeneration
Light S.R. Gasoline - light straight run gasoline
LP - linear programming
LPG - liquefied petroleum gas
LV% - liquid volume percent
M - thousand
MIC - multiple internal cyclones
MM - million
MMT - methylcyclopentadienyl manganese tricarbonyl
NSPS - New Source Performance Standards
P - process weight
PAD - Petroleum Administration for Defense
ppm - parts per million (parts)
psia - pounds per square inch absolute
psig - pounds per square inch gauge
RACT - reasonable available control technology
RON - research octane number
scf - standard cubic feet
scftn - standard cubic feet per minute
SIP - State Implementation Plan
TCC - moving-bed catalytic cracking
USG - U.S. gallon
y - micron
IX
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1.0 EXECUTIVE SUMMARY
This report is one part of a larger study to examine
the energy penalties which result from environmental regulations
applicable to selected industries. The particular industry
examined in this report is petroleum refining. This section
summarizes the results of the refining industry study and pre-
sents the conclusions which were drawn from these results. Also,
recommendations for areas of further work are listed.
1.1 Results
The results presented in this section are based on the
data given in Appendix B. The data in Appendix B were obtained
from calculations based on information which came primarily from
articles, journals, government publications, and published reports
Since the exact regulatory atmosphere for the years 1980 and
1985 is unknown, the results for these years are presented in
three cases. The minimum, maximum, and most likely energy
penalties for each of these years are calculated. This shows
the relative impact of regulatory stringency on the energy penal-
ties. The results of this report are listed below:
The 1974 average baseline energy con-
sumption for the petroleum refining
industry was 8.16 x 1012 Btu1 per day
or approximately 669,000 Btu per barrel
of crude charged.
1A. table of conversion factors for English to metric units is
presented following Section 10.0.
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The 1974 energy penalty due to
environmental regulations , excluding
CO controls, was 0.11 x 1012 Btu per
day or approximately 9000 Btu per
barrel of crude charged. This
represents about 1.3 percent of the
energy required to process a barrel
of crude. CO controls were excluded
because they were not required by
regulation in 1974.
The 1980 average baseline energy
consumption for refining is projected
to be 1.16 x 1012 Btu per day or
636,000 Btu per barrel of crude
charged.
The 1980 minimum energy penalty due
to environmental regulations is
estimated to be 0.51 x 1012 Btu
per day or about 27,800 Btu per barrel
of crude charged. This represents
about 4.4 percent of the energy
required to process a barrel of
crude oil.
The 1980 maximum energy penalty due
to environmental regulations is
estimated to be 1.63 x 1012 Btu
per day or about 89,200 Btu per barrel
of crude charged. This represents
about 14.0 percent of the energy
required to process a barrel of
crude oil.
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The 1980 "most likely" energy penalty
due to environmental regulations is
estimated to be 0.89 x 1012 Btu per
day or about 48,600 Btu per barrel of
crude charged. This is equal to about
7.6 percent of the energy needed to refine
a barrel of crude oil.
The 1985 minimum energy penalty due
to environmental regulations is estimated
to be 0.75 x 1012 Btu per day or about
33,800 Btu per barrel of crude charged.
This is equal to about 5.5 percent of
the energy used to refine a barrel of
crude oil.
The 1985 maximum energy penalty due to
environmental regulations is estimated
to be 2.25 x 1012 Btu per day or about
101,200 Btu per barrel of crude charged.
This is equal to approximately 16.8 percent
of the energy used to refine a barrel of
crude oil.
The 1985 "most likely" energy penalty due
to environmental regulations is estimated
to be 1.33 x 1012 Btu per day or about
44,300 Btu per barrel of crude charged.
This is equal to about 9.9 percent of
the energy needed to refine a barrel of
crude oil.
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1.2 Conclusions
Some conclusions which may be drawn based upon the
results of this study are:
For 1980 the largest contributors to
the total "most likely" energy penalty
are S02 control and gasoline lead
reduction. They contribute 42 percent
and 41 percent of the total, respectively.
For 1985 the largest contributors to the
total "most likely" energy penalty are S02
control and gasoline lead reduction, again.
They contribute 37 percent and 50 percent
of the total, respectively.
Regulatory stringency has a significant
effect on the energy penalties for the
petroleum refining industry. The maximum
case total energy penalties for 1980 and
1985 are about 3 times larger than the
minimum case penalties for the same years.
The reported energy conservation potential
for the petroleum refining industry for
1980 and 1985 is roughly equivalent to
the "most likely" energy penalties
estimated for the refining industry for
1980 and 1985.
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1.3 Recommendations
It is recommended that further work be done in the
area of obtaining more accurate information on existing and pro-
jected pollution control equipment for the petroleum refining
industry. The primary sources of information for this report
were articles, journals, and reports published by governmental
agencies and the refining industry. The accuracy of the results
of this study could be improved if a survey were completed of the
petroleum refining industry's current and projected pollution
abatement inventory.
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2.0 INTRODUCTION
Regulations issued by federal and local governments
and other empowered authorities pursuant to the Clean Air Act
and the Federal Water Pollution Control Act have impacted many
industries. This report is one part of a larger study to
examine the energy requirements or penalties resulting from
compliance by specific industries with these federally enforce-
able environmental regulations. This penalty is defined as the
incremental demand for energy above a baseline demand that
would occur in the absence of any federally enforceable
environmental regulations. The study encompasses the 1974-1985
time frame with outputs provided for the years 1974, 1980, arid
1985. The petroleum refining industry is examined in this report
and the methodology for calculating the energy penalties as
well as the results of the calculations are presented in this
volume.
The methodology used to calculate the energy penalties
for the chosen years involved three phases. The objective of
the first phase was to project the growth in capacity for the
refining industry from 1974 to 1985. The objective of the
second phase was to establish the refining industry energy
consumption for the chosen baseline year of 1974. The objective
of the third phase was to calculate the energy penalties for
the refining industry for the years 1974, 1980,- and 1985.
Documentation of the refining industry growth pro-
jection is presented in Section 4.0. The total estimated
capacity for the industry for 1980 and 1985 is given as well
as the geographical distribution and the size of each expansion.
The models and major assumptions used in making the projections
are also discussed. The resulting projections provide a basis
from which the 1980 and 1985 energy penalties are calculated.
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The methodology used to determine the refining industry
energy consumption for the baseline year of 1974 is presented
in Section 5.0. The energy requirements are organized by census
region and expressed according to the types of fuels actually
used. The energy consumption due to existing environmental
controls is estimated and the baseline consumption numbers
adjusted to determine a true baseline "no environmental controls"
energy requirement.
Section 6.0 describes the methodology used to estimate
the energy penalties for the industry for the years 1980 and
1985. The environmental regulations which impact the refining
industry are analyzed first. Then the various environmental
control strategies available to the industry to achieve com-
pliance with the regulations are reviewed. Finally, the calcu-
lations which were used to estimate the energy penalties for
each census region and year are described. Section 7.0 presents
a summary of the results of the energy penalty calculations.
In addition to calculating the energy penalties,
secondary impact indicators were also specified. Secondary impact
indicators are defined as the control equipment used and the
materials consumed during the operation of a control system.
Section 8.0 describes how these indicators were determined for
the study.
Section 3.0 presents a general description of the '
petroleum refining industry. It is intended to serve as back-
ground information for the study.
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3.0 INDUSTRY DESCRIPTION
3.1 Major Manufacturing Processes
The petroleum refining industry is primarily involved
in the conversion of crude oil into more than 2500 refined prod-
ucts including liquified petroleum gas, gasoline, kerosene,
aviation fuel, diesel fuel, fuel oils, lubricating oils, and
feedstocks for the petrochemical industry. Petroleum refinery
activities start with crude storage at the refinery, include
all petroleum handling and refining operations, and terminate
with storage of the refined products at the refinery.
The petroleum refining industry employs a wide variety
of processes for the conversion of crude oil to finished petro-
leum products. A refinery's processing flow scheme selection is
largely determined by the composition of the crude oil feedstock
and the chosen slate of petroleum products. The example refinery
flow scheme presented in Figure 3.1-1 shows the general process-
ing arrangement used by U.S. refineries for major refinery pro-
cesses. The arrangement of these processes will vary among
refineries and few, if any, refineries employ all of these
processes.
In general, refinery processes and operations can be
divided into five categories: separation processes, conversion
processes, treating processes, product handling, and auxiliary
facilities. The processes comprising each of these categories
are presented in the following sections.
3.1.1 Petroleum Separation Processes
The first phase in petroleum refining operations is
the separation of crude oil into its major constituents using
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TO HEAVY HYOnOCAHBON
STORAGE ft BLENDMO
TO UOOLE DISTLLATE
STORAGE A OLENOMO
TO GASOtME 1 PETROCHEUICA1
STORAGE 1 BLErtt>IMG
Figure 3.1-1. Schematic of a Typical Integrated Petroleum Refinery
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three petroleum separation processes: atmospheric distillation,
vacuum distillation, and light ends recovery. Crude oil con-
sists of a mixture of hydrocarbon compounds including paraffinic,
naphthenic, and aromatic hydrocarbons plus small amounts of im-
purities including sulfur, nitrogen, oxygen, and metals. Refinery
separation processes use distillation, stripping, and absorption
to separate these crude oil constituents into common boiling
point fractions.
3.1.1.1 Atmospheric Distillation
The atmospheric distillation process is used to sepa-
rate crude oil into a light ends fraction, several intermediate
boiling fractions, and a topped crude fraction. The light ends
fraction contains a wide range of low boiling components which
are separated further in the light ends recovery process. The
topped crude fraction contains a wide range of high boiling com-
ponents which are separated further in the vacuum distillation
process.
Crude oil entering the atmospheric distillation unit
is heated in a process heater, often termed a pipe still, to
temperatures of 650°F to 750°F. The heated crude oil is flashed
into a multi-tray distillation column operating in the pressure
range of 10 psig. In the distillation column the crude oil com-
ponents are separated by vaporization and condensation into com-
mon boiling point fractions. To aid the separation efficiency
-of the column, stripping .stream is normally injected into the
bottom of the column and side stream fractions are passed through
side stream steam strippers. Occasionally, reboilers are used
instead of steam strippers. Standard petroleum fractions with-
drawn from the atmospheric distillation column include light
ends, naphtha, kerosene, gas oil, and topped crude. These side
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streams are withdrawn from the distillation column at tempera-
tures ranging from 200°F to 800°F.
3.1.1.2 Vacuum Distillation
Topped crude withdrawn from the bottom of the atmos-
pheric distillation column is composed of high boiling point
hydrocarbons which may crack and polymerize before evaporating
at atmospheric pressures. In order to further separate topped
crude into components, it must be distilled in a vacuum distil-
lation column at a very low pressure and in a steam atmosphere.
In the vacuum distillation unit topped crude is heated
with a process heater to temperatures ranging from 700°F to
800°F. The heated topped crude is flashed into a multi-tray
vacuum distillation column operating at a vacuum of 0.5 psia to
2 psia. In the vacuum column the topped crude is separated into
common boiling point fractions by vaporization and condensation.
Stripping steam is normally injected into the bottom of the
vacuum distillation column to assist in the separation by lower-
ing the effective partial pressures of the components. Standard
petroleum fractions withdrawn from the vacuum distillation column
include lube distillates, vacuum gas oils, asphalt stocks, and
residual oils. The vacuum in the vacuum distillation column
is normally maintained by the use of steam ejectors and baro-
metric or surface condensers, but may be maintained by the use
of vacuum pumps.
3.1.1.3 Light Ends Recovery
Refinery gas streams from the atmospheric distillation
unit and those streams produced as by-products in many other pro-
cessing units are separated into major components in a light
ends recovery unit.
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Gas separation in the light ends recovery unit is
generally accomplished by a combination of absorption and/or
distillation processes. The degree of separation required dic-
tates the processes used. Gross separations might include three
major cuts: fuel gas (Ci , C2 , C3), LPG (C3 , CO, and light
naphtha (Cs+) . R.ef ined separations are becoming more common and
may involve separation of the light ends into individual hydro-
carbon species: Ci, C2, Ci (ethylene), C3, Cl (propylene), id*
(isobutane), C^ (butylene), C5+. The temperatures normally used
in light ends processing range from cryogenic to moderate and
the pressures normally used range from atmospheric to 400 psia.
3.1.2 Petroleum Conversion Processes
Product demand and economic considerations require
that less valuable components of crude oil be converted to more
valuable products by cracking, reforming and alkylation pro-
cesses. To meet the demands for high octane gasoline, jet fuel,
and diesel fuel, the surplus residual and fuel oil components
of a barrel of crude oil can be converted economically to gaso-
line and lighter fractions, maximizing refinery profits. In
addition, waste disposal is very expensive and all components of
crude oil must be converted to salable products.
3.1.2.1 Catalytic Cracking
Catalytic cracking, using heat, pressure, and catalysts,
converts heavy oils into lighter products with product distribu-
tions favoring the more valuable gasoline and distillate blending
components. Feedstocks are usually gas oils from atmospheric and
vacuum distillations, coking and deasphalting. They typically
have a boiling range of 400°F to 1000°F. All of the catalytic
cracking processes in use today can be classified as fluidized-
bed or moving-bed units, except for hydrocracking, which is
discussed in the next section.
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Fluidized-bed Catalytic Cracking (FCC) - The FCC
process, catalyst beads O 0.5 cm) flow by gravity into the top
act as a fluid when aerated with a vapor. Fresh feed is pre-
heated in a process heater, and introduced into the bottom of a
vertical transfer line or riser, with hot regenerated catalyst.
The hot catalyst vaporizes the feed bringing it to the desired
reaction temperature (880°F to 980°F). The high activity of
modern catalysts causes most of the cracking reactions to take
place in the riser as the catalyst and oil mixture flow upward
into the reactor. The hydrocarbon vapors are separated from the
catalyst particles by cyclones in the reactor. The reaction
products are sent to a fractionator for separation.
The spent catalyst falls to the bottom of the reactor
and is steam stripped as it exits the reactor to remove adsorbed
hydrocarbons. In the regenerator coke deposited on the catalyst
as a result of the cracking reactions is burned off in a con-
trolled combustion process with preheated air. Regenerator
temperature is usually 1100°F to 1250°F. The catalyst is then
recycled to be mixed with fresh hydrocarbon feed.
Moving-bed Catalytic Cracking (TCC) - In the TCC
process, catalyst beads (^-0.5 cm) flow by gravity into the top
of the reactor where they contact a mixed phase hydrocarbon feed.
Cracking reactions take place as the catalyst and hydrocarbons
move concurrently downward through the reactor to a zone where
the catalyst is separated from the vapors. The gaseous reaction
products flow out of the reactor to the fractionation section.
The catalyst is steam stripped to remove any absorbed hydrocar-
bons. It then falls into the regenerator where coke is burned
from the catalyst with air. The regenerated catalyst is sepa-
rated from the flue gases and pneumatically or mechanically
recycled to be mixed with fresh hydrocarbon feed. The operating
temperatures of the reactor and regenerator in the TCC process
are comparable to those in the FCC process.
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3.1.2.2 Hydrocracking
Hydrocracking catalytically converts heavy feedstocks
into lighter saturated hydrocarbon fractions through cracking
and hydrogenation under severe conditions (500°F to 950°F, 1000
to 2000 psig) in the presence of hydrogen. Hydrocracking is
generally a supplementary process to catalytic cracking and can
crack heavier feedstocks such as cycle oils and coker distillates
In addition, residual fuel oils and reduced crudes can be hydro-
cracked but require a different technology.
In a typical two-stage system fresh feed is mixed
with recycle and make-up hydrogen and preheated in a process
heater before entering the first of two fixed-bed reactors. The
hydrotreated and partially hydrocracked reactor effluent goes
through heat exchangers to a high pressure separator where hydro-
gen-rich gas is flashed and recycled. The liquid effluent goes
to a low pressure separator where part of the light ends are
removed, and then to a fractionator where gasoline and lighter
products are taken overhead. The bottoms stream is mixed with
hydrogen recycle, reheated, and sent to the second reactor. The
second reactor product is sent through separators and combined
with the liquid effluent from the first reactor as feed to the
fractionator.
3.1.2.3 Thermal Cracking
Visbreaking and Coking are thermal cracking processes
which break heavy oil molecules by exposing them to high tempera-
tures .
Visbreaking - Topped crude or vacuum residuals are
thermally cracked under mild conditions (850°F to 900°F, 50 to
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250 psig) in the visbreaker furnace, reducing the viscosity or
pour point of the charge. The feed is heated and thermally cracked
in the visbreaker furnace. The cracked products are quenched
with gas oil and flashed into a fractionator. The vapor over-
head is separated into light distillate products. A heavy
distillate recovered from the liquid can be used as a fuel oil
blending component or used as catalytic cracking feed. The
residue is usually used as coker feed.
Coking - Coking is a thermal cracking process
which is used to minimize yields of residual fuel oil. Vacuum
residuals and thermal tars are cracked at high temperature and
low pressure. Products are coke, gas oils and lighter petroleum
stocks.
In the delayed coking process, heated charge stock is
fed into the bottom section of a fractionator where light ends
are stripped from the feed. The remaining feed is combined with
recycle from the coke drum and is rapidly heated in the coking
heater to a temperature of 900°F to 1100°F.
Steam injection is used to control heater velocities.
The vapor-liquid leaves the heater, passing to a coke drum where,
with controlled residence time, pressure (25 to 30 psig), and
temperature (750°F), coke is formed. Vapors from the top of the
drum return to the fractionator where the thermal cracking prod-
ucts are recovered.
3.1.2.4 Catalytic Reforming
Catalytic reforming converts low octane naphthas into
high octane gasoline blending components through isomerization,
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cyclization, and dehydrogenation. The feedstock normally in-
cludes heavy, straight-run gasolines and naphthas with a typical
boiling range of 180°F to 375°F.
Reforming processes are continuous, cyclic or semi-
regenerative depending upon the frequency of catalyst regenera-
tion.
In the continuous process small amounts of
catalyst are continuously removed from the
moving bed reactor and regenerated in a sep-
arate unit that maintains high catalyst activities
The cyclic process employs fixed-bed reactors
and is characterized by having one reactor in
addition to those on-stream. When catalyst
activity in a reactor drops below the desired
level, it is replaced by the extra reactor
and regenerated without interruption of the
process.
The semi-regenerative process employs fixed-
bed reactors which operate continuously until
the catalyst activity level is unacceptable.
No extra reactor is present and thus regenera-
tion requires process interruption. The unit
is taken off-stream, blocked out, and the
catalyst is regenerated in situ.
