Gennaro J. (Jerry) Maffia; Professor of Chemical
Engineering and Process Engineering Manager,
Petrochemicals Industry
1
Introduction
Introduction
2
“The ground begins to rumble, then shake. The hero of the film – a lean
excowboy with a square jaw under his hat and a gorgeous brunette on his
arm – reaches out to brace himself against his horse. A smile creases his face
as the rumbling grows louder. Suddenly, a gush of black goo spurts into the air
and splashes down on him, his side-kick and his best gal. They dance with
ecstasy until the music swells and the credits start to roll. Why is our hero so
happy? Because he’s rich! After years of drilling dry holes in every county
between the Red River and the Rio Grande, he finally struck oil.”
Paul R. Robinson
Introduction
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What is petroleum ?
• Petroleum is a thick, flammable, yellow-toblack combustible mixture of gaseous, liquid,
and solid hydrocarbons that occur naturally
beneath the earth’s surface.
• After processing it is usually separated to
fractions, which can be used as fuel, or as raw
material for chemical or petrochemical plants.
Introduction- What is petroleum ?
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What is petroleum ?
• Petroleum produced from a well is not pure
hydrocarbons, it has some impurities including
water, brine, inert gasses, mercaptants,
carbon dioxide, H2S, drilling sands and others.
• It can be classified as light, intermediate or
heavy according to its specific gravity. And as
sweet or sour according to the amount of
sulfur compounds present in it.
Introduction- What is petroleum ?
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Importance of Petroleum
• Petroleum can be refined (fractionated)and
split to it’s components each of which can be
either used directly or processed to give a
wide range of products.
• These products include: fuels, lubricating oils,
solvents, ink, polymers, adhesives, soap,
waxes, alcohols, fertilizers, and a lot others.
Introduction- Importance of petroleum
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Steps of production in nature
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Generation
In oceans:
• Dead animals and plants sank to the bottom
of the ocean.
• Buried under sediments of sand and mud.
• Layers increase in thickness with time.
• Temperature and pressure increase.
• Causing the change to sedimentary rocks.
Introduction- Production of petroleumGeneration, Migration, Accumulation
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Generation
• In absence of oxygen conditions deposits are
changed to kerogen.
• At high temperature (greater than 110oC) and
pressure kerogen is thermally degraded to oil
and gas.
• This process takes hundreds millions of years
to occur.
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Generation
On land:
• dead plants and animals undergo similar processes to
become coal, which is if deeply buried under high
temperature conditions is transformed to gas and
petroleum.
• The factor that determined the transformations is to
gas or oil is the severity of the conditions of which the
organisms are buried the more severer the conditions,
the smaller is the hydrocarbon produced, in extreme
cases methane (natural gas).
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Migration
• Once the deposits are converted to oil it must move from
the source rock to the reservoir to accumulate there to
form reserves that can be exploited by human.
• Migration is controlled by the physical properties of the
sedimentary strata the oil is moving through (permeability,
porosity, etc).
• The driving force is mainly pressure.
• There are two types of migration; primary and secondary.
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Migration
Primary migration
• where the oil is moved from the center of the source rock
to the contact with the reservoir strata.
• The main driving force for primary migration is sediment
compaction due to overburden load.
• Saturated hydrocarbons are preferentially expelled, while
NSO compounds remain preferentially within the pore
space of the source rock.
• Migration of gas is by dissolving in oil or at great depths
where high pressures causes both natural gas and oil to be
a single phase.
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Migration
Secondary Migration
• After the oil has crossed the source/reservoir contact and
entered the reservoir rock.
• The main driving force is buoyancy which is due to the
density difference between oil, gas and water.
• The reservoir rock has much higher porosity and
permeability.
• Since the driving force is buoyancy, the diffusion is in the
upward direction where gas is at the top and oil is below it.
Introduction- Production of petroleumGeneration, Migration, Accumulation
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Migration
Introduction- Production of petroleumGeneration, Migration, Accumulation
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Migration
Introduction- Production of petroleumGeneration, Migration, Accumulation
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Accumulation
• Oil and gas continue to move upwards through permeable
rock until they encounter an impermeable layer of rock.
• The most common traps are anticlines which are culminations
of folds.
• Since the gas is lightest it is at the top of the formation
forming the gas cap, followed by oil then water.
• The trap is formed if impermeable cap rock at the top mainly
clay or salts where there is a very small number of pores or
very small pore diameter that it cannot be entered by the oil
or gas.
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Accumulation
• Very special cases of gas accumulations occur in the form of
so-called gas hydrates.
• These are solid, ice-like compounds whereby water molecules
are arranged in crystal lattices forming cages (called clathrate
compounds).
• Methane molecules are arranged inside these cages. Per unit
volume of reservoir pore space, more methane can be stored
in hydrate condition as compared to free gas.
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Accumulation
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Summary of Crude generation & migration
The following is needed for crude to be produced in
commercially attractive amounts:
1- A source rock (sedimentary type) should be present to be
the source of the oil. (generation step)
2- Sediment compaction or other factor that leads to the
expulsion of petroleum from the source rock to the
reservoir.
3- Presence of a reservoir rock that has sufficient porosity and
permeability to allow for the flow of the formed petroleum.
(migration step)
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Summary of crude generation & migration
4- Structural configurations whereby reservoir rocks form
traps to allow for the accumulation of the oil and gas.
5- Traps should be sealed from the top by impermeable
layers (cap rocks) to prevent petroleum and gas from
leaving the trap. (4, 5 for the accumulation step)
6- The absence of factors that can lead to the destruction
of the geological trap which can cause the release of
the accumulated gas and oil.
Introduction- Production of petroleumGeneration, Migration, Accumelation
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Summary
Introduction- Production of petroleumGeneration, Migration, Accumulation
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History
• First the crude oil was obtained by collecting the oil that
seeped out cracks in the ground or was mined.
• It’s uses were limited to waterproofing ships, as adhesives
in construction and for flaming projectiles.
• Over time the uses of petroleum increased slowly till the
year 1859.
• The invention of countless applications at that date, that
used the fractions of petroleum in their operation caused a
huge increase in the demand for petroleum products.
Introduction- History
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History
• An example is the kerosene lamp and the depletion of
other sources of fuel for lighting such as whale oil.
• Since then the uses of petroleum products have
increased greatly the demand for the production of
larger amounts of petroleum products increased.
• Nowadays it is used to provide fuel, lubricants for all
vehicles and provides raw materials for petrochemical
industry, reaching a point that the stoppage of the
steady flow of petroleum products will lead to a halt in
most of the human activities.
Introduction- History
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Discussion
Discussion
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Characterization of crude oil
• The ultimate goal of oil processing is turning it
into useful products such as fuel, lubricants and
polymers.
• It is important to know the properties of crude oil
to be able to determine the processes needed to
give the desired product.
• Crude assays include two types of information,
bulk properties, and fractional properties.
Discussion- Characterization of crude oil
25
1- Bulk properties
• Bulk properties are properties for the crude as a
whole such as specific gravity, sulfur content,
nitrogen content, pour point, flash point, freeze
point, smoke point, aniline point, cloud point,
carbon residue, boiling point curve, and others.
Discussion- Characterization of crude oilBulk properties
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Important Bulk properties
Discussion- Characterization of crude oilBulk properties
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1- Specific gravity
•
The specific gravity is expressed using the API gravity
(American Petroleum Institute), API= (141.5/SG)-131.5.
• It is the ratio between the density of the crude and that of
water both at 15.6oC.
• It should be noted that the API gravity decreases with
increase in specific gravity.