In a typical reforming process the feedstock and re-
cycle hydrogen mixture are preheated to reaction temperature
(900°F) by a combination of heat exchangers and a furnace.
Hydrogen is present to inhibit coke formation on the catalyst.
The reaction pressure is 100-450 psig. The preheated reactants
-16-
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enter a series of alternate reactors and furnaces. The furnaces
are necessary to reheat the reactor products after the highly
endothermic dehydrogenation reactions. Usually three reactors
are sufficient and the effluent from the final reactor is cooled
to condense liquid products. Hydrogen-rich gases are separated
from the liquid in a separator, and the liquid is fractionated
to remove light .ends. Hydrogen formed in the operation is
separated from the gas stream, recycled to the reactors, and
the excess diverted to a hydrogen collection system.
3.1.2.5 Alkylation
Alkylation units produce.a high octane component for
gasoline blending by catalytically reacting low molecular weight
olefins (e.g., ethylene,propylene, butylene, pentylene) with
isoparaffins (usually isobutane). High purity sulfuric or
hydrofluoric acid catalyzes the liquid phase reaction.
Dehydrated olefinic feed is mixed with excess iso-
butane and then contacted with the liquid catalyst in the reactor
Isobutane is added in excess to increase the octane number and
yield and to reduce side reactions and acid consumption. The
reaction products are separated into hydrocarbon and acid phases
in a settler. Acid is returned to the reactor, and the alkylate
is processed further by chemical treatment and distillation.
Alkylate is separated from the excess isobutane and from normal
butane and propane. Isobutane is returned to the reactor, while
propane and butane are removed from the process.
3.1.2.6 Isomerization
Catalytic isomerization processes are used to increase
the octane rating of light, straight-run gasoline or to produce
alkylation feedstocks from normal butane by catalytically
converting the normal paraffins to their isomers.
-17-
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The dehydrated and desulfurized feedstock is mixed
with hydrogen and an organic chloride promoter. The mixture
is then heated in a process heater to reaction temperature
(500°F). Isomerization occurs in one or two fixed-bed reactors
operating at pressures of 300 to 400 psig. A hydrogen atmosphere
is used to minimize carbon deposits on the catalyst. The ef-
fluent is cooled and charged to a separator where hydrogen-rich
gas is flashed and recycled. The liquid is then stabilized by
removing light ends and separated into normal and isoparaffin
fractions. The normal paraffins are generally recycled to the
reactor while the isoparaffins are sent to alkylation (iso-
butane) and gasoline blending (isopentane, isohexane).
3.1.2.7 P olymer i z a t ion
The polymerization unit produces a high octane component
for gasoline blending or for a petrochemical feedstock by reacting
two olefinic gases in the presence of a catalyst (usually phosphor-
ic acid). The feed can be any combination of olefinic gases and
is commonly a product of gas processing units within the refinery.
3.1.3 Petroleum Treating Processes
Petroleum treating processes stabilize products,
separate fractions for further processing, and remove objection-
able elements from petroleum products and feedstocks. Stabiliza-
tion is the conversion of olefins and diolefins to saturated
hydrocarbons. Objectionable elements removed include sulfur,
nitrogen, oxygen, halides and metals. Separation processes in-
clude aromatics extraction, deasphalting, dewaxing and deoiling.
3.1.3.1 Hydrotreating
The hydrotreating process catalytically stabilizes
petroleum products and removes objectionable elements from
-18-
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products and feedstocks by reacting them with hydrogen. Feed-
stocks range from naphtha to reduced crude. Operating conditions
also vary widely with pressures ranging from 100 to 300 psig and
reactor temperatures of 500°F to 800°F.
Oil feed is mixed with hydrogen-rich gases and heated
to the desired reactor inlet temperature. The temperature is
usually kept below 800°F to minimize cracking. Oil feed and
hydrogen enter the top of a fixed-bed reactor where they react
over a metal oxide catalyst to form hydrogen sulfide, ammonia,
saturated hydrocarbons and free metals. The effluent is cooled
and the oil is separated from the hydrogen-rich gases. The oil
is then stripped of any remaining hydrogen sulfide and light
ends. The effluent gas is treated to remove hydrogen sulfide and
recycled to the reactor. The free metals remain on the catalyst.
3.1.3.2 Sweetening
Sweetening of distillates is accomplished by the con-
version of the sulfur containing compounds to alkyl-disulfides
in the presence of a catalyst. The conversion process may be
followed by an extraction.
i
In one conversion process sulfur is added to the sour
distillate with a small amount of caustic and air. This mixture
is then passed upward through a fixed-bed catalytic reactor
countercurrent to a flow of caustic entering at the top of the
vessel. There are numerous sweetening techniques available to
refiners.
In one conversion and extraction process the sour
distillate is prewashed with caustic and then contacted with a
solution of catalyst and caustic in the extractor. The extracted
-19-
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distillate is sweetened by reacting with air, allowed to settle
and sent to inhibiting and storage. Regeneration is accomplished
by mixing caustic from the bottom of the extractor with air and
separating the disulfides and excess air.
3.1.3.3 Acid Gas Removal
Hydrogen sulfide is formed as a result of the conver-
sion of sulfur compounds in hydrotreating, cracking and coking
operations and is also present to some extent in solution in
crude oils. The acid gas removal unit removes hydrogen sulfide
from refinery gases by absorption and reaction with some regener-
able sorbent.
There are many processes for acid gas removal, but the
diethanolamine process has been most widely used. An aqueous
fifteen to thirty percent diethanolamine solution is introduced
into the top of an absorber in which it flows,countercurrently
to the refinery gas flow, selectively absorbing hydrogen sulfide
and COa. The rich solution then flows into a flash tank allowing
any entrained or dissolved methane and ethane to be separated.
The solution is preheated, and the acid gases are stripped from
the solution with steam in the regenerator. The steam is con-
densed, and the acid gases are sent to a sulfur recovery unit.
3.1.3.4 Crude Desalting
Crude desalting is usually the first processing step
in a refinery. It removes inorganic salts, water, silt and
water soluble compounds from the raw crude to prevent equipment
fouling, corrosion and catalyst poisoning in downstream units.
Water and crude are thoroughly mixed and heated. The
mixture is then demulsified. Soluble impurities are separated
-20-
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from the crude by absorption into the water phase. Phase
separation is accomplished by physical decanting and electro-
static coalescing. Surface active chemicals are sometimes added
to hasten the separation.
3.1.3.5 Acid/Caustic Treatment
Hydrocarbon streams are treated with acid to remove
aromatics, attack olefins, and dissolve resinous or asphaltic
substances and nitrogen bases. Caustic treatment is used to
remove trace sulfur compounds and is often used following acid
treatment for neutralization.
The hydrocarbon stream is contacted with the treating
agent and mixed thoroughly to form an emulsion. The emulsion
is then broken and separated into two phases by coalescence,
sometimes aided by electrostatic precipitation. The product is
a treated, stable hydrocarbon stream.
3.1.3.6 Solvent Treating
Solvent treating processes are applied primarily to
the extraction of undesirable components from lubricating oils.
They are also used to separate petroleum fractions and to remove
impurities from gas oils. Undesirable components removed include
unstable, acidic, 'organometallic, nitrogen and sulfur compounds.
Solvent and oil are contacted in a countercurrent con-
tinuous extractor. The raffinate and extract streams are steam-
stripped to produce refined oil and finished extract streams.
The solvent is separated from the oil and water by settling or
stripping and returned to the contactor.
-21-
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3.1.3.7 Deasphalting
The deasphalting process separates asphaltic materials
from heavy oil and residual fractions, recovering any oil for
use as a feed to catalytic cracking processes and producing a
faw asphaltic material.
Vacuum residuals and a mixture of liquid propane and
other light hydrocarbons are pumped to an extraction tower where
a separation based on solubility difference takes place. A
deasphalted oil solution and an asphalt solution are the pro-
ducts. These solutions are further processed through evapora-
tion and steam stripping to produce the final oil and asphalt
products and to recovery the propane solvent.
3.1.3.8 Aromatics Extraction
An aromatics extraction unit produces a high octane
gasoline blending component by liquid-liquid extraction of
aromatics from typical refinery feedstocks.
Fresh feed is charged to a contactor (extractor) for
countercurrent extraction of the aromatic components with a
solvent. The low aromatic raffinate is discharged from the top
of the column and water washed. The rich solvent is charged to
an extractive stripper where the hydrocarbon overhead is returned
as reflux to the extractor. The bottoms are charged to the re-
covery column where a solvent-free aromatic extract is separated.
The lean solvent is returned to the extractor. In many units
the extractive stripper and the recovery column are combined.
In this case, the high purity aromatics are withdrawn as a side-
stream and made solvent-free by water washing.
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3.1.3.9 Dewaxing/Deo i1ing
Dewaxing/Deoiling units separate waxy materials from
various lube oil fractions to produce low pour point lubricating
oils and wax.
The oil and solvent are mixed and chilled at a con-
trolled rate. The resulting wax crystals are separated from
the oil and solvent by rotary drum filtration. The wax is then
washed and sent to a solvent recovery system. The oil and sol-
vent filtrate is sent to a similar solvent recovery system. It
may consist of evaporators or of high and low pressure flashes,
depending on the solvent used. The evaporation or flashing steps
are followed by steam stripping.
3.1.3.10 Asphalt Blowing
The asphalt blowing process oxidizes asphaltic residual
oils, increasing their melting temperature and hardness to achieve
an increased resistance to weathering.
The oils containing a large quantity of polycyclic
aromatic compounds (asphaltic oils) are oxidized by blowing
heated air through a preheated batch mixture or, in the contin-
uous process, by passing hot air countercurrent to the oil flow.
The reaction is exothermic, and quench steam is sometimes needed
for temperature control. In some cases ferric chloride or
phosphorus pentoxide is used as a catalyst to increase the re-
action rate and impart special characteristics to the asphalt.
Blowing is stopped when the asphalt reaches the desired penetra-
tion specifications.
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3.1.4 Feedstock and Product Handling
The refinery feedstock and product handling operations
consist of storage, blending, and unloading activities. All
feedstocks entering the refinery and all products leaving the
refinery are subject to the refinery handling operations.
3.1.4.1 Storage
All refineries have a feedstock and product storage
area, termed a "tank farm", which provides surge storage capacity
to insure smooth, uninterrupted refinery operations. Individual
storage tank capacities range from less than 1000 barrels to
more than 250,000 barrels, and total tank farm storage capacities
commonly range from several days to several weeks refinery supply,
The most common types of storage tanks used by refineries include
fixed roof tanks, floating roof tanks, internal floating roof
tanks, variable vapor space tanks and pressure tanks. New source
performance standards require that hydrocarbon liquids with true
vapor pressures ranging from 1.5 to 11.1 psia be stored in float-
ing roof tanks or equivalent vapor controls and that hydrocarbon
liquids with true vapor pressures in excess of 11.1 psia be
stored in storage tanks with vapor recovery systems or with
equivalent vapor controls.
3.1.4.2 Blending
Most fuel products from petroleum refineries are a
selective blend of several refinery product streams mixed to
yield specific fuel characteristics. Some of the characteris-
tics affected by blending are volatility, octane rating, cetane
rating, flash point, sulfur level, pour point, and ash content.
Typical blended fuels include gasoline, diesel oil, kerosene,
distillate fuel oils, and residual fuel oils.
-24-
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The blending of refinery products is performed by mixing
products from various product storage tanks in a blending mani-
fold. After blending, the fuels may either be sotred in a
blended product storage tank or put directly into pipelines.
3.1.4.3 Loading and Unloading
Although most refinery feedstocks and products are
transported by pipeline, many feedstocks and products are trans-
ported by trucks, rail cars, and marine vessels. The refinery
feedstocks and products are transferred to and from these trans-
port vehicles in the refinery tank farm area using specialized
pumps and piping systems.
3.1.5 Auxiliary Facilities
Auxiliary facilities include a wide assortment of
processes and equipment which are not directly involved in the
refining of crude oil, but which perform functions vital to the
operation of the refinery. Products from auxiliary facilities
(clean water, steam, process heat, etc.) are required by the
majority of refinery process units and are not limited to any
one part of the refinery.
3.1.5.1 Sour Water Strippers
Sour water strippers remove hydrogen sulfide (H2S) and
ammonia (NH3) from sour water condensate streams generated by
such refinery processes as hydrotreating, hydrodesulfurization,
tail gas treating, and catalytic cracking.
The feed streams going to sour water strippers are
refinery condensates having HaS concentrations up to 6,000 ppm,
NH3 concentrations up to 4,000 ppm, and phenol concentrations up
-25-
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to 600 ppm. If the H2S and NH3 are to be removed as a single
.stream, the sour water is fed into a single stripping column
which distills H2S, NH3 , and some phenols into the column over-
head and discharges treated water from the column bottom. If
the H2S and NH3 are to be removed as separate streams, the sour
water is fed into a series of stripping columns which separate
HaS and NH3 into individual product streams. The stripper columns
may use either direct steam stripping or steam heated reboilers
to accomplish the gas-liquid separation. A good combination
stripper can have 9970 removal of H2S and about 90 to 93% of
NH3 . The H2S rich stream or H2S-NH3 rich stream is routed to
the sulfur recovery plant. If an NH3 stream is produced, it is
treated for trace H2S removal and sold as high quality NH3 .
3.1.5.2 Wastewater Treatment Plant
All refineries employ some form of wastewater treat-
ment to upgrade the quality of water effluents such that they
can be safely returned to the environment or reused within the
refinery.
The design of wastewater treatment plants is compli-
cated by the diversity of refinery pollutants including oil,
phenols, sulfides, dissolved solids, suspended solids, toxic
chemicals, and BOD-bearing materials. Although the wastewater
treatment processes employed by refineries vary greatly, they
generally include neutralizers, oil-water separators, settling
chambers, clarifiers, dissolved air flotation systems, coagula-
tors, aerated lagoons, and activated sludge ponds. Refinery
water effluents are collected from various processing units and
conveyed through sewers and ditches to the wastewater treatment
plant. Most of the wastewater treatment processing occurs in
open ponds and tanks.
-26-
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3.1.5.3 Cooling Towers
Cooling towers are used extensively in refinery cooling
water systems to transfer heat from the cooling water to the at-
mosphere. The only refineries not employing cooling towers are
those with once through cooling. The increasing scarcity of
large water supplies required by once through cooling is con-
tributing to the disappearance of that form of refinery cooling.
In the cooling tower warm cooling water returning from
refinery processes is contacted with air by cascading through
packing. Heat in the cooling water is transferred from the
cooling water to the air by heat exchange and evaporation.
Cooling water circulation "rates for refineries commonly range
from 0.3 to 3.0 gpm per BPD of refinery capacity.
3.1.5.4 Utilities Plant
The utilities plant supplies the steam necessary for
the refinery. The steam can be used to produce electricity by
throttling through a turbine. It may also be used for heating
by direct or indirect contact with hydrocarbon streams. The
generated steam used in noncontact process heating releases its
latent heat by condensation and returns to the boiler. The
waste steam from noncontact process heating and power generation
can be used in direct contact operations as a stripping medium
or a process fluid. It may also be used to produce a vacuum, or
to drive pumps and compressors.
Steam generators or boilers are usually designed to
deliver steam above 600 psig. The steam is produced in tube
bundles which surround the combustion chamber of the boiler.
Heating of the tubes is accomplished by both radiation and con-
vection. The fuel burned may be refinery gas, natural gas, resi-
dual fuel oil or a combination, depending on the economics, operat-
ing conditions and pollution requirements.
-27-
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3.1.5.5 Sulfur Recovery Plant
Sulfur recovery plants are used in petroleum refineries
to convert hydrogen sulfide (H2S) produced in the acid gas treat-
ing unit into the more disposable by-product, elemental sulfur.
Although several other sulfur recovery processes are
available, the primary process used by petroleum refineries is
the modified Glaus process. In the modified Glaus process one-
third of the H2S in the acid gas feed is partially combusted in
a furnace to S02. After passing through a waste heat boiler, the
partially combusted acid gases pass through a series of two to
four bauxite or alumina catalyst reactors where the H2S and S02
are reacted to produce elemental sulfur and water. Molten sulfur
is collected after each reactor. After the last reactor, the
remaining portion of the acid gas stream is normally either in-
cinerated or treated in a tail gas treatment unit. In a typical,
well designed, three reactor Glaus unit, 95 to 98 percent of the
H2S in the feed gas is converted to elemental sulfur.
3.1.5.6 Hydrogen Plant
In many refineries the catalytic reforming operation
supplies the hydrogen necessary for hydrocracking and hydrotreat-
ing. If extensive hydrocracking and hydrotreating are used,
supplemental hydrogen is supplied by a hydrogen plant.
Steam reforming of light hydrocarbons (ranging from
methane to naphtha) is currently the predominant process for
hydrogen production in the United States. Steam reforming is a
catalytic operation requiring four basic steps.
First, the desulfurized feed is catalytically "re-
formed" into carbon monoxide and hydrogen by reaction with steam
-28-
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(1500°F, 125 psig). Then the carbon monoxide formed is reacted
with more steam in the catalytic shift conversion unit to pro-
duce C02 and an equivalent amount of H2 (700°F, 120 psig). The
third step is the removal of carbon dioxide by absorption (130°F)
in an amine or potassium carbonate solution. The final step is
the catalytic conversion of the remaining small quantities of CO
and C02 into methane by reaction with hydrogen (800°F, 100 psig).
The resultant hydrogen stream is moderately pure (9870+) with
generally less than 10 ppm carbon dioxide.
3.1.5.7 Slowdown System
The blowdown system provides for the safe disposal of
hydrocarbons (vapor and liquid) discharged from pressure relief
devices. Most units and equipment subject to planned or un-
planned hydrocarbon discharges are manifolded into a collection
unit, called the blowdown system.
A decreasing pressure system is used for safety and
economic reasons. By using a series of flash drums and conden-
sers arranged in decreasing pressure, the blowdown is separated
into vapor and liquid cuts. The separated liquid is recycled.
The gaseous cuts can either be smokelessly flared (steam injec-
tion) or recycled.
3.1.5.8 Process Heaters
Process heaters (furnaces) are used extensively in
re-fineries to supply the heat necessary to raise input materials
to reaction or distillation temperature. They are used in many
processes and are considered as a single process module to pre-
vent unnecessary repetition.
-29-
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Process heaters are usually designed to raise petroleum
fluid temperatures to a maximum of about 950°F. The fuel burned
may be refinery gas, natural gas, residual fuel oil or a combi-
nation, depending on the economics, operating conditions, and
pollution requirements. The process heaters for CO waste heat
boilers also use the carbon monoxide-rich regenerator flue gas
as fuel. The fuel requirement for furnaces will range between
5 and 10 percent of the heating value of the raw crude entering
the refinery.
32 Typical Energy Requriements
The petroleum refining industry is a highly energy-
intensive industry. It has been estimated that a modern U.S.
refinery will consume energy equivalent to 10 percent of the
energy contained in the raw crude oil it processes. Roughly,
this estimate can be attributed to process heaters (7.5%),
steam consumption (1.5%), and electricity (1.070) (DI-R-090) .
Typical energy requirements of the basic refining
processes are given in Table 3.2-1. Product handling operations
are not included as the energy requirements are negligible.
3.3 Status and Geographic Distribution for Base Year
As of 1 January 1974, there were 142 companies which
comprised the United States Petroleum Refining Industry. These
companies operated 247 refineries in 39 states. Table 3.3-1
lists the 10 largest refiners and the production capacity of
each along with the combined capacity of the other 169 refineries.
A complete listing of the production capacities of all 247 re-
fineries, by company, is found in Appendix C.
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TABLE 3.2-1. TYPICAL ENERGY REQUIREMENTS OF BASIC PROCESSES
Process
Petroleum Separation Processes
1. Atmospheric Distillation
2. Vacuum Distillation
3. Light Ends Recovery
Petroleum Conversion Processes
1. Catalytic Cracking
Fluid ized-bed
Moving-bed (TCC)
2. Hydrocracking
3. Thermal Cracking
Vis breaking
Coking
4. Catalytic Reforming
5. Alkylation
6. Isomerlzation
7. Polymerization
Petroleum Treating Processes
1. aydrotreating
2. Sweetening
3. Acid Gas Removal (unit/kg
removed gas)
4. Crude Desalting
5. Acid/Caustic Treatment
6. Solvent Treating
7 . Deaephalting
3. Aromatics Extraction
9. Devaxing/Deoiling
10. Asphalt Blowing
Auxiliary Facilities
1. Sour Water Strippers
2. Wastevater Treatment
3. Cooling Tovers
4. Utilities Plant
5. Sulfur Recovery (unit/
MSCF)
6. Hydrogen Plant
' 7. Bloudovn Systems
Electricity
(kwh/bbl)
0:40
0.10-0.20
2.00
Oi4.1
0.10-1.50
7.64-14.00
1.72
-
1.51
0.50-5.00
1.19
1.19
0.05-0.25
0.04
<0.01
0.01
-
1.00
0-3.18
0.30
11.93-9.07
0.95
-
kwh
°012 gTT
<0.01
4.00
-
Thermal
Energy
(Btu/bbl)
100,000
50,100
-
145,200
100,000-300,000
145,000-252,500
258,300
300,000-397,700
655,300
-
30,000-68,200
-
2,500-5,000
-
-
22,000
-
285,400
80,200-139,000
190,000
290,000-300,500
5,000-10,000
3,200
(500)
-
300,000
-
Steam
(Ib/bbl)
50
3
-
(74)'"
100 (160)
10-16
20 (100)
31 (182)
-
100-302 (Ib/bbl product)
20-25
20
0.15-0.25
-
0.28-0.56
-
-
40
30-140
2.5
40/60
-
-
(11)
-
-
'parentheses indicate production
'production from CO boiler
Source: (DI-R-090, GA-182, HY-013)
-31-
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TABLE 3.3-1. SUMMARY OF THE 10 LARGEST REFINERS
Company
Exxon
Shell
Texaco
Amoco
Standard Oil of California
Mobil
Gulf
ARCO
Union Oil
Sun Oil
All Others
Total
Number of
Refineries
5
8
12
10
12
8
8
6
4
5
169
247
Crude
Capacity
(BPD)
1,244,175
1,102,068
1,076,231
1,058,343
977,850
926,175
855,218
784,862
483,956
480,975
5,152,800
14,142,656
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Many of these companies are also involved in related
industries, such as petrochemicals, which use refinery products
as feedstocks. Petrochemical plants often border refineries to
permit an easy exchange of products. These plants often generate
by-product materials similar to refinery intermediate products
which are then sold to the refinery.
Refineries are located in 39 states with the majority
of refining capacity found near the coasts. There is consider-
able variation in the size of refineries which range from a
production rate of 3125 barrels per day (BPD) to more than
400,000 BPD.
As shown in Appendix C, many refineries have crude
capacities of less than 5,000 BPD. Economic operation of these
small refineries is generally permitted only by production of
specialty items, lube oils, or asphalts.
3.4 Prospects for Growth Through 1985
The petroleum refining industry has been expanding at
the rate of about 4 percent per year. The future rate of expan-
sion is expected to remain the same. However, in census regions
1 and 3 a much faster growth rate is expected. The increased
growth can be attributed to greater demand for petroleum products
and the anticipated success of offshore exploration along the
Atlantic Coast.
Conversely, census regions 6 and 8 display no growth
potential. This lack of expansion is predominantly the result
of geographic location. Petroleum refineries in these two
regions rely on pipeline crude for the most part. Therefore,
-33-
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the increased expense of pipeline crude coupled with declining
internal domestic oil production indicates that refinery growth
in these regions will be almost nonexistent.
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4.0 INDUSTRY GROWTH PROJECTION METHODOLOGY
The objective of this study is to determine the energy
penalty due to environmental controls over a time frame from
1974 to 1985. To accomplish this, it is necessary to predict
the growth pattern of the industry. The total capacity in 1980
and 1985 is important, of course, but the geographical distribu-
tion and the size of each expansion is also necessary to fully
define the industry.
4.1 Sector and Subsector Definitions
A close examination of the refining industry was made
to determine if the sector and subsector approach would be
beneficial. It was found that petroleum refining was sufficiently
homogeneous to be treated as a whole. If the study had been of
the entire petroleum industry, it would definitely have required
a disaggregate study of production, refining, transportation,
and marketing. Refining alone, however, does not necessitate
such an approach.
4.2 Sources of Data
The baseline production data presented in Form 2,
Appendix B, were developed from two sources. The data for 1974
were taken from the "Mineral Industry Surveys - Crude Petroleum,
Petroleum Products, and Natural Gas Liquids: 1974" issued by
the Bureau of Mines (US-575). The data for 1980 and 1985 were
based' on several economic forecasts described in more detail below.
Since the 1973-1974 oil embargo, the prediction of
energy availability and usage patterns has been the subject of
many studies. Two extensive studies were chosen since they
condensed the previous work and allowed a more efficient overview
-35-
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of available data. These were the 1976 National Energy Outlook
by the FEA (FE-153) and A Western Regional Energy Development
Study by the Stanford Research Institute (ST-381).
These sources provided a good means for estimating
the total production of the industry, but further data were
required to determine the probable geographic and size distribu-
tion of the projected growth. Industry periodicals such as the
Oil and Gas Journal and Hydrocarbon Processing were searched
for announcements of planned expansion (CA-339, HY-038). These
data were augmented by an FEA report (PE-177) and a private
communication from the EPA (WA-290). The results of this survey
of planned expansions are shown in Table 4.2-1. While these con-
struction plans were not used verbatim to project industry growth,
they were useful as a guide in allocating the new capacity
indicated by previous studies into the proper geographic and
size categories.
4.3 Industry Growth Models
While this study is concerned only with petroleum
refining, the growth models used must consider expansion in all
phases of the petroleum industry. Table 4.3 shows the various
cases developed in the two major studies cited earlier (FE-153,
ST-381). The primary variable separating these cases is the
market price of crude oil. But conservation efforts, development
of Alaskan and Outer Continental Shelf reserves, development of
alternate energy sources, and changes in government policies are
also considered. All cases are based on a healthy economy,
compatible with a steady increase in the Gross National Product
of about 3 .370 per year.
These varied cases were judged on two main criteria to
determine their applicability to this study:
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TABLE 4.2-1. ANNOUNCED REFINING EXPANSION PLANS, 1976
Company/Location
Hunt Oil (Tuscaloosa) *
Louisiana Land & Exploration (Mobile)
Marion Corp. (Theodore)2'3
Standard Oil Co. (Pascagoula) l
Tesorq-Alaskan Petr. Corp. 2'3'5
Delta Refining (Memphis)2
J&W Rfy. Co. (Tucker)2
California Oil & Purification
(Ventura) 1*3'"
Douglas Oil Co. Calif. (Paramount)1
Lundray-Thagard Oil Co. (South Gate)2'
Standard Oil Co. Calif. (El
Segundo)1'2'3'*
Standard Oil Co. Calif.
(Richmond) i'2'3'*
Standard Oil Calif. (Perth Amboy)1'2'3
Gulf Oil Co. (Philadelphia)2
Rock Island Rfy. Corp. (Indianapolis)1
Gladieux Rfy. Inc. (Ft. Wayne)2'1
Somerset Rfg. Inc. (Somerset)2'3'7
American-Petrofina (Port Arthur)2'3'1"
ECOL (Garyville)2'3
Exxon (Baton Rouge)2'3'9
Good Hope (Good Hope) "*
Gulf Oil (Port Arthur)1'2'"
Kerr-McGee (Wynnewood) l
Chatnplin Petr. Co. (Corpus
Christi)1'2'3'4'10
Sader Refining Co. (Corpus Christi)2
Sigmor (Three Rivers) 3
Three Rivers Rfy. (Three Rivers)2
Type
E
N
E
N
E
E
N
E
3,6 g
E
E.
'* E
E
'2 E
E
E
8 E
N
E
E
E
N
E
N
N
E
Stage
C
C
E
C
C
E
C
u
u
u
C
E
U
UorE
C
U
u
PAD
III
III
III
III
V
II
III
V
V
V
V
V
I
I
II
II
II
III
III
III
III
III
II
III
III
III
III
AQCR
4
5
5
5
9
18
22
24
24
24
24
3Q
43
45
80
81
105
106
106
106
106
106
188
214
214
214
214
Capacity
(BPD)
15,000
30,000
2,000
54,000
13,000
4,700
6,000
15,000
15,000
3,300
175,000
175,000
80,000
30,000
7,000
2,500
1,600
30,000
200,000
11,000
50,000
23,000
16,000
60,000
12,000
10,000
5,000
-37--
-------
TABLE 4.2-1 ANNOUNCED REFINING EXPANSION PLANS, 1976 (Continued)
Company /Location
Atlantic Richfield (Houston)1'2'3'"'11
Penzoil-United Inc. (Falling Rock)1'2
1977
Mallard Expl. Inc. (Atmor) l
Energy Co. of Alaska (Fairbanks)1'2'3'""
Midland Corp. (Gushing)3'"
California Oil Purification (Ventura)3'"
Standard Oil California (Perth Amboy) l ' z
.Shell Oil Co. (Woodriver) l
Tenneco (Chalmette) l ' 2 ' 3' " ' 1 3
Steuart Petr. Co. (Piney Point)1'21
Gulf Oil (Luling)3'"
Exxon (Baytown) l ' 2 ' 3 ' " ' ' "
1978
Odessa Rfg. Inc. (Mobile)1'"'15
Crown Central Petr. Corp.
(Baltimore)1'16 ,
Dow Chem. Co. (Freeport) 2 ' 3 '" ' l 7
Hudson Oil Rfg. (Bayport) l ' 1 B
Hampton Roads Energy Co.
(Portsmouth)2'3'"'19
Virco (St Croix)"
1979
Pittston Co. (Eastport)3'1*
Cascade Energy Resources (Rainier)"
Type
E
E
N
12 N
E
E
E
E
E
N
N
E
N
N
N,E
N
N
N
N
N
Stage
U
U
E
E
UorE
E
E
E
E
P
P
U
E
E
P
P
P
P
PAD
III
I
II
V
II
V
V
II.
Ill
I
III
III
III
I
III
III
I
I
V
AQCR
216
234
5
9
17
24
43
70
106
116
212
216
5
115
214
216
223
247
109
193
Capacity
(BPD)
93,000
40,000
7,000
25,000
16,000
15,000
30,000
30,000
30,000
100,000
30,000
250,000
120. ? 000
200 .,000
200,000
200,000
184,000
200,000
250,000
200,000
-38r
-------
TABLE 4.2-1. UNCERTAIN, UNDEFINED OR EARLY STAGES OF PLANNING
Company /Location
Wallace & Wallace (Tuskegee) 3 '"*
Odessa Rfg. Inc. (Mobile)1'"1
Tesoro-Alaskan Petr. Corp. (Kenai)1*'2
PIMA (Phoenix)3
Atlas Processing (Shreveport)1*
J&W Refining (Tucker) 3
Penzoil (Shreveport)2
Atlantic Richfield (Wilmington)1*
Newhall Rfg. (Newhall) l ' 3'"'20
Powerine Oil (Santa Fe Springs)1*'1
Macario Indep. Rfy. (Carlsbad)1*'1
Pacific Resources (San Diego) 3
Urich (Martinez)3'1*
In-O-Ven (New London) 3
Pepco (Saybrook)3
Shell (Gloucester) 3
Conoco-Dillingham Oil (Barbers Point)1*'1
HIRI (Eua Beach)1*'1
HIRI . (Ohau) 3
Texaco (Lockport) 3 ' * ' l
Clark (Hartford)3
JOC Oil (Romeville) "*
Le Gardeur Int. (Braithwaite) 3>1*
Texaco (Convent)3'1*
Gibbs Oil Co. (Sanf ord) 3 '
Crown Central Petr. (Baltimore)1'3'1*
Saber-Tex (Dracut) 3
Granite State Refs. (Rochester)3
Olympic Oil Refs. (New Market)3
United Refining (West Branch)3
Lakeside Rfg. Co. (Kalamazoo) l
Type
N
N
E
N
E
E
E
N.
E
E
N
N
N
N
N
N
N
E
E
E
E
N
N
N
N
N
N
N
N
E
E
Stage PAD
III
I
P V
V
UorE III
III
III
P V
V
E V
P V
V
V
I
I
I
E V
P V
V'
II
II
P III
III
III
I
I
I
I
I
II
U II
AQCR
2
5
8
15
22
22
22
24
24
24
29
29
30
41
42
45
60
60
60
67
70
160
106
106
110
115
119
121
121
122
125
Capacity
(BPD)
150,000
120,000
17,000
3,000
40,000
150,000
40,000
20,000
4,000
25,000
100,000
100,000
30,000
400,000
400,000
150,000
50,000
20,000
65,000
25,000
4,000
200,000
300,000
200,000
250,000
200,000
100,000
400,000
400,000
5,000
7
-39-
-------
TABLE 4.2-1 UNCERTAIN, UNDEFINED OR EARLY STAGES OF PLANNING (Continued)
Company /Location
New England Petr. (Oswego)1'4
Cir.illo Bro. (Albany)3'4
Vickers Petr. Corp. (Ardmore)
Cascade Energy Resources (Portland) l
Charter Oil (St. Helens) 4
Columbia Indep. Rfy. (Portland)3
Pacific Resources (Portland) 3
Saber Rfy. (Corpus Christi)2
Amoco (Texas City)"*
Charter Intl. (Houston)1*
Hudson Oil (Bayport)3
Phillips Co. (Sweeny) 4
Texas City Rfy. (Texas City)1*
Hampton Roads Energy Co. (Portsmouth)22
Type
N
N
E
N
N '
N
E
E
N
E
E
N
Stage PAD
I
I
U II
V
P V
P V
V
III
U III
U III
III
P III
U III
I
AQCR
158
161
188
193
193
193
193
214
216
216
216
216
216
223
Capacity
(BPD)
200,000
20,000
60,000
30,000
30-50,000
50,000
50,000
12,000
7
?
100,000
65,000
?
184,000
1 HPI: February 1976
2 OGJ: April 26, 1976
3 PE-177; Trends in Refining Capacity and Utilization; December 1975
4 EPA Listing
5 OGJ = 18,000*; FEA = 17,000 (A star will indicate the value used in this
table)
6 OGJ = 6,800; FEA = 3,300*
7 OGJ = 5,000; FEA = 1,600*
8 OGJ = 26,000; FEA = 34,000; EPA = 30,000*
9 OGJ = 11,000*; FEA = 10,000
10 OGJ = 52,000; EPA, FEA = 60,000*
11 HPI, OGJ = 95,000; FEA, EPA = 93,000*
12 HPI, OGJ = 25,000*; FEA, EPA = 15,000
13 OGJ = 35,000; HPI, FEA, EPA = 30,000*
14 OGJ, HPI = Complete in 1976; FEA, EPA = Complete in 1977*
-40-
-------
TABLE 4.2-1 ANNOUNCED REFINING EXPANSION PLANS (Continued)
i s
Uncertain on EPA listing
16 EPA, FEA listed as uncertain
17 OGJ, HPI = Complete in 1977; FEA, EPA = Complete in 1978*
1.8 FEA listed as uncertain
19 OCJ = 184,000; FEA, EPA = 175,000-; Uncertain due to opposition on
environmental grounds
20 FEA = 4,000*; EPA = 10,000
9 1
FEA listed as planned but not constructed due .to opposition on environ-
mental grounds
22 FEA listed for 1978; EPA opposed on environmental grounds (Washington
Post 4-20-76)
Type: E - Expansion
N - New
Stage: P - Planning
E - Engineering
U - Under construction
C - Completed
-41-
-------
TABLE 4.3-1 SUMMARY OF CRUDE OIL DEMAND PROJECTIONS
1980
.Petroleum Demand (UMBPD)
1985"
Source
Date
Case
I97f. - National Fob. 1976 $11/HRI. business as
Knoi"f*y Out look - MHii.il
Fedcra 1 F.norRy
Admlnlsi rat Ion
(KE-I53)
$13/linL Conservntlon
Domestic * Domestic *
Production Imports Total Production Imports_
J2.B <../, 17.2 13.9 5.9
Totnl
liases
I
-P-
K)
Sn/l>ni. accelerated
supply and conserva-
tion
$13/11111. Imported
oil - domestic oil
regulation at $7.50/
nil],
$13/11111. Imported oil
domestic oil regula-
tion at $9/nill,
511/nni. imported oil
domestic oil supply
pessimistic 9/1)01.
domestIc oil
$R/ltni. huslness ns
usiin I
$lf 1 o DC par I -
Dionl. of Inter lor .nnnnunccd least uj;
schedule, tort Inry recovery mrlh«-d*
ore moderately nppl lei), present pro-
visions of federal inx todes wbl.h
Impact crude ol1 economics ri-maln
unchanged.
17.8 Hnsc<) on the. .same nssurnpt lonn n.s the
$13/lllil. BAD case with the additional
ass t imp 11 on t hat a do, term I nod effort
wt 11 be made 1 o reduce lota I onorp.y
demand by the use of energy sav I up,
do.vl cos.