Discussion- Characterization of crude oilBulk properties
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Specific gravity
Discussion- Characterization of crude oilBulk properties
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Specific gravity
Discussion- Characterization of crude oilBulk properties
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2- Viscosity
• The viscosity is the ability of the fluid to resist shearing forces
mainly during flow, and is due to the frictional forces between
liquid layers.
• It is measures in centistokes or saybolt seconds or redwood
seconds usually at 100oF and 210oF and is the time taken by a
specific volume of liquid to flow through a standardized weir.
Viscosity specifications are different from summer to winter
due to difference in temperature.
Discussion- Characterization of crude oilBulk properties
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3- Viscosity index
• The viscosity index which is the rate of change of viscosity
with temperature. It is high if the rate of change of viscosity
with temperature is high. This property can be improved by
adding specific polymers which act as viscosity index
improvers.
Discussion- Characterization of crude oilBulk properties
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4- Sulfur content
• The sulfur content is expressed as the weight percentage of
sulfur in the crude.
• Crude oils with less than 1% sulfur are called low sulfur
(sweet) crudes, and those with more sulfur than 1% are called
high sulfur (sour) crudes.
• Sulfur containing compounds are mainly mercaptants, sulfides
and polycyclic acids.
Discussion- Characterization of crude oilBulk properties
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5- Pour point & Dew point
• The pour point is a measure of how easy it is to pump the
crude; it becomes of importance in cold weather. It is the
lowest temperature at which crude oil will behave as liquid.
• The dew point is the temperature at which the hydrocarbons
in the gas phase will start to condense out of the gaseous
phase.
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Discussion- Characterization of crude oil- Bulk properties
6- Bubble point & Flash point
• The bubble point is the temperature at which the liquid
hydrocarbon begins to boil and form vapor bubbles. It should
be the same as the dew point for pure components but for
mixtures it is different as boiling occurs on a range of
temperatures.
• The flash point is the lowest temperature at which there is
sufficient vapor is produced above the liquid to form an
explosive mixture with air, which can cause ignition if a spark
is present.
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7- Fire point & Freeze point
• The fire point is a temperature well above the flash point
where the products can catch fire easily.
• The freeze point is the temperature at which the
hydrocarbons solidify at atmospheric pressure. It should be
noted that it is different from the pour point as reaching the
pour point will make the oil very viscous that it will not flow
under the effect of gravity but is still a liquid.
Discussion- Characterization of crude oilBulk properties
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8- Smoke point & Cloud point
• The smoke point is the maximum height of a smokeless flame
from burning a fuel measured in meters.
• The cloud point it the temperature at which waxes start to
crystallize and separate from the solution when cooling.
Discussion- Characterization of crude oilBulk properties
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9- Aniline point & TBP curve
• The aniline point represents the minimum temperature for
complete miscibility of equal volumes of aniline and crude oil,
it is an important property of diesel fuels and a low aniline
point indicates the presence of a larger amount of aromatics.
• The true boiling point curve is the boiling point of the oil
fraction versus the fraction of oil vaporized.
Discussion- Characterization of crude oilBulk properties
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10- C residue 7 Heating value
• The Conradson carbon residue is a measure of the coke
forming tendency of oil. It is determined by destructive
distillation of oil to elemental carbon in absence of air,
expressed as a weight percentage of the original sample.
• The heating value is the amount of heat released from
burning a unit mass of the oil. It can be higher heating value
or lower heating value depending on whether the heat of
vaporization of the produced water from combustion is
subtracted.
Discussion- Characterization of crude oilBulk properties
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Properties of crude from different locations
Discussion- Characterization of crude oilBulk properties
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2- Fractional properties
• Bulk properties provide a quick understanding of the type
of crude as a whole.
• Fractional properties provides the properties of a specific
boiling point range.
• Fractional properties usually include properties for
paraffins, naphthenes, and aromatics contents, sulfur, and
nitrogen contents for each boiling point range.
• And other properties each specific for a product such as
octane number for gasoline and smoke point for kerosene
and diesel.
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Important fractional properties
Discussion- Characterization of crude oilFractional properties
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1- Octane number
• The octane number is a measure of the knocking properties
of a fuel (gasoline). In other words it is a measure of how
difficult is it for the fuel (gasoline) to self ignite before the
spark plug fires.
• A high octane number indicates a higher self ignition
temperature meaning that this fuel will withstand higher
compression ratios before self-igniting.
Discussion- Characterization of crude oilFractional properties
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Octane number
• It is determined by measuring the knocking value of the fuel
compared to that of a mixture of n-heptane and isooctane.
• It is between 0 and 100 where the octane number 90 is for
the same knocking properties as 90% iso octane and 10% nheptane mixture.
Discussion- Characterization of crude oilFractional properties
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Octane number
• There are two types of octane number, the motor octane
number which is at 900 rpm at severe conditions.
• While the research octane number is at normal conditions
(600 rpm) the second is usually higher due to higher efficiency
of engine at lower rpm.
Discussion- Characterization of crude oilFractional properties
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Octane number
• The pump octane number is the one used by consumers and
is the average between the two. The octane number can be
improved by using additives to gasoline such as tetra ethyl
lead (TEL), lead chlorides, and oxygentates (MTBE methyl
tertiary butyl ether) which will be discussed later.
• If the use of additives improved the ignition properties
beyond pure iso octane the octane number will be higher
than 100.
Discussion- Characterization of crude oilFractional properties
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Octane number
• It can be measured by comparison of the ignition property of
the fuel with that of pure iso-octane with different TEL
additions.
• Or using the performance number which is the ratio of the
knock limited power of the fuel to that of pure iso octane
then this ratio converted to octane number by a simple
equation.
Discussion- Characterization of crude oilFractional properties
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2- Cetane number
• The cetane number is the ease of self ignition
of a diesel fuel, and can be considered s the
opposite of the octane number where high
cetane number means easier self ignition at
lower temperatures. This is desired in diesel
engines as these do not have spark plugs so
self ignition is desired.
Discussion- Characterization of crude oilFractional properties
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Cetane number
• It is represented by the percentage of pure
cetane in a mixture of cetane and alpha
methyl-naphthalene that has the same
knocking properties (ignition quality) of the
fuel. The knocking properties in both the
cetane and octane number are measured in a
special test engine which has a single cylinder,
a multi bowl carburetor for different mixtures
of fuel, and a pressure gauge to measure the
intensity of the knock.
Discussion- Characterization of crude oilFractional properties
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Composition of Crude Oil
Discussion- Composition of crude oil
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Ultimate analysis of crude oil
•
•
•
•
•
•
84-87% carbon,
11-14% hydrogen,
0-3% sulfur,
0-2% oxygen,
0-0.6, and
metals 0-100ppm.
All by weight percent.
Discussion- Composition of crude oil
51
Crude can be classified into 9 functional groups
1- Paraffins: Alkanes such as methane, ethane, propane, etc. They are present
in large amounts in the crude oil.
2- Olefins: Alkenes such as ethylene, propylene and butylene, these have a
double bond and are more reactive than paraffins are present in very
small amounts.
Discussion- Composition of crude oil
52
Crude can be classified into 9 functional groups
3- Naphthenes: Cycloalkanes such as cyclopropane, they are not aromatics so
do not increase the octane number so are a target in refining to convert to
aromatics.
4- Aromatics: Such as benzene and toluene they are present in moderate
amounts and contribute to increasing the octane number. They can be
considered as dehydrogenated cycloalkanes.
Discussion- Composition of crude oil
53
Crude can be classified into 9 functional groups
5- Naphthalenes: Polycyclic aromatics consisting of two or more aromatic
rings such as naphthalene.
6- Organic sulfur compounds: organic molecules that do not only include
carbon and hydrogen but also include sulfur such as pyridine. problems
caused by sulfur compounds are environmental effects are corrosion, and
catalyst poisoning.