17.4 lies Ides the has I c at; si imp I. Ion?: of the
$13/11111. case, this projection nsMuraoM
an accelerated DCS leasing program,
Creator product Ion from shall* ol 1 and
tcrtlary recovery, more opt 1 mint Ic
resource csl. I ma ton , and the roii:iorva-
t Inn effort of the prev Ions r;iso.
1.*
11.3
9.4
12.6
13.5
3.3
21.2
20.9
22.2 Assumes - domestic oil regulated nl
$9/IWI,, less favorable r.enlnf.lr.il
and toe hi i tc.nl dcve lopments t linn t he
BAH case.
2/i.9 Assumes - a world oil price of $fl/IUU.
and moderate dove 1 opmrnl a.i In $ 1 \/
18.3 Ansninrn - n world oil price* of $H»/
11III. and moderate dove lopmrnt: an I n
$13/1)111. RAM.
-------
TABLE 4.3-1 SUMMARY OF CRUDE OIL DEMAND PROJECTIONS (Continued)
.Sojircc
Date
£'!?.£
A Western Region- Hoc. 1975 lllntnrlc.il Growth
al F.nerfiy Develop-
niont Study -
Stanford licr.enrr.il
niil I r.ul c (SI-.1H1)
Tcclinlcnl Fix
Nominal Case
1980
Petroleum Demand (HMIII'D)
~
Domostfc*
Production
Importn __Tqtal
_ __
Domestic*
Prodction
11.8
11.6
Imports ____ .I^t'iJ. _____ _ _ __ _ Jlasos
8.2 20.0
10.0
'4.9
14.9
11.7
AKMUOIPS - energy and petroleum con-
sumption will p.row .11: lilstorlf.nl
rate. llasecl on Ford l:oundall*m
Sccn.irln (FO-027).
3.4 15.0 Assumes - .1 determined n:Ulon:tl
effort to rrdure d;im.iml for enerj'.v
hy nppllrntloo of »iner(',y H.'ivlii(\
tcrlmoloj;! es . It.'i.setl on Ford
Found.ttlon lcclinfr:il fix fu-en.-ir lo
(Wl-027).
4.6 16.3 Nomln.il case used by SKI ndd:i
of the difference hetweeit hi ;;1 or lr.nl
p.rowtli nod technical fix sren.-irlo
to I he h.lKcllne ol I In' I ci-lnll ra I fix
nccnarlo.
Analysis for Feb. 1975
National Science
Found.-!t Ion - Check
Sys tents
Pftrnr.liemlc.ilti March 1975
and Kncrp.y In I'er-
sperlIvc - OKP
Shell Chemical
(KF.-I49)
Petroleum Stor- AIIR. 1975 lUf.h Ranije of Im-
fip.t.1 for National port Projections
Security -
(NPC (NA-261) Low Ranf.e of Im-
port Projections
Calculated Medium
19.8
18.5
21.4
19.9
10.2
7.8
12.5
(t.4
*N,iLur.t I |-,,TH liquids ;trc I n<: 1 uilod In 11><: domrst. ic l.nt ;i Is of tlies
**Syn1itt*t I c: 1 l<|nld.s .ire not tnr.liuiod tti those, totnln.
ese pro Jort Ions.
-------
1) each scenario should represent a realistically
attainable situation, and
2) the scenarios chosen for study should bound
the range of possible developments.
Application of these criteria yielded three cases:
Maximum case - $13/bbl Supply Pessimistic - FEA
Minimum case - $13/bbl Accelerated Supply - FEA
"Most Likely" case - $13/bbl Business As Usual - FEA
The "$13/bbl Business As Usual" case was chosen as
the most significant for this study. 'It essentially represents
the average of all cases, and its basic assumptions seem to be
the most realistic.
4.4 Major Assumptions
Once given the overall demand for petroleum products,
an assumption needs to be made about the level of refining
activity. It is possible that domestic refining capacity will
expand to accommodate the increased petroleum demand, or this demand
will be met by importing refined products. The stated government
energy policies would seem to favor the former, calling for an
energy supply that is independent of foreign powers. On the other
hand, the expansion of domestic refineries may pose problems in
attaining the National Ambient Air Quality Standards.
There are clearly two opposing forces here, and it is
difficult to predict which will prevail or if some compromise
will be found. For the purposes of this study, it was assumed
that domestic refineries will grow to meet the increased petroleum
-44-
-------
demand. This will provide a study basis that encompasses all
possible refining formats (expansion of existing refineries,
grassroots refineries, etc.). It should also be much easier to
remove the effect of new growth from the calculations, if
necessary, than to add the growth effect later if it was required.
4.5 Caveats and Limitations
Predicting the future is always an endeavor filled
with uncertainty. Under the best conditions, where the given
phenomenon has performed in a regular manner historically and
there seems to be no impetus to change, the uncertainty is still
considerable.
While the petroleum industry has had a fairly uniform
historical growth, the last decade has shown divergence. Many
recognized forces are at work which could greatly alter-the
future growth of refining. Some of the major ones are:
Government policy changes including tax incentives,
price controls, offshore leasing, forced allocation
of crude and/or products, safety regulations, en-
vironmental regulations, and punitive efforts to
increase the competitive nature of the industry
(vertical or horizontal divestiture).
Development of new technology in the fields of
exploration, alternate energy forms, and enhanced
recovery of known reserves.
Changes in public opinion, especially as they affect
conservation measures and the siting of refineries
and production facilities.
-45-
-------
Changes in the world-wide energy distribution as
affected by OPEC and the emerging nations.
These non-quantifiable factors naturally add a great deal of
uncertainty to this projection.
Since completion of the Draft Final Report, govern-
mental policies have changed in the energy area. Legislation
such as the National Energy Policy and the requirements for
increasing automobile efficiency have placed pressure against
rising refinery crude oil demand. One result of this has been
a slightly lower growth in motor gasoline demand than predicted
by the model chosen. This should have a minimal effect on
the overall accuracy of the calculated energy penalties,
however, since the penalties are expressed on a per barrel of
crude basis. The only effect could come in slightly over
estimating penalties, because of stricter controls on new
capacity, which are then averaged with the penalties for
existing capacity. If this predicted capacity increase does
not materialize, the industry average penalty would be lower
than predicted. Conversely, the predicted penalties would be
too low if actual capacity expansion exceeds the predicted
expansion. Since the projected growth of new capacity is only
about 5.77o per year, these effects should be minimal.
-46-
-------
5.0 BASELINE ENERGY CONSUMPTION METHODOLOGY
In order to determine the relative impact of the increased
energy consumption due to environmental controls, it is necessary
to determine the baseline energy consumption with no controls.
The baseline production data will then allow the calculation of
an energy consumption per unit of production which can be extra-
polated into the future.
5.1 Calculation of Process Requirements
The base year was chosen as 1974 because full year
data were available, the level of existing environmental con-
trols was relatively low, and it was recent enough to accurately
represent the modern refining industry. The base year energy
consumption data were taken from the Bureau of Mines Annual
Petroleum Statement (US-595). These data are presented in
Form 1, Appendix B.
There were some environmental controls in effect in
1974, however, and the actual energy consumption figures must be
adjusted for this to determine a true "no control" baseline energy
requirement. These data are presented in Table 5.1. It is inter-
esting to note that if all pollution control equipment is attrib-
uted to environmental regulation requirements, there is a net
decrease in the overall refinery energy requirement. This effect
is caused by the waste energy recovery of the Carbon Monoxide
(CO) Boilers in use on many cracking units. In fact, many of
the CO Boilers in operation in 1974 were not required by any
environmental regulation. Therefore, it is evident that the CO
Boilers were being justified on the basis of energy conservation,
and that the pollution abatement aspect was only a side effect.
The bottom section of Table 5.1-1 shows the energy penalty for
environmental controls neglecting CO Boilers. This yields a
-47-
-------
TABLE 5.1-1. BASELINE ENERGY CONSUMPTION
i
f>
oo
Actual 1974 Energy
Consumption
Energy Penalty for
Existing Controls
Adjusted 1974 Energy
Consumption with "no
controls"
Energy Penalty for
Existing Controls
(neglecting CO Boiler)
All units are in 103 Btu/Bbl
Census Region No.
12345678
0 690 750 550 640 576 753 608
0 (8) (5) (6) (4) (12) 0 (1)
0 698 755 556 644 588 753 609
085855 10 4
Wt. National
9 Average
654 678
(1) (3)
655 681
11 9
Adjusted 1974 Energy
Consumption with "no
controls" except CO
Boilers
0 682 745 542 635 571 743 604 643
669
-------
more reasonable number, a weighted national average penalty of
9000 Btu per barrel of crude processed. Since the actual con-
sumption in 1974 averaged 678,000 Btu/bbl, the true baseline
energy consumption was 669,000 Btu/bbl.
The penalty for existing controls devoted exclusively
to pollution abatement was, therefore, only about 1.370 of the
baseline consumption. This difference between actual 1974 con-
sumption and the true baseline consumption need not be considered
in the projected baseline consumptions for 1980 and 1985, since
it is of negligible magnitude in comparison to the uncertainties
of forecasting the industry production levels (see Sections 4.3
and 4.4) .
5.2 Allocation Among Fuel Types
The BOM data were discretely expressed in the actual
fuel types used in 1974. Each fuel type was projected to maintain
its share of the energy requirements for 1980 and 1985, except
for natural gas. The current natural gas shortages, resulting
in curtailment of industrial consumption in order to meet resi-
dential needs, make it unlikely that natural gas can maintain
its share of the refinery fuel market. It was assumed for this
study, that natural gas would supply only half of its 1974 share
in 1980, and would not be used at all in 1985. Fuel oils were
chosen as the most likely replacement.
The balance of purchased versus self-generated elec-
tricity was also considered. Economic factors are currently
favorable for self-generation in refineries. Since a refinery
requires large amounts of steam for the process units, it is
possible to generate this steam at a higher pressure than
needed and reduce pressure through a turbine driving a generator.
The efficiency of this scheme is considerably higher than that
-49-
-------
attained by an electric utility company, and with rising fuel
costs this provides a strong incentive. The modification of
existing equipment is a very capital intensive operation, however,
and this may deter any large scale conversion. It would be most
attractive in the larger plants and in new construction. For
the purposes of this study, it was assumed that self-generation
of electricity would only maintain its current level.
There is some uncertainty about what constitutes a pur-
chased fuel or a self-generated fuel in a refinery, since its
principal products are fuels. Fuel oils were listed on Form 1
as purchased fuels, even though they were very likely produced
in the refinery where they were burned. The rationale for this
is that the fuel oils consumed in the refinery would be sold if
they were not burned. Therefore, by relinquishing the potential
income from the fuel oils consumed internally, the refinery is
purchasing the fuel from itself. Refinery fuel gas and catalytic
coke were listed as self-generated fuels since there was no
outside market to which they could be diverted.
5.3 Regionalization
The 1974 data from the BOM were presented by state.
It was a simple matter to group these states into their appro-
priate census districts. Data for 1980 and 1985 were extrapolated
from 1974 data using the growth models described in Section 4.3.
5.4 Projected Changes Through 1985
The refining industry is dynamic, always in a process
of internal change, but there are no great changes forecast in
refinery fuel implementation through 1985. The major effect
will be the application of more sophisticated pollution control
equipment and its inherent energy drain. Counteracting this effect
-50-
-------
will be industry conservation efforts. In addition, refined
products specifications have historically become progressively
stricter in order to meet the needs of more sophisticated end
use machinery. This trend should continue.
While research into alternate energy forms is being
actively and- successfully pursued, this will have little bearing
on the refining industry fuel slate. While coal, solar power,
nuclear power, etc. show great promise, these energy sources are
not expected to overcome the logical convenience of burning
petroleum based fuels in a refinery.
The application of alternate energy technology outside
refining may eventually slow the growth in demand for fossil fuels
It can even be anticipated that petroleum derivatives will some-
day be far too valuable as chemical feedstocks to be used as fuels
at all. But these developments are beyond the time frame of this
study.
5.5 Caveats and Limitations
The figures for 1974 actual and baseline energy con-
sumption are firm. Consumptions for 1980 and 1985 are subject
to variation. The major factors introducing uncertainty are:
\
Dependence on fluctuating foreign crude supplies,
Lack of a firm, comprehensive national energy
policy,
Effectiveness of public energy conservation
measures,
-51-
-------
Development and application of alternate energy
forms, and
Possible technology improvements in refining
processes, pollution control equipment, and/or end
use machinery (mainly automobiles).
-52-
-------
6.0 ENERGY PENALTY METHODOLOGY
This section describes the methods used to estimate
the energy penalties which result from refinery compliance
with environmental regulations. This penalty is defined as
the incremental demand for energy above a baseline demand that
would occur in the absence of any federally enforceable en-
vironmental regulations. The method that was used to estimate
the energy penalties first analyzes the environmental regulations
which impact the petroleum refining industry. Then the various
environmental control strategies available to the refining
industry are reviewed. Finally, the actual energy penalty
calculations are summarized, and the section concludes with a
discussion of how the refining industry was regionalized for the
study and how the energy penalties are distributed according to
fuel types.
6.1 Identification of Major Environmental Regulations and
Standards
The environmental regulations and standards covered
in this study are limited to those which are enforceable by
the federal government. Those federally enforceable regulations
impacting the refining industry were reviewed and the regulations
which result in potentially significant energy penalties were
selected. This section identifies those regulations and standards
which were chosen on that basis. The pollutants covered include
particulates, S02 , NO , CO, HC, lead, and wastewater. The
X
following discussion presents a review by pollutant of the re-
gulations which were selected for this study.
-53-
-------
6.1.1 Particulate Regulations
In defining the four regulatory scenarios for the con-
trol of particulates, three types of regulations were considered
State Implementation Plans (SIP), New Source Performance Stan-
dards (NSPS), and the Reasonable Available Control Technology
(RACT). While RACT is actually a hypothetical control regula-
tion, it is an important indication of the impact of implement-
ing the most severe particulate control regulations.
For the control of particulate emissions, State Imple-
mentation Plans concentrate basically on combustion units, pro-
cess units, and catalytic cracking units (see Appendix A, Table
A-l). Although'regulations vary widely among the states, some
are more common than others. For instance,. most states set the
maximum allowable particulate emissions from combustion units
at about 0.6 lb/hr/106 Btu. Similarly, many states limit par-
ticulate emissions according to process weights. Therefore, .
for a process weight (P) less than or equal to 30 ton/hr, the
allowable emission rate (Ib/hr) is equal to 4.10 (P)°'57. For
larger process weights, the emission rate becomes [ 55.0 (P)° ' 11}
-40. Most states consider catalytic cracking units as process
units.
Presently NSPS applies only to steam generators and .
catalytic crackers. For either coal, oil, or gas-fired boilers
the maximum allowable particulate emission rate is 0.10 lb/106
Btu. For catalytic crackers particulate emissions cannot exceed
1.0 lb/1000 Ib of coke burnoff in the regenerator.
In applying RACT values the objective was maximum
particulate emission control. The result was to apply three
types of particulate control measures in a staged arrangement
which achieved 99.95% theoretical efficiency.
-54-
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6.1.2 Sulfur Dioxide Regulations
In defining the six regulatory scenarios for the con-
trol of sulfur dioxide emissions, five types of regulations were
considered: State Implementation Plans, New Source Performance
Standards, the most Reasonable Available Control Technology,
and desulfurization of all petroleum products to either 0. !"/» or
0.370. Presently the only federally enforceable regulations are
SIP and NSPS.
For the control of S02 emissions, State Implementation
Plans concentrate basically on combustion units, process units,
and sulfur recovery units (see Appendix A, Table A-2). In all
three instances, there is no common regulation. For combustion
units several states rely on various means of control. For
example, some states regulate the sulfur content of the fuel
according to weight percent, while other states regulate the
effluent by ppm SOa. Still others limit the emission rate as
an allowable Ib S0a/10s Btu heat input. For process units and
sulfur recovery units the regulations are more consistent. Most
states regulate the effluent by ppm SOa, with allowable values
ranging from 500 to 2000.
Presently NSPS applies only to steam generators great-
er than 250 million Btu/hr and fuel gas combustion. For coal-
fired boilers the allowable emission rate is 1.2 Ib SOa/106 Btu
and for oil fired boilers the allowable emission rate is 0.80
lb/105 Btu. NSPS also require that any fuel gas be less than
0.1 grain H2S/dscf (KE-181). Proposed rules would also limit
the concentration of sulfur dioxide in the gases discharged to
the atmosphere from a sulfur recovery unit to 0.025 percent by
volume at zero percent oxygen and on a dry basis.
-55-
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In applying RACT regulations the objective was maximum
S02 emission control. For the most part, this meant hydrodesul-
furization of fuel oils marketed for use in industrial and
utility process heaters and boilers. RACT also required tail
gas cleanup on all sulfur recovery units. To control SOz from
the catalytic cracker, two options are available: hydrodesulfur-
ization of feed or flue gas scrubbing.
The final two sets of regulations did not limit emis-
sions as such, but limited the sulfur content of petroleum pro-
ducts to 0.7 weight percent and 0.3 weight percent, respectively.
The major aim of these regulations was to decrease the SOz emis-
sions associated with burning fuels (distillate, gas oil, and
resid) by decreasing the sulfur available in the fuels. These
regulations would not affect other products such as gasoline
and jet fuel, which already meet these specifications.
6.1.3 Nitrogen Oxides Regulation
Current federally enforceable regulations for nitrogen
oxide emissions from petroleum refining are the State Imple-
mentation Plans (SIP) and New Source Performance Standards
(NSPS). A list of the SIP NO regulations by state is'given
2C
in Appendix" A, Table A-3.
The only source of NO emissions in refineries
Jt
subject to regulation are the fuel combustion units. Most
SIP regulations limit only the amount of NOV emitted from units
it
with greater than 250 million Btu per hour heat input. Common SIP
emission limits are 0.2 pounds NO per million .Btu__of ..heat input
2t
for gas-fired units and 0.3 pounds NO per million Btu for oil
fired units. The New Source Performance Standard for NO
X.
emissions from fuel combustion is also 0.2 Ibs/million Btu for
-56-
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gas and 0.3 Ibs/million Btu for oil. The Control Strategies
section of this report describes the common control techniques
used by industry to reduce NO emissions from fuel combustion.
X
Besides the SIP and NSPS regulations, a regulation was
used in the study which assumed the required application of
reasonable available control technology (RACT). This regulation
was intended to represent a "strictest case" of regulation for
NO emission control. For purposes of energy penalty calcula-
Jt
tions it was assumed to apply to all fuel combustion sources
of NO with greater than 250 million Btu per hour heat input.
j£
The limits of NO emission chosen were 0.2 Ibs NO /million Btu
X X
for gas firing and 0.3 Ibs NO /million Btu for oil firing.
X
6.1.4 Carbon Monoxide Regulations
Twenty states have written specific carbon monoxide
emission limitations in their SIP's. Fourteen of these apply
to existing and new units, while the other six are strictly for
new sources. All new sources will also be under the regulation
of the Federal New Source Performance Standards (NSPS) which
allow a maximum of 0.05 volume % CO emissions from a catalytic
cracker.
The only significant source of carbon monoxide emis-
sions in petroleum refineries is the catalytic cracking catalyst
regenerator. Before federally enforceable CO standards existed
well over half of the total catalytic cracking capacity was
equipped with CO boilers (SH-306). This is because in most
cases there is a net energy saving to the refiner once CO boilers
are installed. As energy costs escalate in the future the eco-
nomic advantage of CO boilers will become even more pronounced.
-57-
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This reasoning led to the assumption that CO boilers
were not installed for environmental reasons, but rather for
economic reasons. Therefore, no energy penalties, or credits
in this case, were calculated due to the installation and
operation of CO boilers. While this assumption may not be true
for every case of a CO boiler installation, it is believed that
this assumption describes the real world situation with the
least error within the scope of this study.
6.1.5 Hydrocarbon Regulations
Current federally enforceable regulations for hydro-
carbon emissions from petroleum refining are the State Implementa-
tion Plans (SIP) and New Source Performance Standards (NSPS).
A list of the SIP hydrocarbon regulations by state is given in
Appendix A, Table A-5.
Those sources of hydrocarbon emissions in refineries which
are regulated by SIP's and whose control leads to significant
primary and/or secondary energy penalties include gasoline tank
car and tank truck loading racks, oil-water separators, vapor
blowdown, and storage tanks. The typical SIP requirement for
loading racks is control by vapor recovery. For oil-water
separators floating covers are usually required. Vapor blowdown
is controlled by flaring. Storage tanks containing volatile
hydrocarbon liquids are usually required by SIP regulations to
be controlled by floating roofs, vapor recovery system, or pressure
tanks depending on vapor pressure. The New Source Performance
Standards for hydrocarbon emissions from refineries refer only
to hydrocarbon storage. The NSPS requires floating roof tanks,
pressure tanks, or vapor recovery systems depending on vapor
pressure.
-58-
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Another regulation was used in the study besides the
SIP and NSPS regulations. This regulation was developed to
determine the energy penalty for the "strictest case" of hydro-
carbon emission control. The regulation applied to tank car/
truck loading racks, oil-water separators, vapor blowdown, and
storage tanks. The requirements of this regulation are vapor
recovery systems for loading racks, floating covers for oil-
water separators, smokeless flares for vapor blowdown control,
and floating roofs and pressure tanks for storage tank control.
6.1.6 Lead Regulations
The removal of lead anti-knock additives from gasoline
has been the subject of heated debate since 1970. Although there
is some evidence that airborne lead may be a health hazard,
the impetus for unleaded gasoline was primarily to sat-
isfy the requirements of the catalytic muffler. Since
the catalytic converter was to become standard equipment
on the 1975 model year cars, it was mandated that all major
refiners make unleaded gasoline available by July 1, 1974.
Total pool lead reduction had already been in effect since 1971
when low lead gasoline was introduced, but market acceptance of
this grade was very low. The 1975 and later cars were equipped
with a special filter neck that would not accept a leaded gaso-
line nozzle, so the use of unleaded gasoline has risen proportionally
to the influx of new cars. This market demand for unleaded.
gasoline was considered to be the most lenient regulatory scenario
for this study.
In an effort to reduce airborne lead levels more rapidly
than demand for unleaded gasoline would accomplish, total pool
lead phasedown schedules have been promulgated. Several versions
of the phasedown timetable have been modified at the request of
-59-
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refiners, who claimed that they were unable to comply with
proposed schedules. The current phasedown criteria allows
waivers of the intermediate lead levels for refiners who can
show that they are taking good faith steps to meet the ultimate
level of less than 0.5 gram of lead additive per gallon of the
total gasoline pool. This would require a reduction in the
lead level in regular and premium grades as well as the pro-
duction of unleaded gasoline. This lead phasedown was chosen
as the second regulatory scenario.
The strictest regulatory scenario would obviously
be the complete exclusion of lead from gasoline. Calculations
for this case were made only for 1985, since it would not be
technologically feasible in the earlier study years. This
scenario will probably occur even if not required by law.
The replacement of the auto population with new models requiring
unleaded gasoline will make it economically unattractive to
maintain segregated marketing facilities for the small portion
of cars that can use leaded gasoline.
6.1.7 Water Regulations
Current federally enforceable regulations for water
effluents from petroleum refining are the State Water Laws,
the Effluent Limitations Guidelines, and New Source Performance
Standards. A list of the State Water Laws as they apply to the
refining industry is given in Appendix A, Table A-7. Also
listed in Table A-7 are the Effluent Limitations Guidelines and
New Source Performance Standards.
The State Water Laws limit the discharge of any pol-
lutant to state waters from any point source by requiring that a
certain level of control be applied to the source. For the
refining industry the level of control is either primary or
-60-
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secondary treatment. The Effluent Limitations Guidelines and
New Source Performance Standards specifically describe the level
of control which must be applied to refinery effluents. These
guidelines call for all existing refinery sources to have
secondary-level waste treatment facilities by 1977 and tertiary
treatment and wastewater flow reductions by 1983. For new
sources the guidelines require secondary treatment and waste-
water flow reductions.
6.2 Control Strategies
This section of the report presents the control stra-
tegies which were developed for the given regulatory scenarios.
The control technology represents current state-of-the-art ap-
plication as well as projected control technology needed to
meet 1980 and 1985 requirements. Particulate control strategies
are discussed first, followed by S02, NO , HC, lead, and water.
X
Table 6.2-1 presents a summary of the control strategies used
for each of the pollutants.
6.2.1 Particulates
The two major sources of particulate emissions from
petroleum refinery operations are process heaters and boilers
and fluidized-bed catalytic cracking units. For process heaters
and boilers there is no technically practical means to clean
the flue gas from so many diverse sources. As a result, the
best means of control is to limit the types of fuel which can
be burned. Based on emission factor data, the particulate emis-
sions from residual oil and distillate oil combustion are 0.154
lb/106 Btu and 0.108 lb/106 Btu, respectively (EN-071). Many
State Implementation Plans and the New Source Performance Stan-
dards have chosen to regulate fuels by allowing particulate
emissions not to exceed 0.10 lb/106 Btu.
-61-
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TABLE 6.2-1. SUMMARY OF CONTROL STRATEGIES
Regulatory
Scenario
1
2
3
A
Regulatory
Scenario
Particulates SIP
(Existing Sources)
Particulates SIP;
(New Sources)
Particulates NSPS
Particulates RACT
CONTROL STRATEGY MIX #
1
Multiple
Internal
Cyclones
(MIC)
MIC
MIC
MIC plus
ESP
2
MIC plus
Electro-
static Pre-
cipitator
(ESP)
MIC plus
ESP
MIC plus
ESP
MIC plus a
Wet
Scrubber
3
MIC plus a
Wet Scrubber
MIC plus a
Wet Scrubber
MIC plus a
Uet Scrubber
MIC, ESP,
and a Wet
Scrubber
4
5
-------
TABLE 6.2-1. (Continued)
ON
co
Regulatory
Scenario
5
6
7
8
9
10
Regulatory
Scenario
S02 SIP (Existing
Source)
S02 SIP (New
Sources)
S02 NSPS
SO 2 RACT
S02 0.7 wt.
% S Fuel
S02 0.3 wt.
% S Fuel
CONTROL STRATEGY MIX 0
1
Selective Fuel
Blending;
Claus Unit
Selective
Fuel Blending
Selective
Fuel Blending
Selective
Fuel Blending
Selective
Fuel Blending
Selective
Fuel Blending
2
Blending plus
some Gas Oil
I1DS: Claus
Unit
Blending plus
some Gas Oil
HDS; Claus
Unit
Blending plus
some Gas Oil
I1DS; Claus
Unit
Blending plus
some Gas Oil
11DS; Claus
Unit
Blending plus
some Gas Oil
11DS; Claus
Unit
Blending plus
some Gas Oil
11DS; Claus
Unit
3
Blending plus
HDS of FCC
Feed; Claus
Unit with Tail
Gas Treating
Blending plus
HDS of FCC
Feed; Claus
Unit with Tail
Gas Treating
Blending plus
HDS of FCC
Feed; Claus
Unit with Tail
Gas Treating
Blending plus
HDS of FCC
Feed; Claus
Unit with Tail
Gas Treating
Blending plus
HDS of FCC
Feed; Claus
Unit with Tail
Gas Treating
Blending plus
HDS of FCC
Feed; Claus
Unit with Tail
Gas Treating
4
No. 3 plus Gas
Oil HDS
No. 3 plus Gas
Oil HDS
No. 3 plus Gas
Oil HDS
No. 3 plus Gas
Oil HDS
No. 3 plus Gas
Oil HDS
No. 3 plus Gas
Oil HDS
5
Blending Gas Oil
HDS, FCC Flue Gas
Scrubbing; Claus
Unit with Tail
Gas Treating
Blending Gas Oil
HDS, FCC Flue Gas
Scrubbing; Claus
Unit with Tail
Gas Treating
Blending Gas Oil
HDS, FCC Flue Gas
Scrubbing; Claus
Unit with Tail
Gas Treating
Blending Gas Oil
HDS, FCC Flue Gas
Scrubbing; Claus
Unit with Tail
Gas Treating
Blending Gas Oil
HDS, FCC Flue Gas
Scrubbing; Claus
Unit with Tail
Gas Treating
Blending Gas Oil
HDS, FCC Flue Gas
Scrubbing; Claus
Unit with Tail
Gas Treating
-------
TABLE 6.2-1. (Continued)
i
cr>
Regulatory
Scenario
11
12
13
14
Regulatory
Scenario
NO SIP
x
(Existing Units)
N0x SIP
(New Units)
N0x NSPS
NOX RACT
CONTROL STRATEGY MIX #
1
Two State
Combustion
Two Stage
Combustion
Two Stage
Combustion
Two Stage
Combus tion
2
Flue Gas
Recircula-
tion
Flue Gas
Recircula-
tion
Flue Gas
Recircula-
tion
Flue Gas
Recircula-
tion
3
4
5
-------
TABLE 6.2-1. (Continued)
Ul
Regulatory
Scenario
15
16
17
18
Regulatory
Scenario
Hydrocarbon SIP
(Existing Sources)
Hydrocarbon SIP
(Hew Sources)
Hydrocarbon NSPS
Hydrocarbon RACT
CONTROL STRATEGY MIX //
1
Slowdown
vented to
flares ;
Pressure
tanks
Blowdown
vented to
flares ;
Pressure
tanks
Floating
roof tanks,
Blowdown
vented to
flares ;
Pressure
Lanka
2
No. 1, plus
floating
roof tanks
and vapor
recovery
-------
TABLE 6.2-1. (Continued)
Regulatory
Scenario
19
20
21
Regulatory
Scenario
Produce Unleaded
Gasoline to'Meet
Market Demand
Lead Phasedown to
<0.5 gm/gal of the
Total Pool by
10-1-79
Zero Lead in
Gasoline
1
Increase
Processing
Severity to
Improve
Octanes
Increase
Processing
Severity to
Improve
Octanes
Increase
Processing
Severity to
Improve
Octanes
CONTROL
2
Some sever-
ity increase,
plus the use
of a non-
Lead
additive
Some sever-
ity increase
plus the use
af a non-
lead
additive
Some sever-
ity increase
plus the use
of a non-
lead
additive
STRATEGY I*
3
ux #
A
5
-------
TABLE 6.2-1. (Continued)
Regulatory
Scenario
22
23
24
25
Regulatory
Scenario
Slate Waste-
water Treatment
Requirements
BPCTCA-Federal
Effluent
Limitations
BADT-Federal
Effluent
Limitations
BATEA- Federal
Effluent
Llmltatlonu
CONTROL STRATEGY Ml.X //
1
Sour Water Stripping, API
Separators, Dissolved Air
Floatation, Equalization
Basin, Clarification,
Trickling Filters
Sour Water Stripping, API
Separators, Dissolved Air
Floatation, Equalization
Basin. Clarification,
Trickling Filter,
VI 1 1 ration
Sour Water Stripping, API
Separators, Dissolved Air
Floatation, Equalization
Basin, Clarification,
Trickling Filter, Flit ra-
tion pl.ua Reduction in
Flow
Sour Water Stripping. API
Separators, Dissolved Air
Floatation, Kquu 11 zutlon
Basin, Clarification,
Trickling Filter, Filtra-
tion, Carbon Adsorption,
Reduction in Flow
2
No. 1 with Un-
uerated Lagoons
Replacing Trick-
ling Filters
No. 1 with Un-
ae rated Lagoons
Replacing Trick-
ling Filters
No. 1 with Un-
aerated Lagoons
Replacing Trick-
ling Filters
plus Reduction
In Flow
No. 1 with Un-
acrated Lagoons
Hep lacing Trick-
ling Filters
plus Reduction
in Flow
3
No. 2 with
Aeration Towers
Replacing Un-
ae rated Lagoons
No. 2 with
Aeration Towers
Replacing L)a-
aerated Lagoons
No. 2 with
Aeration Towers
Replacing Un-
aeratud Lagoons
plus Reduction
in Flow
No. 2 with
Aeration Towers
Iteplac Ing Un-
aerated Lagoons
plus Reduction
in Flow
A
No . 3 w i i h
Aerated Lagoons
Replacing Aera-
tion Towers
No. 3 with
Aerated Lagoons
Replacing Aera-
tion Towers
No. 3 with
Aerated Lagoons
Replacing Aera-
tion Towers
plus Reduction
i n F 1 ow
No. 3 wi til
Aerated Lagoons
Replacing Aera-
tion Towers
plus Reduction
in Flow
5
No. It with
Activated
Sludge Re-
placing
Aerated
Lagoons
No. ') with
Act ivated
Sludge Re-
placing
Aerated
Lagoons
No. 4 wl th
Activated
Sludge Re-
placing
Aerated
l.ai'.onn:; plus
Reduction in
Flow
No. 4 uilh
Act ivated
Sludi;e Kir-
p lac Ing
Aerated
l.a>;».>iis plus
Reduction in
Flow
cr>
^j
i
-------
In the fluidized-bed catalytic cracker the particulate
emissions result from coke burnoff in the catalyst regenerator.
Three possible control strategy mixes have been proposed. One
means of control would be the use of multiple internal cyclones
(MIC). Multiple cyclones have only slightly higher efficiencies
( 90% for particles >5u) than one large cyclone, but usually
require less space (LU-013). A second method of particulate
control is the combination of multiple internal cyclones and an
electrostatic precipitator (ESP). The addition of the electro-
static precipitator increases the overall collection efficiency
to about 99.5% (JO-086). The third control strategy mix con-
sisted of multiple internal cyclones followed by. a wet scrubber.
The wet scrubber, considered here was a jet-ejector venturi
scrubber designed by Exxon, which claims a particulate collection
efficiency of 90% (EX-001). By combining multiple internal cy-
clones and a wet scrubber, the overall efficiency is about 99.0%.
6.2.2 Sulfur Dioxide
The three major sources of sulfur dioxide emissions
from petroleum refining operations are process heaters and
boilers, fluidized-bed catalytic cracking units, and sulfur
recovery units. The control of sulfur dioxide emissions requires
complicated arrangement of various process units. Five diffe-
rent control strategy mixes were proposed ranging from the most
common arrangement presently used by the refinery industry to
an arrangement utilizing the most reasonable available techno-
logy.
In calculating the effectiveness of each process unit
the following sulfur removal efficiencies were assumed:
-68-
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Naphtha HDS
Distillate HDS
Gas Oil HDS
Res id HDS
Gas Treating Plant (GA-182) 99.99%
Glaus Sulfur Recovery Unit (GA-182) 95%""I QQ
Scot Tail Gas Treatment (HY-014) 96%j
FCC Flue Gas Scrubber (EX-001) 97%
All five control strategy mixes were assumed to use naphtha
hydrodesulfurization, distillate hydrodesulfurization, and gas
treating plants as a matter of accepted industry practice.
Therefore, in calculating energy penalties and secondary impact
indicators, only the necessary incremental capacities were con-
sidered.
The most reasonable means of controlling SOz emissions
from process heaters and boilers is to control the sulfur con-
tent of the fuels. In 1974 such control represents no signifi-
cant difficulty, but in 1980 and 1985 the amount of sour crude
being processed will have increased tremendously and the use of
gas oil hydrodesulfurization and resid hydrodesulfurization will
be important factors in meeting low sulfur fuel demands.
The control of SOa emissions from fluidized-bed
catalytic cracking units can be accomplished in one of two ways.
The most common method has been to desulfurize the FCC feed.
The near-absence of sulfur in the feed results in a much lower
SOz concentration in the flue gas. Recently Exxon has proposed
flue gas scrubbing as a viable alternative to FCC feed desul-
furization. Exxon has installed a commercial size unit at their
Baytown and Baton Rouge refineries and preliminary indications
of S02 removal have been very favorable.
-69-
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Sulfur recovery units are the third potential source
of SOa emissions from petroleum refining operations. Sulfur
recovery units are necessary to convert high E2S concentrations
in acid gas into the more disposable by-product elemental sulfur.
The most common practice is to use a modified Glaus plant, usually
equipped with a reheat scheme and up to four catalytic converters.
The EPA suggests for Glaus sulfur plants, an SOa emission lim-
itation of 0.01 Ibs of SOa/lb of sulfur processed. This is
about one tenth of the typical emission found in most Glaus plant
stacks and will result in the addition of some type of tail gas
cleaning unit (GO-214). Although several tail gas cleaning pro-
cesses are available, for the purposes of this study the SCOT
process was chosen because of its similarity to other refinery
processes, the economical materials of construction, and the
low SOa emissions (less than 250 ppm SOa after incineration).
Each of the five control strategy mixes is an arrange-
ment of the emission control operations discussed. In addition
the degree of these operations may also differ within a control
strategy mix. For example, fuels hydrodesulfurization may imply
hydrodesulfurization of either gas oil, residual oil, or both,
depending upon the severity of the regulation being considered.