Discussion- Composition of crude oil
54
Crude can be classified into 9 functional groups
7- Oxygen containing compounds: Present in small amounts such as acetic
and benzoic acid, the main problem is corrosion so they have to be
removed.
8- Resins: Polynuclear aromatics with long side chains of paraffins and a small
ring of aromatics they are of high molecular weight. These compounds
also contain sulfur, nitrogen, and metals.
9-Asphaltenes: Polynuclear aromatics with 20 or more rings along with
paraffinic and naphthenic chains, and usually an indication for the possible
use of the crude in coke production if present in large amounts.
Discussion- Composition of crude oil
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Main products of a refinery
Discussion- main products of the refinery
56
Main products of a refinery
1- Volatile products
• May be bottled in cylinders and sold or used as fuel.
• Propane LPG
• Butane LPG
• Light naphtha
2- Light distillates
• Gasoline used as motor fuel.
• Heavy naphtha used in petrochemical industries
• Kerosene use for lighting, cleaning, tractor fuel and jet fuel
Discussion- main products of the refinery
57
Main products of a refinery
3- Middle distillates
• Diesel fuel used as fuel in diesel engines and as lubricant.
• Benzene
• Heating oils
• Gas oils
4- Fuel oils
• Marine diesel
• Bunker fuels (used for ships)
Discussion- main products of the refinery
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Main products of a refinery
5- Lubricating oils
• Use to reduce friction and hence wear in moving parts.
• Motor
• Spindle
• Machine oils
6- Waxes
• Food and paper coating industry
• Pharmaceutical uses
7- Bitumen
• Asphalt, used for paving roads.
• Coke
Discussion- main products of the refinery
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The Refinery
Discussion- The Refinery
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Overview
• Sources of oil to the refinery are, the liquid product
from separation of natural gas and the directly from
the well.
• Before the oil is processed to give final products it is
separated into several fractions of boiling point ranges.
This is accomplished by distillation (atmospheric, and
vacuum).
• The distillation column separates the crude into five
main products; gases, kerosenes, light gas oil, fuel oil,
and heavy gas oil.
Discussion- The Refinery- Overveiw
61
Overview
• Each of these products is passed to the next level of
treatment, an example is kerosene and light gas oil are
passed to vapor recovery units and catalytic cracking units
to give gasoline, jet fuel, diesel fuels and others.
• Heavy gas oil is passed to the dewaxing units to give
lubricating oils.
• Finally the residue is processed to give asphalt and coke.
Usually the residue from the atmospheric tower is fed to a
vacuum tower before treatment for better separation. The
products of vacuum distillation are light vacuum gas oil,
heavy vacuum gas oil, and bitumen.
Discussion- The Refinery- Overview
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Overview
Discussion- The Refinery- Overview
63
Different refinery processes
• Distillation: Separating crude oil to fractions of boiling point
ranges, making it ready for further processing. Distillation can
be atmospheric or vacuum.
• Cracking: breaking the heavy crude fractions into lighter
products which can be further processed or blended with
other streams to give final products. Cracking can be either
thermal or catalytic.
Discussion- The Refinery- Main refinery
processes
64
Different refinery processes
• Upgrading (reforming): Rearranging of molecular structures
to improve the properties and value of the products. Such as
catalytic reforming, alkylation, and isomerization.
• Treating: Removal of hetero atm impurities such as sulfur
from streams and blends.
• Separation: By physical or chemical means for quality control
or further processing.
Discussion- The Refinery- Main refinery
processes
65
Different refinery processes
• Blending: Combining of different streams to give a final
product with the desired specifications and standards. Such as
gasoline blending, and jet and diesel fuel blending.
• Utilities: Provide fuel for refinery, power, steam, storage,
emission control.
Discussion- The Refinery- Main refinery
processes
66
Main units of the refinery
Discussion- The Refinery- Main units of the
refinery
67
Main Units of the refinery
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
Crude distillation unit (CDU)
Vacuum distillation unit (VDU)
Thermal cracker
Hydrotreaters
Fluidized catalytic cracker
Separators
Naphtha splitter
Reformer
Alkylation and isomerisation
Gas treating
Blending pools
Stream splitters
Discussion- The Refinery- Main units of the
refinery
68
Main Units of the refinery
Discussion- The Refinery- Main units
of the refinery
69
1- Distillation, atmospheric & vacuum
Discussion- The Refinery- Distillation
70
Overview of distillation
• Distillation is the separation of completely miscible mixtures
of liquids according to the difference of the boiling point and
volatility of the components in the mixture.
• Distillation is the first unit operation in any refinery it can be
only preceded with smaller units which perform pretreatment
of the oil to prepare it for distillation such as desalting and
dehydration both will be discussed later.
• Distillation separates raw crude oil into several refinery
streams known as fractions or cuts each has it’s own boiling
point.
Discussion- The Refinery- Overveiw of
Distillation
71
Overview of distillation
• The main fractions are light gasses, naphthas, distillates, gas
oils and residual oils ordered from the top to bottom.
• Each fraction goes to a different refinery process to be further
processed to give final products.
• There are two types of distillation units the first is
atmospheric distillation where the operation pressure is close
to the atmospheric pressure.
Discussion- The Refinery- Overveiw of
Distillation
72
Overview of distillation
• The second type is the vacuum distillation where the
pressure is reduced inside the tower allowing for the
vaporization of a part of the high boiling point (heavy)
residue from the atmospheric tower at lower temperature,
so no decomposition of hydrocarbons will occur.
• The pressure is reduced to 25-40 mmHg and the
temperature is around 380-420oC.
• Several unit operations that follow the “main” distillation
step also use smaller distillation columns to separate their
products into several streams.
Discussion- The Refinery- Overview of
Distillation
73
Atmospheric distillation
Discussion- The Refinery- Atmospheric
Distillation
74
Atmospheric distillation
Before the tower
• Atmospheric distillation is preceded by a desalting unit to remove
salts, water, and suspended solids.
• Desalting is either chemical or electrostatic. Both use water to
dissolve the salts and collect the suspended solids.
• In Chemical desalting surfactants are added along with water to
facilitate the separation of the salt water. The mixture is then sent
to a settling tank where the oil and water are separated.
• In electrostatic desalting chemicals are separated with a strong
electrostatic charge which facilitates the separation of the added
water from oil.
Discussion- The Refinery- Atmospheric
Distillation
75
Atmospheric distillation
Discussion- The Refinery- Atmospheric
Distillation
76
The atmospheric tower
• Modern distillation towers can process 200,000 barrels of oil per
day.
• They can be up to 150 feet (50 meters) tall and contain 20 to 40
trays spaced at regular intervals.
• Sometimes trays are replaced with packing made of an inert
material mainly ceramics.
• The main aim of packing or trays is providing intimate contact
between the vapor phase moving upwards and the liquid phase
moving downwards.
Discussion- The Refinery- Atmospheric
Distillation- The tower
77
The atmospheric tower
Packing and Trays
78
The atmospheric tower
• Before the crude enters the tower it is desalted then goes
through a network of heat exchangers and a fired heater
which pre-heats the feed to the desired temperature then
enter the tower just above the bottom of the tower.
• The heat exchangers use the heat from the product streams
of the tower to heat the feed crude.
• This decreases the cost of fuel needed for preheating.
Discussion- The Refinery- Atmospheric
Distillation- The tower
79
The atmospheric tower
• Steam is added to enhance separation, by decreasing the vapor
pressure of the hydrocarbons so stimulates it’s further evaporation.
• Products are collected at the top, bottom and the side of the
column.
• Side products are taken from trays at which the temperature
corresponds to the boiling point range that is desired for the
product.
• In modern towers, a fraction of each side stream is returned to the
tower to control the tower temperature so further enhances
separation. This goes for the top product and sometimes the
bottom product.