6.2.3 Nitrogen Oxides Control Strategies
The only source of nitrogen oxides from petroleum
refineries that is subject now or is expected to be subject in
the future to federally enforceable regulations is fuel com-
bustion. Currently, these regulations apply to steam boilers
with greater than 250 million Btu per hour heat input. Two
control strategies were developed which satisfy the regulatory
-70-
-------
scenarios used in this study. The first control strategy is
two-stage combustion. The second is flue gas recirculation.
Both control strategies have primary and secondary impacts
associated with their use.
Two stage combustion has the effect of fuel rich burner
operation on boiler NO formation. Two-stage combustion works
X
on the principles of off-stoichiometric combustion except that
the fuel-rich burner operation is achieved by diverting a por-
tion of the total required air through separate ports located
above the burner pattern. This has the effect of lowering NO
X
formation by lowering peak flame temperature.
The flue gas recirculation control technique reduces
NO formation by reducing both the peak flame temperature and
X
partial pressure of available oxygen at the burner inlet. This
is accomplished by recirculating a portion of the boiler flue
gas back to the primary combustion zone.
6.2.4 Hydrocarbon Control Strategies
Four sources of hydrocarbon emissions from refineries
were chosen for this study on the basis of the primary and/or
secondary impact of their control. These sources are tank
truck/car loading racks, oil-water separators, vapor blowdown,
and storage tanks. Alternative control strategies were developed
for the regulations which apply to these sources. The control
strategies vary according to regulatory scenario and stringency.
Included in Table 6.2-1 (Regulatory Scenarios 15-18) are the
control strategies that were used for this study. A description
of each control technique for the hydrocarbon sources listed
follox\rs.
-71-
-------
The control of tank truck/car loading racks is usually
only required for petroleum products with vapor pressures greater
than 1.5 psia. Those State Implementation Plans which do require
control of emissions from loading operations usually specify
vapor collection and recovery. The vapor collection systems
are manifolded into a vapor recovery unit either for conversion
of the hydrocarbon vapors into liquid product by condensation or
compression or for disposal of the vapors through such processes
as combustion or absorption. Most systems are capable of achieving
90 percent reduction of hydrocarbon emissions. For energy penalty
calculations, condensation of the collected vapors was assumed.
Where control of oil-water separators is required,
vapor loss control devices on the units are generally specified.
Vapor loss control devices can. be a floating cover or a vapor
recovery system. Since floating covers are much simpler and
more economical they are preferred over vapor recovery systems.
The floating cover on the separator acts much the same as does
the floating roof used to control storage tank emissions. By
eliminating the vapor space above the liquid surface, the volatile
components of the wastewater are not allowed to evaporate.
Vapor blowdown occurs in a refinery due to unit
start-ups, shutdowns, process venting, process upsets, power
failures, or natural catastrophies. The hydrocarbon blowdown is
collected in a system which vents the gases to flares for com-
bustion. Liquids in the blowdown stream are separated by knock-out
drums. For the purpose of calculating energy penalties, flares
were assumed to be required for all refineries even though their
use was not stated specifically in each regulation. Smokeless
operation was also assumed which requires the addition of steam
to the flare tip during combustion. Flaring results in a 994-
percent control of vapor blowdown emissions. Flaring also re-
sults in both primary and secondary impacts.
-72-
-------
The control of hydrocarbon emissions from storage
tanks depends upon two factors. First, the vapor pressure of
the liquid stored generally determines what type of control is
required. For liquids with true vapor pressures greater than
11.0 psia, pressure tanks or vapor recovery systems are required
by most regulations. Pressure tanks are commonly used in re-
fineries for storing highly volatile products, and vapor recovery
applications to storage control are limited due to high costs.
For liquids with true vapor pressures from 1.5 psia to 11.0 psia,
floating roof tanks or vapor recovery systems are required by
most regulations. Floating roof tanks are used almost exclusively
to control emissions because of their economic advantages over
vapor recovery systems.
The second factor determining storage tank control is
the capacity of the tank. The State Implementation Plans generally
limit regulation to tanks with capacities greater than 40,000
gallons. This includes virtually all refinery tankage. The New
Source Performance Standards apply only to tanks with capacities
greater than 40,000 gallons, also.
6.2.5 Lead Control Strategies
The purpose of lead additives in gasoline is to increase
the octane number, which is merely a'numerical measure of the ten-
dency of an engine to "knock" on a given fuel. There are a number
of alternatives which can compensate for the removal of lead. One
would be to modify the internal combustion engine so that it could
operate satisfactorily on lower octane fuels. This was done, at
least in part, when auto makers cut the compression ratio of their
engines to accommodate fuel with an octane similar to "regular"
gasoline instead of "premium." This was a necessary, but not a
sufficient adjustment. Thus, the refiner is left with two alter-
natives, increasing process severity or using a non-lead based
additive to increase the octane number of his product gasoline.
-73- '
-------
There are already many processes at work in the
refinery whose purpose is octane improvement. The most impor-
tant of these is the Catalytic Reforming Unit (CRU). Just as
the name implies, this unit reforms low octane normal paraffin
components into isoparaffins, naphthenes, and aromatics.
Typical operation of such a unit would upgrade the gasoline to
about a 90 Research Octane Number (RON). This is usually
termed a severity of 90. The production of substantial amounts
of unleaded gasoline requires that reformer severity be raised
to an eventual limit of about 100. This requires more energy
in the form of fuel to the heaters, but the worst effect is
the decrease in yield. Figure 6.2-1 graphically demonstrates
a typical yield/severity relationship. It should be noted that
the yield drops ever more sharply with increasing severity.
This is due to the increase in the unwanted side reaction,
hydrocracking, which breaks the gasoline components into butanes,
propanes, and fuel gas. This loss of gasoline yield means that
more naphtha must be run to yield the same volume of higher
octane product. This necessitates additional construction of
reformer capacity, and therefore an increase in energy consump-
tion.
Another important process in octane boosting is the
Fluid Catalytical Cracking Unit (FCCU) . Although the primary
function of the FCCU is to increase the gasoline supply by
cracking heavier gas oils, the way in which this is accomplished
can have considerable effect on pool octane. Cracking at higher
reactor temperatures can provide a several octane number increase
in cracked gasoline. This will be accompanied by the production
of more of the reactive propylene and butylene which feed
Alkylation and Polymerization units, also producers of high
octane gasoline. This high temperature cracking is accompanied
by increased energy consumption, both in fuel to the feed
preheater and in incremental coke yield burned in the regenerator
-74-
-------
Figure 6.2-1. Reformer Yield/Severity Relationship
100 r
95-
>J
a 30
3 75
a
70
65
60
90
Heavy S, R. Gasoline
"X
Heavy Hydrocracked
Gasoline
Light S= R, Gasoline
95
REFORMER SEVERITY (RON)
100
-75-
Source: LI-151
-------
The Alkylation process builds a gasoline molecule
from two molecules of light hydrocarbon. One of the feed
molecules must be isobutane, and the other must be an olefin
such as propylene, butylene, or pentylene. The result is a
very high octane gasoline stock with good volatility characteristics
More alkylation capacity will be needed to compensate for lead
removal, and this is a very energy intensive process. The
Polymerization process builds gasoline from three olefin
molecules. This gasoline is somewhat lower in quality, and this
process will play a negligible part in replacing lead.
The Isomerization process changes straight chain
paraffins into branched chains, and by doing so raises the octane
number. This will be used primarily for five and/or six carbon
gasoline molecules. Isomerization is important in that it pro-
duces high octane gasoline with a relatively low boiling point.
This high volatility octane is very important to engine performance,
especially as the higher boiling aromatics are concentrated by
high severity reforming.
The combination of all the above processes is required
in varying proportions to satisfy the octane needs of various
regions and refinery configurations. This general control
strategy is called increasing process severity.
The other unique control strategy would be the replace-
ment of lead with a non-lead based anti-knock additive. There
are several possibilities, but- probably the most promising is
methylcyclopentadienyl manganese tricarbonyl, or MMT as it is
commonly called. Preliminary data from General Motors indicate
that above a certain level MMT may pose a problem of clogging
the catalytic converter. However, because of the low concentra-
tion of MMT in gasoline proposed in this report, it is believed
-76-
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that MMT is a viable anti-knock additive. Furthermore, there
is no evidence that manganese poses a health hazard (UN-072).
MMT is currently in use in "trimming" blends of unleaded
gasoline. This is the process of correcting a blend whose
octane falls below the specification. It is much easier to
add a few pounds of MMT, than to add hundreds of barrels of
high octane blending stock. This is an efficient and desirable
process, since it allows the refiner to let his target octane
on the blend approach the octane specification more closely,
thus reducing costly over-refining.
While the routine use of MMT on a large scale has been
delayed by its cost, it becomes more economically feasible as
the octane requirement increases. It is presently felt that an
optimum concentration of MMT would be 0.125 grams per gallon
(BA-459). This would provide a two to three octane number
improvement in most unleaded blends. While this obviously does
not replace the eight to ten octane number loss with lead removal,
it is of great benefit in reducing the degree of increased pro-
cessing severity necessary. Thus, the use of a non-lead addi-
tive, specifically MMT, in conjunction with some increase in
process severity is the refiners second control strategy.
6.2.6 Water Control Strategies
The discharge of wastewater from, refineries was in-
cluded in this study on the basis of the primary and secondary
impact of its control. The control strategies vary according
to regulatory scenario and stringency. Included in Table 6.2-1
(Regulatory Scenarios 22-25) are the control strategies that
were used for this study.
-77-
-------
The control strategies developed vary from primary
level treatment to tertiary level treatment. The State Water
Laws enforceable in 1974 called for either primary treatment of
refinery wastes or secondary treatment. The Federal Effluent
Guidelines require secondary treatment for refineries by 1977
and tertiary level treatment by 1983.
6.3 Engineering Calculation Methodology
This section describes how the primary energy penalties
were calculated. Basically, for each pollutant this involved
first determining which environmental controls had primary.energy
impacts. (Secondary energy impacts are discussed in Section 8.0).
Then, the number and size or capacity of the control units were"
estimated. For 1974, this involved gathering information on the
extent of application of each control method. For 1980 and 1985
this involved estimating control usage based on projected re-
finery growth and projected regulatory scenarios. After deter-
mining the number and size of the controls, the energy penalties
were estimated by using energy consumption data for each type of
control. Appendix B, Form 5 contains the results of the energy
penalty calculations.
6.3.1 Particulates
In calculating energy penalties for the control of
particulate emissions, the only process unit to consider is the
fluidized-bed catalytic cracker. Typical data on an FCC indicate
that approximately 0.242 Ib of particulates/bbl feed are emitted
for uncontrolled conditions (EN-071). Using this figure as a
basis, the energy penalty calculation was a four step process.
-78-
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1) Check the specific control regulation
(see Appendix A) for the AQCR under
consideration and determine the allow-
able emission rate.
2) From data on refinery capacity and
FCC throughput for that region, cal-
culate the uncontrolled emission rate
using 0.242 as the base figure.
3) Using the rates calculated in the pre-
vious two steps , determine percent col-
lection efficiency necessary to meet
the specific control regulation.
4) The necessary control efficiency will
determine which control strategy mix
will satisfy the regulation. For each
satisfactory control strategy mix cal-
culate the required capacity and energy
consumption. Typical power requirements
are given in.Table 6.3-1.
6.3.2 Sulfur Dioxide
In calculating energy penalties for the control of
sulfur dioxide emissions, there were three basic process units
to consider: process heaters and boilers, the fluidized-bed
catalytic cracker, and the sulfur recovery plant. The sulfur
dioxide emissions from each unit are indirectly related to the
others. For example, the increasing demand for low sulfur fuels
-79-
-------
TABLE 6.3-1. TYPICAL ENERGY REQUIREMENTS FOR
POLLUTION CONTROL EQUIPMENT
Electricity
(Kwh/unit)
Thermal
(Ib/unit)
Multiple Cyclones
Scrubbers (103 scf)
Electrostatic Precipitators (103 scf)
High Voltage
Low Voltage
Hydrodesulfurization (bbl)
0.202
0.003 - 0.010
0.0002-0.0007
Distillates
Gas Oil/FCC Feed
Residual Oil
Arnine Gas [Sweetening] (scf)
Glaus Unit (Ib Feed)
SCOT Unit (Ib Feed)
2.55
2.55
4.4
3,000
0.0025
0.0053
123,000
123,000
64,000
-
68.34
50.5
50.5
2.7
0.25
(0.817)*
0.10
* parenthesis indicate production
-80-
-------
necessary to meet S02 emission limitations for industrial and
utility process heaters and boilers has resulted in increasing
hydrodesulfurization of gas oils. The sulfur rich off-gas from
an HDS unit ultimately passes through an amine treatment unit
and arrives at a sulfur recovery plant, thus increasing S02
emissions at this point.
Therefore, each of the five proposed control strategy
mixes was drawn as a process flow sheet, detailing the move-
ment of sulfur (Ib sulfur/Mbbl. crude charged) through the
various process units from crude oil input to sulfur recovery.
Such a flow sheet arrangement provided an accurate means of
calculating the process rates and associated S02 emissions for
important refinery units. Each flow sheet was based on the as-
sumption that gas oil is the primary FCC feed and 90% of the
gas oil from atmospheric and vacuum distillation is used for
this purpose. In addition, each flow sheet was adjusted to
reflect the product character of each region according to data
on FCC capacity (bbl FCC feed/bbl crude charged).
A standard procedure was followed in calculating
energy penalties:.
1) Check the applicable control regulation
(see Appendix A) for the AQCR under con-
sideration and determine the allowable
emission rates for process heaters and
boilers, FCC units, and sulfur recovery
units.
2) From data on refinery capacity and FCC
throughput for that region, use a control
strategy mix flow sheet to calculate the
emission rates for process heaters and
boilers, FCC units, and sulfur recovery
units.
-81-
-------
3) Using the emission rates calculated in
the previous two steps, determine which
of the five control strategy mixes meets
the applicable regulations. Failure to
meet the emission limitation in only one
of the three main areas of concern, elimi-
nates a control strategy mix from considera-
tion in that AQCR.
4) For each suitable control strategy mix
calculate the required capacity and energy
consumption. Typical power requirements
are given in Table 6.3-1.
It should be noted here that hydrodesulfurization of
fuel oils results in lowering the heating content of the fuel.
The loss in heating value varies with process severity, but
is in the neighborhood of 2-3 percent of the fuel's total
heating value. However, this loss in heating value is not a
primary energy penalty as the penalty is defined in this report.
For this reason, this loss is not included in calculating the
hydrodesulfurization energy penalty.
6.3.3 NO -Engineering Calculation Methodology
X ' " "" ' ' " ' - -r" __ - ._._.' I -T-H-_J_ ....... _ **-*
Those NO control units used in 1974, and projected to
A.
be used in 1980 and 1985, which result in primary energy penalties
are exhaust gas recirculation and two-stage combustion. Federally
enforceable regulations for NO emissions from fuel combustion
X
apply only to units with greater than 250 million Btu/hr heat
input. A description of how the energy penalties associated
with NO control were calculated follows.
-82-.
-------
Refineries with greater than 100 MBPD capacity may
be expected to have steam generators with greater than 250
million Btu/hr capacity. For each Census Region for 1974,
1980 and 1985, the capacity of refineries in the region greater
than 100 MBPD was totaled. Using a factor developed to estimate
the energy penalty for exhaust gas recirculation (20 Btu/bbl of
crude capacity) and two-stage combustion (80 Btu/bbl of crude '
capacity) overall regional energy, penalties were calculated
(TH-116). Penalties were calculated only for those units which
burned oil since gas.fired units generally meet emission limits
without control. See Appendix B, Forms 5, Regulatory scenarios
11, 12, 13, and 14 for tabulated results. The penalties are
reported as Purchased Oil.
6.3.4 Hydrocarbon-Engineering Calculation Methodology
The hydrocarbon control techniques used in 1974 and
projected t.o be used in 1980 and 1985 which result in primary
energy penalties are the vapor recovery units used for loading
rack control and vapor blowdown flares. A description follows
of how the energy penalties associated with each of these control
techniques was calculated.
For vapor recovery systems used to control loading rack
emissions an average system energy requirement per thousand
gallons of motor gasoline loaded was first calculated. This
number, 2 Kw-hrs per 103 gallons, was calculated from results
published in a previous Radian report (BU-217). For the regions
requiring control this number was applied to estimates of the
gasoline output transported by tank car or tank truck and the
resulting energy penalty was determined. Appendix B, Form 5,
Regulatory Scenarios 15 through 18 present the results. The
penalties are reported as Purchased Electricity.
-83-
-------
For the flaring of vapor blowdown an energy requirement
per pound of hydrocarbon flared was first determined. From results
published in the literature an average energy requirement for
steam of 560 Btu per pound of hydrocarbon flared was estimated
(DA-069). Also, an average number was obtained for the quantity
of hydrocarbon flared at refineries, 0.19 percent of refinery
feed (KL-081). By applying these numbers to regional refinery
throughputs, the energy penalties due to vapor blowdown flaring
were calculated.
6.3.5 Lead-Engineering Calculation Methodology
The calculation of energy penalties attributable to
lead phasedown required two steps:
determine the process changes required
to raise the pool octane enough to offset
the removal of lead and
determine the incremental energy con-
sumption of these process changes.
The first step was accomplished by the interpretation and
regionalization of the results of The Impact of Lead Additive
Regulations on the Petroleum Refining Industry as prepared for
the EPA by Arthur D. Little, Inc. (LI-151). Incremental energy
consumption was determined by the use of utilities factors taken
from the literature and by heat balances around the units
concerned.
The A.D. Little report was one of a three volume study
which examined the impacts of lead, sulfur in gasoline, and
S02 regulations on petroleum refining. In the course of these
-84-
-------
studies, a linear programming (LP) computer model of the
industry was made based on six regional cluster models. These
models were carefully chosen and calibrated to simulate the
actual industry. The complicated gasoline blending values and
lead susceptibilities were submitted both to the refiners and
the lead additive manufacturers for review and comment. This
resulted in a sophisticated program which could adjust the
internal processing to make various product specifications.
This report consumed much time and effort, and it would not have
been feasible to duplicate this work in the time frame of this
energy penalty study. A. D. Little did not emphasize the energy
consumption aspect, but was concerned with the overall impacts
of capital expenditures, operating expenses, and energy penalties.