Discussion- The Refinery- Atmospheric
Distillation- The tower
80
The atmospheric tower
• After leaving the atmospheric tower the products are
transferred to storage tanks of fed to other equipment to
undergo further processing.
Discussion- The Refinery- Atmospheric
Distillation- The tower
81
The atmospheric tower
82
Design and principle
• Distillation is an equilibrium stage operation. In each stage
a liquid phase is contacted with a vapor phase, and mass
transfer occurs from vapor to liquid and vice versa.
• When the crude enters the tower the vapors move
upwards and the heavy liquids drop to the bottom of the
tower. The liquids are drawn off and sent to the vacuum
tower.
• The vapors rise through the trays, coming in contact with
the condensed liquid coming from the top.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
83
Design and principle
• This provides good contact between the vapor and liquid which
allows for mass transfer between the two phases.
•
The heavier hydrocarbons condense moving from the vapor phase
moving upwards to the liquid phase moving downwards and vice
versa.
•
When the vapor reaches the top it would have lost most of it’s
heavy hydrocarbons (HCs) and gained extra light HCs.
• Hence the stream leaving the top will mainly have light HCs and the
stream at the bottom having mainly heavy HCs and the side streams
in between have intermediate boiling point HCs.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
84
Design and principle
• The feed can be liquid, vapor or a liquidvapor mixture, this can enter the
column at any point.
• The product streams are at the top and
bottom, however side streams can be
used to withdraw products at the
desired tray with the desired
composition.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
85
Design and principle
Design of column
• The column is divided to two sections the section above the
feed tray is the rectifying section, and the section below it is
the stripping section.
• The base of the column is used as a reservoir for holding the
liquid leaving the bottom tray.
• This liquid is fed to a heat exchanger ”re-boiler” which is used
to boil this liquid, the “boil up” resulting from this is recycled
to the bottom of the tower, and the liquid stream leaving the
re boiler is the bottom product or residue.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
86
Design and principle
• The column is divided into a series of stages, each is
considered at equilibrium (equilibrium stages), with liquid
flowing downwards and vapor moving upwards.
• For mass transfer to occur, intimate contact between the
phases should be promoted.
• This is done using either trays or packing, both have the ability
to force the phases into close contact and giving the sufficient
time for the mass transfer to occur.
• After several stages (trays) enough mass transfer has
occurred, to ensure that the desired degree of separation has
been achieved.
87
Design and principle
• The product leaving from the top is called the overhead
product or the distillate, this can be a vapor or liquid
depending on the type of condenser.
• The product leaving at the bottom is called bottoms, it is a
liquid which is produced from the bottom reboiler after the
light components were evaporated.
• The vapor leaving the top of the column is passed through a
condenser where it is partially or totally condensed. A liquid
stream is withdrawn and recycled to the top tray (reflux) and
the remainder is the top product stream.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
88
Design and principle
• The reflux is the amount of liquid recycled from the cooler
back to the top plate of the tower. The ratio of the amount of
recycled HCs to the amount of HCs in the product stream is
the reflux ratio.
• Increasing the reflux improves the purity of the overhead
product but decreases it’s amount, and increases the recovery
in the bottom stream.
• Hence, increasing the reflux ratio decreases the number of
plates (stages) needed for a certain degree of purity, as it
gives better separation for the same number of trays.
89
Design and principle
• This drives us to two important conclusions, the first is that the smallest
number of trays can be known for a specific degree of purity when total
reflux is employed.
• The second is that below a certain reflux ratio the separation is impossible
no matter the number of trays due to the absence of liquid coming from
the top to mix with the vapor.
• Therefore the refinery should operate between the minimum reflux and
the total reflux ratios.
• The optimum reflux ratio that is practically employed is between 1:2 to 1:5
times the minimum reflux ratio.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
90
Design and principle
• In normal operation the five parameters that can be adjusted
to control the behavior of the distillation tower are the feed
flow, the product streams flow, the reflux ratio or flow, and
the boiler duty or the boil up flow.
• A normal column has a temperature gradient and a pressure
gradient from bottom to top.
• The operating pressure is controlled by adjusting the heat
removal of the condenser.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
91
Design and principle
Stages
• Stages as previously discussed are used to maximize the contact
between he liquid and vapor so mass transfer can occur.
• Each stage is considered to be ideal meaning that the vapor and
liquid leaving the stage are considered to be in equilibrium.
Meaning that the liquid is at it’s bubble point, and the vapor is at
it’s dew point.
• Consequently the vapor composition will depend on the liquid
composition. Vapor and liquid leaving the stage are never at
equilibrium, ideality is only an approximation, but stage efficiencies
are used to describe how far are the leaving fluids from equilibrium.
92
Design and principle
•
Theoretically speaking there is no limit to the purity of the products, providing that there is
enough reflux and number of stages. But in practice there are limits to both, so not any
degree of purity can be accomplished. Theoretical limits are calculated by assuming total
reflux (minimum stages) and minimum reflux (infinite number of stages).
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
93
Design and principle
Condensers
There are two types of condensers, the total condensers and the partial
condensers.
• The total condenser condenses all the vapor leaving the tower,
consequently the composition of the liquid leaving the condenser is
identical to the vapor leaving the column. Part of the liquid is recycled to
the column as reflux and the other is the overhead product stream.
• The partial condenser only liquefies a part of the vapor. The liquid
produced is recycled to the column, and the vapor is the product stream.
Thus the composition of the vapor entering the condenser and the two
product streams will be different. Partial condensers are considered an
extra stage as they operate as an equilibrium separation stage.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
94
Design and principle
• The reflux ratio is defined as the ratio of reflux to distillate which
represents the fraction of the vapor product from the column that is
recycled back to it.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
95
Design and principle
Re boilers
• Most reboilers are partial reboilers that are that they vaporize only part of
the liquid in the column base which is recycled to the column and the
remaining liquid is the product stream or residue. This also is considered
as an extra stage as it also operates as an equilibrium separation stage.
• In large columns side stream reboilers can be used to draw liquid off a
tray, heat it, then return the vapor-liquid mixture to the same or a
different tray.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
96
Design and principle
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
97
Design and principle
Feed conditions
The column internal flows are determined by the thermal condition of the
feed.
• If the feed is below it’s bubble point, heat should be added to raise the
temperature and allow it to vaporize.
• This heat is provided by the condensing vapor rising through the column,
so this fed liquid condensed vapor thus decreasing the off product
produced. If the feed is as a superheated vapor, it will vaporize some liquid
so the liquid flow is decreased and the vapor flow is increased.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
98
Design and principle
• If the feed is saturated, no additional heat must be added or removed and
the feed directly is part of the normal flow in the column.
• This is due to that inside the column the liquid and vapor are at the bubble
and dew points respectively so adding feed at a different temperature will
cause a disturbance in the amounts of gas and liquid present which will
change phases to give the required energy to change the temperature of
the feed to the dew or bubble points.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Design & Principle
99
Side operations
Side cut strippers
• Kerosene and Diesel are products that are withdrawn form the column as
sidestreams, these usually contain hydrocarbons form other cuts. These
are stripped in a small trayed (usually 5-6 trays) columns after being
withdrawn using steam which allows for lower boiling point hydrocarbons
are stripped out at the flash point of the other cuts that these
hydrocarbons belong to.
Discussion- The RefineryAtmospheric DistillationThe tower- Side ops.
100
Side operations
Pump arounds
• Pumparounds are side operations where part of the liquid is withdrawn
from a tray then heated then fed to the same or a different tray.
• This allows for the utilization of the available column heat using the heat
exchanger network, and maintaining the stability of the vapor loading of
the column and maintaining the amount of liquid moving in the column.
• Pumparound also control and distribute fractions between the products as
the control the flow of vapor. If the rate of pumparound is decreased the
vapor flow will increase.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Side ops.
101
Side operations
• If there are no pump around the liquid flow with be highest at the top as
the vapor load will increase then condense in the condenser then recycle
to the top of the tower.
• The capital cost is increased by the addition of a pumparound, this is due
to the need of a pump and a heat exchanger. Distillation columns usually
have 3 pump arounds.
Discussion- The Refinery- Atmospheric
Distillation- The tower- Side ops.
102
Products of Atmospheric distillation
103
Products of Atmospheric distillation
104
Products of Atmospheric distillation
Each of these products goes to a different unit to undergo further processing to
give the final product. Examples are
105
Atmospheric column schematic
Preheating,
desalting, tower,
side strippers,
pump arounds,
cooler, reboiler,
and products.
106
Vacuum distillation
107
Overview
• The residue from atmospheric distillation is sent to a vacuum
distillation tower which recovers additional liquid at 0.7 to 1.5
psia (atmospheric pressure is 14.7 psia) and temperature
between 380-420oC.
• The vacuum is created by vacuum pumps or steam ejectors is
pulled from the top of the tower.
• Vacuum towers have larger diameters and are simpler in
design than atmospheric columns.
108
Overview
• Random packing and demister pads are used mostly instead
of trays.
• This usually has a smaller number of streams than the
atmospheric tower.
• The overhead stream- light vacuum gas oil can be used as a
lube base stock, heavy fuel oil, as feed to a conversion unit.
• The side draw is heavy vacuum gas oil.
• The vacuum residue can be used to make asphalt or sent to a
coker or visbreaker for further processing.
109
Overview
• The vacuum residue can be used to make asphalt or sent to a
coker or visbreaker for further processing.
• Processing the residue at lower pressure will allow for the
vaporization of the hydrocarbons.
• Tis will reduce the need for increasing the temperature, which
can cause the decomposition of the hydrocarbons.
• The vacuum distillation unit is supported with side strippers to
allow for the refining of the side draws.
110
Types of vacuum distillation
• Dry vacuum distillation: without the injection of steam. It
runs at a very low pressure (10-15 mmHg at the top) so
requires the use of a booster ejector before the first
condenser.
• Wet vacuum distillation: With the injection of steam in the
furnace feed and stripping stream in the bottom of the tower.
It uses higher pressure (40- 60mmHg at the top). A
precondenser is used before the tower.
111
Types of vacuum distillation
112
Types of vacuum distillation
113
Types of vacuum distillation
• Semi-wet vacuum distillation: is when only steam is injected
at the bottom of the column. A booster ejector is needed. It is
positioned upstream of the first overhead condenser and
designed to boost process pressure high enough to allow
condensation.
114
Definitions
• LVGO: light vacuum gas oil.
• MVGO: medium vacuum gas oil.
• HVGO: heavy vacuum gas oil.
• Cracked hydrocarbons: hydrocarbons produced when the
feed is cracked at the furnace. They are found at the top of
the tower with the non- condensables and the steam injected
in the process.
115
Definitions
• Noncondensables: compounds that can not be condensed by
the vacuum system. This is made from air entering from leaks,
noncondensables dissolved in the feed when stored in the
storage tank, and light hydrocarbons produced by cracking in
the furnace.
• Slop cut and overflash: the two are the internal reflux coming
from the first tray above the feed inlet. Overflash is 3-5% of
the feed, is the section seen with the feed liquid to the
bottom of the column.
116
The vacuum tower
• The atmospheric residue is sent directly to the vacuum tower,
it is sometimes stored at 150oC to ensure it’s viscosity.
• It us preheated in a group of exchangers by heat recovery
from products and pump arounds.
• Then it is heated in a furnace to 380-415oC and fed to the
distillation column. It should be noted that flashing occurs in
the transfer line.
117
The vacuum tower
• In wet vacuum distillation, the furnace banks are often
equipped with dilution steam injection to limit the
temperature thus reduce coking.
• The number of side streams is usually based on the needs of
the units downstream. The distillate is withdrawn in two cuts
MVGO and HVGO.
• The HVGO is used in pump around due to it’s adequate
temperature.
118
The vacuum tower
• If it is required to increase the value of the gas oil or if the
downstream units require special initial cut point, three cuts
are drawn off from the column.
• An LVGO which is sent to atmospheric gas oil to produce
commercial products.
• An MVGO and HVGO which are the feed for the downstream
units.
119
The vacuum tower
120
Description of the column
• The vacuum column has two main targets the first is the
recovery of light hydrocarbons from the atmospheric residue
and the preparation of feed for the following units.
121
Preparing the feed for catalytic units
1- Column without a fractionation zone
If no end or initial point requirement for the vacuum distillate.
Configuration:
• One or two wash zones fed by internal reflux of the HVGO
draw tray.
• A heat exchanger zone above the HVGO side draw tray.
• A heat exchanger zone above the HVGO side draw tray.
122
Preparing the feed for catalytic units
2- Column with fractionation zones
If the downstream units require a specified distillate end point.
Configuration
• The feed for this zone is made up of internal reflux under
HVGO.
• If better values are desired for the gas oil in the feed then a
fractional zone is installed between the LVGO and the MVGO
offtakes.
123
Preparing the feed for catalytic units
3- Bottom of the column
• The bottom of the column has 4 to 6 valve trays to perform
stripping in wet vacuum distillation, In dry vacuum distillation
the bottom of the column is equipped with simple horizontal
baffles.
• The vacuum residue in the bottom of the column must be as
short as possible to prevent coking.
124
Preparing the feed for catalytic units
Special case, two stage vacuum distillation
Configuration
• In some cases the solution of two stage vacuum distillation
can be used to obtain very heavy cuts.
• The first tower is dry and the second is wet. The bottom of the
first tower supplies the feed for the second.
125
Vacuum distillation design to give lube oils
• These are equipped with side strippers to the side draw
distillates.
• And the column has fractionation zones between each side
stream and the other one.
126
Vacuum distillation design to produce bitumen
• These have a stripping column at the bottom of the tower and
are therefore at semi wet.
• They operate under higher vacuum than the other towers.
127
Choosing the type of vacuum distillation
The choice is dependent on economic considerations
• The pressure drop in the column as a result of the
fractionation.
• The available utilities (whether the cooling air temperature
allows for the condensation of the overhead vapors.
128
Technology
129
Packing and distributors
• Fractionation and heat exchanger zones are equipped with
packing to curb pressure drop.
• The bottom zone is equipped with reinforced valve trays.
• There are two types of packing.
• The first is random packing, made of metal rings and grates.
This is used for heat exchanger zones.
• The second is Structured packing which is made of stacks
folded and perforated corrugated metal grates.
130
Packing and distributors
• This type of packing is more expensive and more effective and
is mainly used in fractionation zones.
• It is today being used for all the column above the wash
zones. The wash zones can be equipped with less
sophisticated grates.
• The liquid is supplied to the packing by two types of
distributors. The first is sprays and the second is gravity.
131
Vacuum pumps and ejector- condensers
• Pumps and jet ejectors are used to create vacuum.
• Ejectors recompress the gasses by speeding them up (venture
effect) through a nozzle. Where the working fluid is medium
or low pressure steam.
• The vapor phase at the ejector exit is partially condensed in a
heat exchanger with cooling water.
132
Vacuum pumps and ejector- condensers
133
Vacuum pumps and ejector- condensers
134
Vacuum pumps and ejector- condensers
• These are direct contact condensers which generate pollution
and have been phased out.
• The liquid phase is sent to an overhead drum via barometric
leg. The vapor phase goes from the condenser to another
ejector-condenser stage.