The results of their LP model were the basis of our more detailed
examination of the energy penalties. Examples of the LP model
output as adapted to Region 2 are shown in Tables 6.3-2 and
6.3-3. These present the unit processing scheme and gasoline
blending results, respectively. ADL's cases were defined as:
Case A - No restrictions on the use
of lead additives,
Case B - Manufacture of unleaded
gasoline to meet the market demand, and
Case C - EPA's proposed lead phasedown.
The second phase of the calculation required the
application of unit energy consumption factors to the increased
processing detailed above. Four basic refinery units were
involved:
-85-
-------
TABLE 6.3-2. A. D. L.'s L. P. MODEL RESULTS - PROCESSING AND VARIABLE OUTPUTS
East Coast Cluster - Region 2
CO
Variable output
Gasoline Mbbl/CD
LPG Mbbl/CD
Sulfur tons/CD
SOX emissions tons/CD
Processing Mbbl/CD
Reforming
Total
For gasoline
Severity for gasoline
Catalytic cracking
Untreated feed
Hydrotreated feed
Total
Conversion Vol Z
Hydrocracking
High severity
Medium severity
Total
Isomerizatlon of light naphtha
Once through
Recycle
Total
Alkylation (product basis)
Hydrogen manufacture(MMSCF/CD)
Desulf urizatlon
Light naphtha (isom. feed)
Medium naphtha (ref. feed)
Cat cracker cycle oil
Straight run distillate
Total
Scenario A
1977
110.972
4.634
112
52
47.1
43.6
90.0
55.2
55.2
80.4
8.2
5.2
13.4
9.5
32.9
36.1
3.4
18.0
57.5
1980
111.524
3.954
111
52
47.0
43.5
90.0
58.2
58.2
78.3
3.9
9.5
13.4
9.5
29.9
37.9
5.3
12.4
55.6
1985
110.785
3.981
109
54
47.0
43.5
90.1
56.8
56.8
79.1
4.1
9.4
13.5
9.5
30.6
37.7
4.5
10.6
52.8
Scenario B
1977
. 110.424
4.402
103
50
47.9
44.4
92.3
53.4
53.4
84.4
9.0
9.0
10.5
25.7
37.6
0.7
20.2
58.5
1980
109.817
4.910
104
51
45.8
42.3
95.6
58.5
58.5
81.9
6.7
2.3
9.0
0.6
0.6
11.1
24.6
0.6
36.3
2.4
15.3
54.6
1985
106.915
6.119
114
59
46.5
43.0
100.0
62.2
62.2
83.6
1.4
8.0
9.4
0.1
7.6
7.7
12.9
20.7
7.7
36.5
4.1
12.9
61.2
Scenario C
1977
109.109
5.579
104
51
47.8
44.3
97.0
55.6
55.6
85.0
5.4
3.8
9.2
0.2
0.2
11.4
24.2
0.2
38.1
0.1
19.7
58.1
1980
108.723
5.561
106
54
45.8
42.3
98.0
60.5
60.5
84.1
4.2
5.1
9.3
3.2
0.2
3.4
12.6
22.7
3.4
35.8
2.3
13.7
55.2
1985
106.915
6.119
114
59
46.5
43.0
100.0
62.2
62.2
83.6
1.4
8.0
9.4
0.1
7.6
7.7
12.9
20.7
7.7
36.5
4.1
12.9
61.2
-------
TABLE 6.3-3. A. D. L.'s L. P. MODEL RESULTS - GASOLINE BLENDING
CO
^J
l
Cluster: East Coast -
Region 2
Scenarios
Premium Pool
Research octane
Motor octane clear
Volume Mbbl/CD
Lead CC/USG
Sulfur ppm
Composition LV%
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alky late
Light hydrocrackate
Isomerized light naphtha
Straight run
Total
Regular Pool
Research octane clear
Motor octane clear
Volume Mbbl/CD
Lead CC/USG
Sulfur ppm
Composition LV%
BTX raffinate
Butanes
90 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alky late
Light hydrocrackate
Isomerized light naphtha
Natural gasoline
Straight run
Total
Year
1977
A
92.7
83.5
29.96
3.00
686
8.0
0.4
59.4
23.0
9.2
100.0
85.5
77.6
72.13
2.20
187
2.0
7.0
50.4
16.5
1.8
17.6
4.7
100.0
B
92.7
83.3
16.56
3.00
568
9.1
7.8
54.3
24.3
4.5
100.0
85.8
77.3
59.63
1.93
424
2.4
7.2
32.2
38.4
19.8
100.0
C
94.9
86.3
16.37
1.53
304
10.9
17.6
28.8
41.7
1.0
100.0
87.7
79.0
58.92
1.32
438
2.4
7.1
19.0
6.8
41.0
5.2
18.5
100.0
1980
A
92.7
83.6
36.80
3.00
448
8.8
21.4
40.9
23.5
5.4
100.0
85.4
77.5
71.37
2.24
373
2.0
6.8
40.3
26.2
2.0
5.0
17.7
100.0
B
92.4
82.8
4.39
3.00
714
6.3
64.5
22.3
6.9
100.0
83.9
75.9
40.64
3.00
350
3.5
7.1
40.1
24.0
25.3
100.0
C
96.6
87.8
4.35
0.97
2
8.0
46.3
41.5
4.2
100.0
88.4
79.5
40.22
1.17
492
1.0
7.4
20.2
2.8
44.7
6.4
17.5
100.0
1985
A
92.8
83.8
44.31
3.00
722
7.7
3.0
61.2
20.2
7.9
100.0
84.5
77.0
64.26
2.71
170
2.2
7.3
55.9
9.1
5.8
19.7
100.0
(Continued)
-------
TABLE 6.3-3. Continued
i
oo
00
I
Cluster: East Coast -
Region 2
Scenarios
Lead- free pool
Research octane clear
Motor octane clear
Volume Mbbl/CD
Sulfur ppm
Composition LV%
BTX raffinate
Butanes
90 RON reformate
95 RON reformate
100 RON reformate
Cat cracker gasoline
(untreated feed)
Alkylate
Light hydrocrackate
Isomerlzed light naphtha
Natural gasoline
Straight run
Total
Total gasoline pool
Research octane clear
Motor octane clear
Volume Mbbl/CD
Lead CC/USG
Sulfur ppm
Year
1977
A
92.0
84.0
8.88
459
8.2
22.6
30.2
29.5
9.5
100.0
88.0
79.7
110.97
2.2A
343
B
92.0
84.0
34.23
3
7.5
24.4
8.7
19.1
18.9
9.1
12.3
100.0
88.8
80.3
110.42
1.49
315
C
93.8
84.0
33.82
136
6.9
2.7
50.3
13.2
4.6
7.7
12.4
2.2
100.0
90.7
81.6
109.11
0.94
324
1980
A
92.0
84.0
3.35
5
7.2
11.0
37.7
25.2
0.6
18.3
100.0
88.0
79.7
111.52
2.42
387
B
93.5
84.0
64.79
369
7.8
28.9
34.0
15.6
4.3
0.9
6.5
2.0
100.0
89.9
81.0
109.82
1.23
376
C
93.5
84.0
64.15
317
7.4
34.9
28.3
12.9
3.9
4.8
6.6
1.2
100.0
91.7
82.5
108.72
0.47
369
1985
A
92.0
84.0
2.22
5
6.6
46.5
25.1
21.8
100.0
88.0
79.7
110.79
2.77
387
B/C
93.8
84.0
106.9
394
0.1
7.3
30.9
34.6
12.1
2.1
6.8
3.9
2.2
100.0
93.8
84.0
106.9
394
-------
Catalytic Reforming Unit (CRU),
Fluid Catalytic Cracking Unit (FCCU),
Alkylation Unit, and
Isomerization Unit.
A literature search was performed to determine the operating
energy requirements of the above, and the results are presented
in Table 6.3-4.
In addition to the normal range of energy consumption
for each unit, it was necessary to determine the incremental
energy required to make a process change, such as increasing
reformer severity from 90 to 100 or increasing the conversion
on the FCCU. On the CRU, literature yielded correlations from
which the increase in reactor temperature required to increase
product octane (or severity) from 90 to 100 could be calculated
(LI-151, GA-182). A heat and -material balance was then performed
to determine the amount of fuel needed to provide the higher
reactor temperatures.
Increasing reformer severity from 90 to 100 results
in a decreasing yield of gasoline. The lower yield of gasoline
per barrel of naphtha charged means that more naphtha must be
processed to produce the same volume of gasoline. Increasing
the rate of naphtha charged necessitates the addition of
more catalytic reformer, isomerization, and alkylation capacity.
The fuel required to process the additional naphtha is considered
a primary energy penalty. Typical yield-severity relationships
are illustrated in Figure 6.2-1.
-89-
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TABLE 6.3-4. UTILITY REQUIREMENTS
O
I
T |i 1 1 1 of Energy
Catalytic Reforming Unit
Fluid Catalytic Cracking
Alkylation
I-somerization
Fuel (Oil or Gas)
MBTU/bbl.
Max.
400
350
1070
684
Mln.
200
0
0
50
A\7f .
308
100
410
100
Steam
' Ibs./bbl.
Max.
85
92
950
65
Mln.
0
-73
0
25
AVP .
25
-30
425
35
Electricity
kWhr/bbl.
Max
6.0
6.0
8.8
4.6
Min.
0.7
0.2
0.5
1.0
Ave .
3.4
1.8
4.0
1.5
Sources: RA-119, GA-182, DI-070, BL-078
-------
Process changes were also necessary on the FCCU's,
primarily in the form of increased conversion, which is defined
as the volume percent of the feedstock that is converted to
gasoline and lighter components. This helps in three ways:
The higher reactor temperatures
necessary to achieve higher conversion
cause an increase in the octane of the
cracked gasoline.
More cracked gasoline is produced,
which helps offset the yield loss
on the CRU.
More reactive propylene and butylene
are produced, which can be converted
to high octane gasoline by alkylation.
These benefits are balanced by an increase in the catalytic
coke yield, which typically ranges from five to seven weight
percent of the feed. All of this coke is burned off in the
regenerator providing process heat for the reactor section and
usually making steam by waste heat exchange or in a CO Boiler.
That portion of the heat liberation from coke burning that goes
to increased process heat plus the incremental heat loss in flue
gas out the stack can be considered an energy penalty. Typically,
a 10 volume percent increase in conversion will cause an increase
in coke yield of 0.9 weight percent of the feed (GA-182).
Once the above two steps were completed, it was merely
necessary to multiply the energy consumption factors determined
in step two by the processing changes called for in step one.
The sum of the penalties for each process was then recorded in
Form 5, Appendix B.
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It was determined that there was no energy penalty
applicable to lead phasedown in 1974. While considerable ex-
penditures of capital funds had been made to prepare for unleaded
gasoline production by that time, the demand in 1974 was so low
that no pool clear octane increase was required. This can be
easily understood by examining Figure 6.3-1, which shows gasoline
consumption by grades (AA-022). It can readily be seen that
the decrease in market share of leaded premium gasoline, which
began with the introduction of lower compression ratios in new
cars in 1971, far outweighed the impact of unleaded gasoline in
1974. In fact it is not until 1978 that the combined premium
and unleaded market reaches the level of leaded premium in 1970,
at which time the clear pool octane requirement begins to increase
rapidly. Thus, it can be said that the production of unleaded
gasoline caused no energy penalty in 1974.
The only clear alternative to increased processing
severity is the use of a non-lead additive, probably MMT.
Calculations for such an eventuality were made using reported
MMT susceptibility data (UN-072, BA-459). These data indicated
that a two to three octane number improvement could be achieved
by adding 0.125 grams per gallon of MMT to the typical unleaded
blend. This effect was used to offset part of the processing
severity, and the application of energy consumption factors
was then identical to the above cases.
6.3.6 Water-Engineering Calculation Methodology
The wastewater control techniques used in 1974 or
projected to be used in 1980 or 1985 which result in energy
penalties include primary, secondary, and tertiary treatment.
A description follows of how the energy penalties associated
with each of these control systems was calculated.
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Figure 6.3-1. Gasoline Consumption by Grades
-*H*- Regular
Premium
=* ="=" Unleaded
70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85
YEAR, 19
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Primary level wastewater treatment for refineries
was assumed for this study to include sour water strippers,
oil-water separators, and dissolved air flotation units. Sour
water stripping and dissolved air flotation requires energy.
The use of oil-water separators, however, results in a net
energy recovery since the oil separated in the units is recycled
back to the refinery for processing.. The energy requirements
for sour water stripping were calculated from data reported in
the literature (KL-032). Credit for the energy recovered (as
steam) from the processing in Glaus plants of the recovered HzS
from the strippers is accounted for in the desulfurization
calculations. The estimated energy penalty for sour water
stripping is 3.2 million Btu per 103 barrels of refinery
throughput. For dissolved air flotation the energy requirement
calculated from literature data is 104,000 Btu per 103 barrels
of refinery throughput (PR-121). The oil water separator results
in a recovery of 770,000 Btu per 103 barrels of refinery through-
put based on calculations made from literature data (EN-407).
The net energy penalty of primary level wastewater treatment is
calculated to be 2.5 million Btu per 1Q3 barrels of refining
capacity. This number includes wastewater pumping costs.
Secondary level wastewater treatment was assumed to
include, in addition to primary level treatment, equalization,
coagulation, floculation, and carbonaceous waste removal.
Carbonaceous waste removal could be trickling filters, unaerated
lagoons, aeration towers, aerated lagoons, or activated sludge.
Based on literature data the energy penalty for equalization is
162,000 Btu per 103 barrels refinery throughput. For coagulation
and floculation it is 16,200 Btu per 103 barrels throughput.
The energy requirements for carbonaceous waste removal depend
upon what process is used. Both trickling filters and unaerated
lagoons require no energy. From literature data the energy
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requirement for aeration towers was calculated to be 30,000 Btu
per 103 barrels and for activated sludge the requirement is
240,000 Btu per 103 barrels (PR-121).
Tertiary level wastewater treatment includes, in addi-
tion to secondary level treatment, activated carbon adsorption
and wastewater flow reduction. The reduction in wastewater
.flow results in a net energy savings since less water is
treated per barrel of crude throughput. An average flow of
32.5 gallons of wastewater per barrel of crude throughput was
assumed for primary and secondary treatment plants. For tertiary
treatment a flow of 20 gallons per barrel was assumed (EN-407).
Activated carbon adsorption requires approximately 20,000 Btu
per 103 barrels of crude throughput according to literature
data (PR-121). This does not include regeneration of the carbon.
Since the adsorption system would operate as a polishing step,
regeneration of the spent carbon would not be economical.
6.4 Regionalization
The energy penalties are regionalized because they are
calculated from regionalized data. Regional regulations were
applied to regional refinery configurations in order to develop
the necessary control strategies. The energy consumption of
these control strategies were determined on a per barrel basis,
which could then be converted to a regional total by applying
the regional crude running projections.
6.5 Allocation Among Fuel Types
The allocation of the calculated energy penalties
among the fuel types was straightforward. The present and pro-
jected shortages of natural gas make it very doubtful that this
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fuel could assume-additional load. Therefore, it must naturally
be assumed that fuel oils will provide the additional process
heat, as well as energy to generate any incremental steam re-
quirements. It was assumed that any additional electricity would
be purchased rather than self-generated. The tremendous capital
necessary to build power plants would be difficult to generate
in this time frame when refiners will be hard pressed to meet
the demands of environmental improvement as .well as energy in-
dependence .
Some energy penalties (or credits) were expressed in
terms of catalytic coke when they involved changes on the
Fluid Catalytic Cracking Units. Since this self-generated
fuel must be burned in the FCC Regenerator, it is unique and
not interchangeable with other fuel sources.
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7.0 SUMMARY OF RESULTS
This section summarizes the results of the primary
energy penalty calculations described in Section 6.0 for the
years 1980 and 1985. The penalties are totaled for Census
Regions 1 through 9 according to the six pollutants considered-
pcirticulates, NO. S02, HC, lead, and wastewater. Three ,
X
cases were evaluated. They were chosen to represent the mini-
mum, maximum, and most likely energy penalties due to projected
and existing federally enforceable regulations for the subject
years. Summaries of each of these three sections follow.
7.1 Minimum Energy Penalty Case
The results of the minimum penalty case for 1980 and
1985 are presented in Table 7.1-1. The numbers for the mini-
mum penalty case for each pollutant were generated from the energy
penalty data on the Form 5's in Appendix B. For each region and
each pollutant the control strategy mixes and regulatory scenarios-
with the lowest energy requirements were totalled. The numbers
for that region for each pollutant were then added to the'Other
eight regional numbers for each pollutant to give the totals
shown in Table 7.1-1.
Table 7.1-1 shows that lead control is the largest
energy consumer of the pollutants covered in the minimum penalty
case. .For 1980 lead control is approximately 49 percent of the
total energy penalty and about 2 percent of the total daily
refinery energy consumption. For 1985 lead control accounts for
slightly over 58 percent of the total daily energy penalty and
over 3 percent of the total daily refinery energy consumption.
The projected baseline daily energy consumption for the re-
fining industry for 1980 is 11.65 x 1012 Btu/day and 13.43 x
1012 Btu/day for 1985.
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TABLE 7.1-1. MINIMUM ENERGY PENALTIES
REGIONS 1-9
1980 Minimum
Energy Penalty
Pollutant (106 Btu/day)
Particulates 404
NO 407
X
S02 127,880
EC 6,570
i
vO
*f Lead 248,550
Water 121,855
TOTAL PENALTY 505,666
Percent of 1980
Baseline Energy
Consumption (%)
0.003
0.003
1.097
0.056
2.133
1.046
4.338
1985 Minimum
Energy Penalty
(106 Btu/day)
487
512
154,178
8,044
439,173
151,880
754,274
Percent of 1985
Baseline Energy
Consumption (%)
0.004
0.004
1.148
0.060
3.270
1.131
5.617
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7.2 Maximum Energy Penalty Case
The results of the maximum penalty case for 1980 and
1985 are presented in Table 7.2-1. Data from the Form 5's
in Appendix B were used to generate the numbers for the maximum
penalty case. For each region and each pollutant the control
strategy mixes and regulatory scenarios with the largest energy
requirements were totalled. Then the numbers for that region
for each pollutant were added to the other eight regional
numbers for each pollutant to give the totals shown in Table 7.2-1
Table 7.2-1 shows that S02 control is the largest
energy consumer of the pollutants covered in the maximum penalty
case. For 1980,S02 control is roughly 67 percent of the total
daily energy penalty and about 9 percent of the daily refinery
energy consumption. For 1985, SOz control accounts for approxi-
mately 59 percent of the energy penalty and is equivalent to
almost 10 percent of the daily refinery energy consumption. The
projected baseline daily energy consumption for the refining
industry for 1980 is 11.65 x 1012 Btu/day and 13.43 x 1012
Btu/day for 1985.