• The overhead drum allows the hydrocarbons to settle so
separate from the water.
135
Vacuum pumps and ejector- condensers
• Liquid pumps have a compression ratio of about 10 and
therefore replace two or three stages of ejectors in dry or wet
vacuum distillation.
• Pumps are less reliable than ejectors.
• The higher investment cost required by pumps are offset by
the reduced steam consumptions and lower installation costs.
• Even with the addition of the cost of electric power consumed
by the pumps.
136
Vacuum pumps and ejector- condensers
137
Vacuum pumps and ejector- condensers
Types of vacuum pumps
138
Vacuum pumps and ejector- condensers
139
The whole tower with the vacuum system
140
Products of the vacuum distillation unit
141
Products of the vacuum distillation unit
1- Multiple gas oils.
• Sent to the hydrotreating unit.
2- Vacuum residue:
• Blended to give asphalt and heavy fuel oil.
• Further processing. Thermal treatment or solvent extraction.
142
Vacuum distillation summary
Configuration
• Reduced pressure to allow for lower temperatures.
• Larger diameter than atmospheric column.
• Liquid reflux from pumparounds.
• No reboiler.
• Stripping steam can be used.
• Needed for deep cuts.
143
Vacuum distillation summary
Feed
• Residue from atmospheric distillation.
• All the vapor comes from the heated feed.
• Under vacuum.
• Separate higher boiling materials at lower temperatures so
minimize thermal cracking.
144
Cracking
145
Overview
• Cracking is the process (chemical reaction) where large high
boiling point hydrocarbons are broken “cracked” into smaller,
lighter molecules.
• These can be suitable after further processing for blending to
different products such as gasoline, jet fuel, diesel fuel,
petrochemical feedstock, and other high value light products.
146
Overview
• Cracking units are an essential component in the refinery:
• Allow the refinery to achieve high yields of transportation
fuels and valuable light products.
• Provide operating flexibility to maintain the output of the light
products in the face of normal crude oil quality fluctuation.
• Allows the economic use of the heavy and sour crude oils
when burned during cracking.
147
Thermal cracking
148
Thermal cracking
• Thermal cracking followed by the separation using physical
differences (distillation).
• The products are usually naphtha, gas, gas oil, and thermal
cracked residue.
• Sometimes thermal cracking is replaced with delayed coking
to give coke as one of the products.
149
Thermal cracking
• The operating temperature is about 450-500oC.
•
And the operating pressure is 2-3 bar.
150
The process
• Products (Residue) from the atmospheric and vacuum column
are used.
• The feed is preheated in a furnace to about 1000oF.
• The space velocity is high to prevent reactions from occurring
in the furnace tubes.
• The effluent form the furnace goes to the reaction chamber
for a few munities, however the pressure is kept as high as
140 psi which favors only cracking not coking.
151
The process
• The effluent form the reaction chamber is passed through a
quench to stop the cracking.
• Quenching is done by mixing this stream with a cooler recycle
stream.
• This stream is then fed to a flash chamber where the light
products go overhead then are fed to a fractionator.
• The C4 and lighter streams from the fractionator are sent for
further processing usually alkylation.
152
The process
• The thermally cracked gasoline and naphtha from the
fractionator are sued for gasoline blending.
• The gas oil from the fractionator is used as a distillate fuel.
• The residue from the bottom of the flash chamber is diluted
by gas oil to reduce it’s viscosity then sold as residual fuel and
heavy industrial fuel oil.
153
The process
154
Coking
155
Coking
• A sub category of a variant of thermal cracking is coking.
• Coking is thermal cracking under severe conditions to allow to
the breaking of the hydrocarbons completely to give carbon
(coke).
• Coking was used to preheat vacuum residues to prepare coker
gas oil, which is a suitable feed for the catalytic cracker. This
has the advantages of the amount of coke depositing on the
catalyst.
156
Coking
The main uses of petroleum coke:
• Fuel.
• Manufacture of anodes for electrolytic cell.
• Direct use as chemical carbon source for manufacture of
elemental phosphorus, calcium carbide.
• Manufacture of electrodes for use in electric furnace .
• Manufacture of graphite
157
Delayed coking
• The delayed coking process was developed to minimize
refinery yields of residual fuel oil.
• This is achieved by severe thermal cracking of stocks such as
vacuum residuals. Thermal tars, and aromatic gas oils.
• In early refineries, the severe thermal cracking of these stocks
caused the formation of large amounts of residual coke.
158
Delayed coking
• Gradual evolution of refineries lead to that heaters were
designed to raise the feedstock temperature above the coking
temperature without significant coke formation in the
heaters.
• This was achieved by increasing the velocity of flow in the
heather (minimum retention time).
• Then providing an insulated surge drum on the exit of the
heater which will give sufficient time for coking to occur.
159
Delayed coking
160
Delayed coking
• The higher the outlet temperature of the furnace the greater
the tendency to produce shot coke.
• And the shorter the time before the furnace tubes have to be
decoked.
• Usually the furnace tube have to be decoked every 3-5
months.
161
The process
• Hot fresh liquid feed is fed to the fractionator two to four
trays above the bottom vapor zone.
• Vapors from the top of the fractionator return to the base of
the fractionator.
• These consist of steam along with the products of thermal
cracking.
162
The process
• These vapors; afterbeing fed to the fractionator are passed
through the quench trays.
• Quench trays are trays where the fresh feed is mixed with the
gasses from the reactor.
• There are usually 2-3 trays above the feed trays which are
below the gas oil draw tray.
• These trays are refluxed with partially cooled gas oil to
provide control over the gas oil end point.
163
The process
• Steam and vaporized light ends are returned from the top of
the gas oil stripper to the fractionator 1-2 trays above the gas
oil draw tray.
• Eight to ten trays are between the gas oil draw and the
naphtha draw (column top).
164
The process
165
Coke removal
• The coke drum is continuously being filled during service to a
safe margin from the top.
• There are two coke drums installed in parallel, one is in
operation and getting filled by coke. And the other is already
full and being cleared from the coke.
• When one drum is full the heater is switched to the other
drum and the full drum is isolated.
166
Coke removal
• After isolation, the empty drum is steamed to remove the
hydrocarbon vapors.
• Then cooled by filling with water, opened, drained then the
coke removed.
• In some plants decoking is accomplished by a mechanical drill.
• However, most plants use hydraulic systems.
167
Coke removal
• The hydraulic system, is a number of high pressure (13800 to
31000 kPa) water jets which are lowered into the coke bed on
a rotating drill stem.
• A small whole in diameter is first cut all the way through the
bed from the top to the bottom using a special jet.
• This is done to allow the main drill stem to enter and allow
the movement of coke and water through the bed.
168
Coke removal
• The bulk of the coke is then cut from the drum, usually
starting at the bottom.
• Some operators prefer to start at the top to avoid the chance
of dropping large pieces of coke which can trap the drill stem
or cause problems in the following units.
169
Coke removal
• A newly developed technique called chipping is now used to
remove the coke from the surge drum.
• In this technique the cutting bit is repeatedly transferred back
and forth from the top to the bottom as it rotates.
• Then the coke is cut from the center to the wall.
• This reduces the cutting time, produces fewer fines, and
eliminates the problem of the bit being trapped.
170
Coke removal
• The coke which falls from the drum is often collected directly
in railroad cars.
• An alternative is that the coke is sluiced or pumped as a water
slurry or conveyed by a belt.
171
Coke removal
172
Operation
• The coke drums are filled and emptied and filled on time
cycles.
• The fractionation column is operated continuously.
• Usually 2 drums are present one for reaction and the other
for releasing coke.
• However units having 4 drums
are being widely used.
173
Operation
• The table shows time schedules for the different stages of
operation of the unit.
174
Operation
• The capacity can be increased by operating in shorter cycle
times.
• Usual design factors will allow for a 20% increase in capacity
by decreasing the coking time from 24 to 20 hours.
• Shorter times will cause a decrease in yield of liquid products,
and reduce the remaining drum life by 25%.
175
Operation
176
Flexicoking
177
Flexicoking
• The feed to flexicoking can be any heavy oil such as vacuum
residue, coal tar or sand bitumen.
• The feed is preheated to about 315 to 370oC then sprayed
into the reactor where it contacts a hot fluidized bed of coke.
• This coke is recycled to the reactor from the coke heater at
the rate which is sufficient to maintain the reactor fluid bed
temperature between 510-540oC.
178
Flexicoking
• The coke recycle thus provides the sensible heat and heat of
vaporization for the feed.
• And the endothermic heat for the cracking reactions.
• The cracked vapor products pass through several cyclones in
the top of the reactors to separate them from the entrained
coke particles.
• Then are quenched in a scrubber vessel at the top of the
reactor.
179
Flexicoking
• Some of the high boiling point cracked vapors are condensed
in the scrubber then recycled to the reactor.
• The remainder is sent to the cocker fractionator to be
separated to several cuts.
• The coke produced by cracking is deposited as thin films on
the existing coke particles in the reactor fluidized bed.
180
Flexicoking
• The coke is stripped with steam in a baffled section at the
bottom of the reactor to prevent the reaction products, other
than coke, from being entrained with coke leaving the reactor.
• Coke flows from the reactor to the heater where it is reheated
to 600oC.
• The coke heater is also a fluidized bed with the primary
function of transferring heat from the gasifier to the reactor.
181
Flexicoking
182
Flexicoking
• Coke flows from the coke heater to a third fluidized bed in the
gasifier where it is reacted with air and steam to give a fuel
gas product consisting of CO, hydrogen, carbondioxide, and
nitrogen.
• Sulfur in the coke is converted to H2S and a small amount of
COS.
• Nitrogen in the coke is converted to NH3 and N2.
183
Flexicoking
184
Flexicoking
• This gas flows from the top of the gasifier to the bottom of the
heater where it is used to fluidize the heater bed.
• And provide the heat needed in the reactor.
• As previously mentioned, the heat required by the reactor is
supplied by recirculation hot coke from the gasifier to the
heater.
185
Flexicoking
• The system can be designed and operated to gasify about 6097% of the coke product from the reactor.
• The overall coke inventory of the system is maintained by
withdrawing a stream of purge coke from the heater.
• The coke gas leaving the heater is cooled in a waste heat
steam generator.
• Then passed through external cyclones and a wet scrubber.
186
Flexicoking
• The coke fines collected in the wet scrubber plus the purge
coke from the heater represent the net coke yield and contain
all of the metal and ash components of the reactor feedstock.
• After removal of the entrained coke fines the coke gas is
treated to remove the hydrogen sulfide in a Stretford unit
then used as refinery fuel.
• This gas has a much lower heating value than natural gas, so
modifications to boilers an furnaces may be necessary for
efficient combustion.
187
Fluid coking
188
Fluid coking
• Fluid coking is a simplified version of flexicoking.
• In the fluid coking process, only enough of the coke is burned
to satisfy the heat requirements of the reactor and the feed
preheat.
• This is about 20-25% of the produced coke from the reactor.
• The remainder of the coke is withdrawn from the burner
vessel and is not gasified.
189
Fluid coking
• Therefore only two fluid beds are used in a fluid coker; a
reactor and a burner which replaces the heater.
• The main advantage of the flexicoker over the more simple
fluid coker is that most of the heating value of the coke
produced is made available as low sulfur gas.
• This gas can be burned without a sulfur dioxide removal
system on the stack.
190
Fluid coking
• Also the coke gas can be used to displace liquid and gaseous
hydrocarbon fuels in the refinery heaters.
• And does not have to be used only in boilers as the case with
fluid coke.
191
Yields from Flexicoking and Fluid coking
• The products from Flexicoking and fluid coking are the same
as those from the delayed coking except for the amount of
reactor coke product which is burned or gasified.
• Thus the coke yield from fluid coking will be about 75-80% of
the coke yield from a delayed coker.
• And the yield from a flexicoker will be in the range of 2-40
wt% of the delayed coker.
192
Visbreaking
193
Visbreaking
• Visbreaking is relatively, mild thermal cracking operation.
• It is mainly used to reduce the viscosities and pour points of
vacuum tower bottoms to meet specific oil specifications.
• Or to reduce the amount of cutting stock required to dilute
the residue to meet the desired specifications.
• The cutting stock is a feedstock mixed with the product to
decrease it’s viscosity.
194
Visbreaking
• Refinery product of heavy fuel oils can be reduced by 20-35%.
• And the cutter stock requirements can be reduced by 20-30%
by visbreaking.
• Also the gas oil fraction produced by visbreaking is also used
to increase catalytic cracker feed stocks and increase gasoline
yields.
195
Visbreaking
• Long paraffinic side chains attached to aromatic rings are the
main cause of high pour points and viscosities for paraffinic
base residues.
• Visbreaking is carried out at conditions to allow the breaking
off of these side chains and their subsequent cracking to
shorter molecules with lower viscosities and pour points.
• The amount of cracking is limited, because if the operation is
too severe, the resulting product becomes unstable and can
be liable to polymerize during storage.
196
Visbreaking
• The degree of viscosity and pour point reduction is a function
of the composition of the residues which are fed to the
visbreaker.
• Waxy feed achieve pour point reduction of 15-35oF and final
viscosities from 25-75% of the feed.
• High asphaltene content in the feed reduces the conversion
ratio at which a stable fuel can be made which results in
smaller changes in the properties.
197
Visbreaking
• The properties of the cutter stocks used to blend with the
visbreaker tars also have an effect on the severity of the
visbreaking operation.
• Aromatics cutter stocks such as catalytic have good effect on
fuel stability and permit higher visbreaker conversion levels.
• The molecular structures of the compounds in petroleum
which have boiling points above 538oC are highly complex and
are classified as oils, resins, and asphaltenes according to
solubility in light paraffinic hydrocarbons.
198
Visbreaking
• The oil fraction is soluble in propane.
• The resin fraction is soluble in either pentane, hexane, nheptane, or octane. Depending on the investigator.
• The solvent selected has an effect on the amounts and
properties of the fractions obtained.
199
Visbreaking
The main reactions that occur during visbreaking are:
• Cracking of the side chains attached to cycloparaffin and
aromatic rings. Which are either removed or shortened.
• Cracking of resins to light hydrocarbons (mainly olefins) and
compounds which convert to asphaltenes.
• At temperatures above 480oC some cracking of naphthene
rings occurs.
200
Visbreaking
The severity of the visbreaking operation can be expressed in
several ways:
• The yield of the material boiling below 166oC.
• The reduction in product viscosity.
• The amount of standard cutter stock needed to be blended
with the visbreaker to give the desired specifications
compared to the amount needed for the feedstock.
201
Visbreaking
• In the US the severity is expressed as the volume % product
gasoline in a specified boiling range.
• In Europe as the weight % yield of gas plus gasoline.
202
Visbreaking
• There are two types of visbreaking operations, coil and
furnace cracking and soaker cracking.
• As in all cracking reactions the reactions are time and
temperature dependent.
• Compromise must be done between temperature and time to
give the highest yields.
203
Visbreaking
• Coil cracking uses higher furnace outlet temperatures 473500oC and reaction times from 1 to 3 minutes.
• While soaker cracking use lowers the furnace outlet
temperatures (427-443oC) and longer reaction times.