7.3 Most Likely Energy Penalty Case
The results of the most likely energy penalty case for
1980 and 1985 are presented in Table 7.3-1. Data from the Form
5's in Appendix B were used to generate the numbers for the most
likely penalty case. For each region and each pollutant, the
control strategy mixes and regulatory scenarios judged to be the
most likely case for 1980 and 1985 based on available information
were totalled. Then the numbers for that region for each pollu-
tant were added to the other eight regional numbers for each
pollutant to give the totals shown in Table 7.3-1.
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TABLE 7.2-1. MAXIMUM ENERGY PENALTIES FOR 1980 AND 1985
REGIONS 1-9
Pollutant
Particulates
NO
X
SO 2
i
I ' HC
i
Lead
Water
TOTAL PENALTY
1980 Maximum
Energy Penalty
(10 Btu/day)
11,171
2,406
1,091,977
6,587
376,173
145,040
1,633,354
Percent of 1980
Baseline Energy
Consumption (%)
0.096
0.021
9.373
0.057
3.229
1.245
14.021
1985 Maximum
Energy Penalty
(106 Btu/day)
12,738
2,760
1,319,781
8,066
745,378
161,283
2,250,006
Percent of 1985
Baseline Energy
Consumption (%)
0.095
0.021
9.827
0.060
5.550
1.201
16.754
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TABLE 7.3-1. MOST LIKELY ENERGY PENALTIES FOR 1980 AND 1985
REGIONS 1-9
Pollutant
Particulates
NO
X
S02
HC
Lead
Water
TOTAL PENALTY
1980 Most Likely
Energy Penalty
(106 Btu/day)
416
560
375,269
6,570
362,320
145,040
890,175
Percent of 1980
Baseline Energy
Consumption (%)
0.004
0.005
3.221
0.056
3.110
1.245
7.641
1985 Most Likely Percent of 1985
Energy Penalty Baseline Energy
(106 Btu/day) -Consumption (%)
504
852
495,413
8,044
662,590
161,283
1,328,686
0.004
0.006
3.689
0.060
4.934
1.201
9.894
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Table 7.3-1 shows that SOa control is the largest
energy consumer for the most likely penalty case in 1980.
SOa control is 42 percent of the total energy penalty for that
year and is equivalent to a little over 3 percent of the daily
refinery energy consumption for 1980. For 1985, lead control
is the largest energy consumer for the most likely case. Lead
control is almost 50 percent of the total energy penalty for
the most likely case for 1985 and is equal to about 5 percent
of the daily refinery energy consumption. The projected baseline
daily energy consumption for the refining industry for 1980 is
11.65 x 1012 Btu/day and 13.43 x 1012 Btu/day for 1985.
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8.0 SECONDARY IMPACT INDICATORS
For this study secondary energy penalties were classi-
fied as either recurring or non-recurring impacts. Recurring
impacts are those linked to materials consumed during the
operation of a pollution control system, such as catalyst or
chemicals. Non-recurring secondary impacts refer to the one-time
energy costs of materials which go into the manufacture of a
control system as well as the energy expended in its construction.
Actual determination of the secondary energy penalties associated
with the environmental controls mentioned in Section 6.0 was
beyond the scope of this study. Instead, indicators of the
secondary penalties were provided. The remainder of this sec-
tion discusses the secondary impact indicators developed for
each pollutant.
8.1 Particulate Secondary Impact Indicators
In calculating the secondary impact indicators for
the control of particulate emissions there were two non-recurring
impacts and two recurring impacts. Also included were three
descriptive impacts, that is, indicators of FCC throughput,
number of FCC units in operation, and particulate collection
efficiency for the control strategy mix under consideration.
The two non-recurring impacts are those associated
with the actual process units (i.e., the electrostatic precipi-
tator or wet scrubber). The two recurring impacts were ammonia
requirement for ESP feed conditioning and make-up water for wet
scrubbing. Assuming that 45% of the operating electrostatic
precipitators need conditioning with ammonia (average concen-
tration of 25 moles NHs/103 moles feed gas), then a base figure
for the ammonia requirement is 1.12 Ib NHa/MMscf. For wet
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scrubbing, the make-up water base figure was assumed to be 51.35
gal HaO/MMscf (MA-519). From these two base figures and data on
FCC throughput, the recurring impacts for control of particulate
emissions can be readily calculated.
8.2 Sulfur Dioxide Secondary Impact Indicators
In calculating the secondary impact indicators for
the control of sulfur dioxide there were seven non-recurring
impacts and seven recurring impacts. All secondary impact
indicators were determined according to equipment through-
puts .
All seven non-recurring impacts represent new or
additional capacities for various process units. All capacities
quoted are annual incremental throughputs for a specified region
except for the FCC flue gas scrubber. Since the FCC scrubber
was the only process unit unique to a region (as determined by
bbl FCC feed/bbl crude charged), it seemed appropriate to quote
the average size of a scrubber. To determine annual incremental
throughputs for a region, production data for that region (see
Appendix B, Form 2) and FCC flue gas base rates of 99,167 scfm
(wet basis) and 78,973 scfm (dry basis) were used (DA-069).
Note also that annual incremental throughputs for Glaus units
and SCOT units are identical. This is a common sizing practice
as reflected in technical literature.
All the recurring impacts represent catalyst and
chemical requirements for various process units. All seven
recurring impacts are annual figures and were calculated
according to Table 8.2-1.
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TABLE 8.2-1. CHEMICAL AND CATALYST REQUIREMENTS FOR S02 CONTROL
(Ib/unit)
Catalyst
Distillate HDS (bbl) 0.001
Gas Oil/FCC Feed HDS (bbl) 0.0021
Residual Oil HDS (bbl) 0.5
Scot Unit (ton Sulfur) 0.11
Chemicals
Amine (MMscf Feed) . 2.5
Diisopropanol Amine (MMscf Feed) 2.5
Scrubber Liquor (MMscf) 8.33 (gal)
References: AD-033, MA-519, PF-008
8.3 N0x Secondary Impact Indicators
The control of N0v emissions from fuel combustion
X
in refineries by flue gas recirculation results in a non-recurr-
ing secondary impact. Two-stage combustion does not require
the use of any additional control systems and so has no secondary
impact associated with it. There are no recurring impacts
associated with either flue gas recirculation or two stage
combustion.
The secondary impact of flue gas recirculation is the
material requirement for the equipment needed to recirculate a
portion of the flue gas back through the burners.
8.4 Hydrocarbon Secondary Impact Indicators
The control of hydrocarbons from tank car/truck
loading racks, oil-water separators, vapor blowdown, and stor-
age tanks results in significant non-recurring secondary impacts.
There are no recurring impacts associated with the control of
these sources.
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For tank car/truck loading rack control, the secondary
impact indicators chosen are the material requirements for the
vapor collection system and vapor recovery unit. For oil-water
separator control the secondary impact indicators are the float-
ing covers required for the separator. The secondary impact
indicators used for vapor blowdown control are the piping and
associated equipment for blowdown collection and the flares used
to combust the hydrocarbon vapors. For storage tank control
the secondary impact indicators are the pressure tanks and float-
ing roofs used. Appendix B, Form 6, Regulatory Scenarios 15
through 18 present the secondary impact indicators for 1974,
1980, and 1985.
8.5 Lead Secondary Impact Indicators
The removal of lead additives from motor gasoline
can be compensated for by increased processing severity as
detailed in Section 7.2. Part of this increased severity must
come through the construction of more Catalytic Reformers,
Isomerization Units, and Alkylation Units. The required addi-
tional capacity for each of these was tabulated as a one time
secondary impact in Form 6 of Appendix B.
There are also recurring requirements for chemicals
and catalyst associated with the new capacity, and increased
consumption rates on existing units due to more severe process-
ing conditions. The major substances involved are:
Catalytic Reformer - reforming catalyst,
HDS catalyst
Isomerization - catalyst, and
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Alkylation - sulfuric acid, hydrofluoric
acid, and caustic.
In addition to these, a recurring requirement for MMT is pro-
jected for Control Strategy Mix No. 2. Balancing all of these
is a credit due to the decreasing demand for lead alkyIs. The
requirements of all the above are tabulated in Form 6, Appendix B,
8.6 Water Secondary Impact Indicators
The control of refinery wastewater discharges by
secondary or tertiary level treatment results in significant
non-recurring secondary impacts. Only tertiary level wastewater
treatment results in a recurring secondary impact.
The facilities used for secondary level wastewater
treatment were mentioned in Section 6.2.6. The secondary impact
indicators chosen for secondary wastewater control were the
number of treatment plants controlled at this level within a
region as well as their combined wastewater throughput.
The facilities used for tertiary level wastewater
treatment were mentioned in Section 6.2.6, also. The secondary
impact indicators chosen for tertiary level treatment were the
number of treatment plants controlled at this level within a
region as well as their combined wastewater throughput. Ter-
tiary wastewater treatment also has a recurring secondary impact.
The activated carbon adsorption unit requires that makeup carbon
be supplied periodically. The indicator chosen was the number
of tons of carbon consumed per year per region.
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9.0 DISCUSSION
This section discusses changes in three variables
which might increase or decrease the energy penalty due to
environmental regulations for the petroleum refining industry.
The impact of these variables on the energy penalties calculated
in this report cannot be quantified because of limitations in
the scope of work. Therefore, a qualitative discussion is pre-
sented on these three variables: possible changes in the
refining industry makeup; possible changes in environmental
regulations; and possible changes in environmental control
methods.
9.1 Possible Changes in the Refining Industry Makeup
There are several trends in the petroleum refining
industry that are concerned with maintaining environmental qual-
ity, conserving energy, and meeting consumer demands. A brief
description of these changes and a discussion of their effects
on the energy penalties follows.
A major trend has been toward an increasing dependence
on foreign crude oils which generally contain a higher percentage
of sulfur than domestically produced oil. To meet federal and
state SOz emission standards, improved methods of hydrodesulfur-
ization and sulfur recovery are being developed. These sulfur
bearing crudes also tend to be corrosive, consequently many
processing modifications are necessary before most domestic re-
fineries can handle the high sulfur crudes. The result of having
to install hydrodesulfurization and sulfur recovery equipment is
an increase in both primary and secondary energy penalties for
the refining industry.
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Another refining industry change is the direct result
of the federally imposed schedule for lead phasedown in gasoline.
Expansion of processing units which produce high octane blending
stocks, such as alkylation and catalytic reforming units, may be
anticipated to meet the demand for unleaded gasoline. Although
polymerization is another process capable of producing high
octane blending stocks, it will probably be of little significance,
since olefins have become an increasingly important petrochemical
feedstock. The result of this change will be an increase in both
primary and secondary energy penalties.
Still another industry change is the utilization of
improved catalysts. These new catalysts are of the bimetallic
variety and have been found.to be more active and more selective.
Furthermore, a special oxidation catalyst for catalytic crackers
has been developed. This catalyst enables a greater conversion
of CO to C02 at lower temperatures. Through better oxidation,
there is a decrease in the coke laydown on the catalyst resulting
in a higher product yield. This change results in improved
efficiencies and better yields for refineries.
9-2 Possible Changes in Environmental Regulations
Changes in federally enforceable environmental regu-
lations will have a direct impact on the energy penalties of the
refining industry. Of course, a change of regulation which
requires more efficient pollutant removal usually results in
larger energy penalties. One such recent change proposed by the
EPA at the end of 1976 required more stringent S02 control
for new, modified, or reconstructed refinery sulfur recovery
plants. However, this control will result in a net energy
recovery equal to approximately 90,000 barrels of fuel oil
yearly, the EPA reports. Another potential change in environ-
mental regulations is one requiring reduced sulfur levels in
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all fuel oil products from refineries. This regulation would
require additional hydrodesulfurization capacity and would
result in larger primary and secondary energy impacts for
refineries.
The potential also exists for more stringent N0x
emissions standards being proposed for fuel combustion units in
refineries. This would certainly result in increased energy
penalties for refineries, especially if flue gas scrubbing is
required.
Changes in water regulations are also taking shape
and will almost certainly impact the refining industry. Beginning
in September, 1978 and ending no later than December, 1979 is a
phased schedule of proposed toxic effluent regulations which will
be published by the EPA. Control of specific toxic pollutants
in refinery effluents will be mandated. Their control will
probably result in larger primary and secondary energy penalties
for refineries. Compliance will be required of all existing
sources by June 30, 1983.
9.3 Possible Changes in Control Methods
Control technology is continuously evolving with systems
being developed that more efficiently remove pollutants which are
subject to regulation. Many of these systems have application to
pollution abatement in the refining industry or were developed
specifically for refinery use. Their application in refineries
may or may not result in increased energy consumption. Below
is a discussion of these systems and whether or not increased
energy consumption will result from their use.
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9.3.1 Particulates Control Changes
Wet scrubbers and fabric filters both have potential
for particulate removal from cat-cracker flue gas. At least one
refinery source currently employs wet scrubbers on an FCC unit.
Breakthroughs in fabric filter design may open the door for their
application to particulate removal from FCC flue gases. Both
control systems result in primary and secondary energy penalties.
9.3.2 SO2 Control Changes
Possible changes for SOa control methods for refineries
include hydrodesulfurization and flue gas scrubbing. While
hydrodesulfurization will probably be extensively employed in
the near future by refineries, flue gas scrubbing has an uncertain
future. It has good potential, but requires more development
to make it a reliable control. Both of these S02 control methods
result in higher energy penalties.
9.3.3 N0y Control Changes
Currently NOX control in the refinery industry relies on
combustion modification techniques. Possible changes in this con-
trol method due to more stringent NOX standards could mean
implementation of flue gas scrubbing systems. Similar to S02
flue gas scrubbing, certain obstacles concerning operating re-
liability face this technology. Energy penalties would be larger
if this control system were used.
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9.3.4 Hydrocarbon Control Changes
A major control change for hydrocarbons in the future
will probably be design and installation of efficient blowdown
recovery systems. Significant reductions in hydrocarbon blow-
down losses to flares can be realized by a well designed collec-
tion and routing system. This control would result in lower
energy penalties for refineries since less flare operation would
be needed and more product could be recovered.
9.3.5 Lead Control Changes
Non-lead additives to gasoline which could replace
tetra-ethyl. lead as an octane promoter would result in signifi-
cant energy penalty savings for the refining industry. A
magnesium based additive is currently being investigated and
looks attractive on an economic basis. Its environmental impact.
is also being examined.
9.3.6 Water Control Changes
Refinery wastewater control currently centers on
gravity separation followed by secondary biological oxidation.
Carbon adsorption systems will be included in refinery effluent
control by 1983. Other wastewater controls which may have
potential for refinery effluent treatment include reverse
osmosis, electrodialysis, and ion exchange. All of these
systems would result in larger energy penalties for refineries.
However, the energy penalty from the use of these tertiary control
techniques would be minimized because of wastewater flow reduction
schemes which must be implemented by 1983.
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10.0 CONCLUSIONS AND RECOMMENDATIONS
This section presents the conclusions of this study,
discusses conservation opportunities for refineries, and recom-
mends areas of further study related to energy penalties from
air and water pollution regulation.
10.1 Conclusions
The following is a list of conclusions based on the
results which were presented in Section 7.0. Also, presented
after the conclusions is a brief discussion of energy conserva-
tion opportunities. A comparison of the magnitude of the energy
penalties and energy conservation potential for the refining
industry for 1980 and 1985 is included in the discussion.
For 1980 the largest contributors to the total
"Most Likely" energy penalty are S02 control
and gasoline lead reduction. They contribute
42 percent and 41 percent of the total,
respectively.
For 1985 the largest contributors to the
total "Most Likely" energy penalty are S02
control and gasoline lead reduction, again.
They contribute 37 percent and 50 percent
of the total, respectively.
Regulatory stringency has a significant
effect on the energy penalties for the
petroleum refining industry. The maximum
case total energy penalties for 1980 and
1985 are about 3 times as large as the mini-
mum case total penalties.
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10.2 Refinery Conservation Opportunities
The refining industry is one of the largest energy
consumers of the major U.S. industries. There are numerous
energy conservation opportunities within refineries. Equipment
whose modification could result in significant conservation
opportunities within refineries include fired heaters, heat
exchangers, air coolers, pumps and drivers, compressors, frac-
tionating towers, vacuum systems, and steam systems (EC-Oil).
Table 10.2-1 presents an example breakdown of energy consumption
in a refinery (GO-152).
TABLE 10.2-1. EXAMPLE REFINERY ENERGY CONSUMPTION BREAKDOWN
Source Percent of Total (78)
Direct Fired Fuel in Process Heaters 78
Electrical Energy 11
Steam 10
Cooling Water 1
Proper conservation can reduce refinery energy consump-
tion by as much as 10 to 15 percent (EC-Oil). Therefore, based
on numbers used in this study conservation may recover from
60,000 to 90,000 Btu per barrel of crude processed. This com-
pares to the "Most Likely" energy penalties of 50,000 Btu per
barrel for 1980 and 60,000 Btu per barrel for 1985. This com-
parison indicates that for refineries the energy penalties due
to environmental regulations are roughly equivalent to the energy
recovery available from using conservation techniques.
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10.3 Recommendations
Recommended areas of further work center on obtaining
more detailed pollution control equipment information, both
existing and projected, for the refining industry. The primary
sources of data for this report were articles, journals, and
reports published by governmental agencies and the refining
industry. The accuracy of the resulting penalty numbers could
probably be improved if a survey of the refining industry's
current and projected pollution abatement equipment and planned
installations were completed.
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CONVERSION FACTORS
The references used in developing this report
generally stated flows, capacities, weights, etc., in English
measurement units. The following table can be used to convert
these measurements to metric units.
To Convert From
Btu
bbl
gal
ton
Ibs
cm
ft3
psi
g/gal
Btu/bbl
kWh/bbl
Ib/bbl
lb/10s Btu
grain/ ft 3
gal/MMcf
To
kcal
I
a
kg
kg
in
m3
kg/cm2
g/*
kcal/£
kWh/£
kg/£
g/Mcal
g/m3
11 (hm) 3
Multiply By
0.252
159.0
3.785
907.2
0.454
0.394
0.0283
14.223
0.264
0.0016
0.0063
0.0285
18.0
2.29
133.7
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(Cont'd)
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BIBLIOGRAPHY
(Cont'd)
GO-214 Goar, B. Gene, "Today's Glaus Tail Gas Clean-Up
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BIBLIOGRAPHY
(Cont'd)
LU-013 Lund, Herbert F., Industrial Pollution Control Handbook.
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