• The product yields and properties are similar, but the soaker
operation with it’s lower furnace outlet temperatures ahs the
advantages of lower energy consumption and longer run
times before having to shut down to remove coke from the
furnace tubes.
204
Visbreaker
205
Visbreaking
• Run times are in the range of 3-6 months for furnace
visbreakers.
• And 6-18 months for soaker visbreakers.
• The apparent advantage of the soaker visbreaker is partially
balanced by the greater difficulty in cleaning the soaking
drum.
206
Soaker visbreaker
207
Coil visbreaker
208
Coil visbreaker
209
Soaker visbreaker
210
Process
• The feed is introduced into the furnace and heated to the
process temperature.
• In both the furnace and coil cracking process the feed is
heated to the cracking temperature 475-500oC.
• Then the feed is quenched with gas oil or tower bottoms.
• This is to stop the cracking reaction.
211
Process
• In soaker cracking operation the feed leaves the furnace at
425-440oC.
• Before it is quenched it is passes through the soaking drum
where additional reaction time is provided.
• Pressure is an important design parameter.
• Units are designed to operate as high as 5170 kPa for liquid
phase visbreaking and as low as 690-200 kPa for 20-40%
vaporization at the furnace outlet.
212
Process
• In furnace cracking, fuel consumption accounts for nearly 80%
of the operating cost.
• Fuel requirement for soaker visbreaking is about 30-35%
lower.
213
products
• The properties of the products of visbreaking change with the
conversion and the characteristics of the feedstocks.
• However some properties such as the diesel index and octane
number are more closely related to feed quality and the
density and viscosity of the gas oil uesd.
214
products
215
products
216
Fluid Catalytic cracking
217
Overview
• Catalytic cracking is the most important and widely used
process in the refineries for converting heavy oils into
gasoline and lighter products.
• Originally cracking was accomplished thermally. Bit the
catalytic process has almost completely replaced it.
• This is due to that the catalytic process produces higher
octane number gasoline and les heavy fuel oils and light
gasses.
218
Overview
• Fluid catalytic cracking (FCC) operates at high temperature
and low pressure conditions and employs a catalyst.
• It converts heavy gas oil from atmospheric distillation and
other streams to light gasses, petrochemical feedstock,
gasoline blendstock (FCC naphtha), and diesel fuel blendstock.
219
Overview
• The cracking process produces coke as a side product which
remains on the catalyst surface and lowers it’s activity.
• It is important to regenerate the catalyst by burning this coke
in air.
• The cracking reaction is endothermic and regeneration is
exothermic. Hence the regeneration heat can be used to
supply the heat needed to preheat the feed to the reactor.
220
The process
• The FCC process employs a catalyst in the form of very fine
metallic particles about 70 micrometers.
• These particles behave as fluid when aerated with vapor.
• The fluidized catalyst is continuously circulated between the
reaction zone and the regenerator. Thus acting as a “vehicle”
to transport heat between the two processes.
221
The process
There are two types of FCC units
• The first is side by side type, where the reactor and the
regenerator are separate vessels adjacent to each other.
• The second is the orthoflow or stacked type where the
reactor is mounted on top of the regenerator.
222
The process
223
The process
• Until 1965 most units were a discrete dense phase fluidized
catalyst bed in the reactor.
• The unit operated so that most of the cracking occurred in the
reactor bed.
• The extent of cracking was controlled by changing the depth
of the reactor bed and hence the residence time.
• Most recently designed units operate with a minimum bed
level in the reactor and the reaction rate is controlled by
varying the catalyst circulation rate.
224
The process
• The fresh feed and recycle streams are preheated by heat
exchangers or a furnace and enter the unit at the base of the
feed riser where they are mixed with the hot regenerated
catalyst.
• The heat from the catalyst vaporizes the feed and raises it’s
temperature to the reaction temperature.
• The mixture of the catalyst and hydrocarbons travel up the
riser to the reactors.
225
The process
226
The process
• The cracking reactions start when the feed contacts the hot
catalyst in the riser and continues until the oil vapors are
separated from the catalyst in the reactor.
• The vapors produced are sent to a fractionator to be
separated into liquid and gaseous products.
• The catalyst leaving is called the spent catalyst, and contains
hydrocarbons adsorbed on it’s surface as well as coke.
227
The process
228
The process
• Part of the adsorbed hydrocarbons is removed by steam
before the catalyst is fed to the regenerator.
• In the regenerator coke is burned with air. The temperature
and coke burn off are controlled by changing the air flow rate.
• The heat of combustion raises the catalyst temperature to
620-845oC, most of which is transferred to the feed in the
riser.
• The regenerated catalyst contains 0.01-0.4 weight % coke.
229
The process
• The regenerator can be designed to operate to burn the cohe
on the catalyst to:
• Either a mixture of carbon dioxide and carbon monoxide.
• Or completely to carbon dioxide.
• Older units were designed to give CO to minimize the blower
operating and capital costs. As only half the amount of air is
needed to be compressed to burn the carbon to CO not CO2.
230
The process
• The flue gas leaving the regenerator will have large amounts
of carbon monoxide which is burned to carbon dioxide in a CO
furnace (waste heat boiler).
• This is done to recover the available fuel energy.
• The hot gases produced in this process can be used to
generate steam or to power expansion turbines.
231
The process
• Newer units are design to burn the coke to CO2 in the
regenerator as they can burn to a much lower residual carbon
level on the regenerated catalyst.
• This gives a more reactive and selective catalyst after
regeneration.
• And better product distribution results at the same
equilibrium catalyst activity and conversion level.
232
The process
233
FCC
234
FCC
• The products formed in catalytic cracking are the result of
primary and secondary reactions.
• The primary reactions are these having the initial carboncarbon bond breaking and the immediate neutralization of
the carbonium ion.
235
FCC
Advantages
• High yields of gasoline.
• High reliability and low operating cost.
• Operating flexibility to adapt to changes in crude oil quality.
In large transportation fuels oriented refinery 40% of the
production of gasoline and distillates is produced from the FCC
unit only.
236
FCC
• FCC produces significant amounts of light gasses including
olefins.
• Olefins are highly reactive unsaturated chemicals that can be
used as petrochemical feedstock or as feedstock for the
upgrading units in the refinery.
• With suitable catalyst selection FCC units can be designed to
maximize the production of gasoline blendstock or
petrochemical feedstock.
237
New designs for fluidized bed catalytic cracking units
• Zeolite catalysts have a higher cracking activity than
amorphous catalysts, and shorter reaction times are needed
to prevent over cracking.
• This has resulted in units which have a catalyst-oil separator in
place of the fluidized bed reactor to achieve maximum
gasoline yields at a given conversion level.
• Newer units are redesigned to have up to 25% reduced crude
in the FCC feed.
238
Cracking catalyst
Commercial cracking catalysts are divided to 3 classes:
• Acid- treated natural aluminosilicates.
• Amorphous synthetic silica-alumina combinations.
• Crystalline synthetic silica-alumina catalysts (zeolites).
• Most catalysts used today are either type 3 or mixtures of
types 2 and 3 catalysts.
239
Cracking catalyst
The advantages of the zeolite catalysts are:
• Higher activity.
• Higher gasoline yields at a given conversion.
• Production of gasolines containing a larger percentage of
paraffinic and aromatic hydrocarbons.
240
Cracking catalyst
• Lower coke yield.
• Increased isobutane production.
• Ability to go to higher conversions per pass without
overcracking.
241
Cracking catalyst
• The high activity of zeolite cracking catalyst allows for shorter
residence time.
• Basic nitrogen compounds, iron, nickel, vanadium, and copper
in the oil act as poisons to cracking catalysts.
• The nitrogen reacts with the acid centers on the catalyst and
lowers it’s activity.
242
Cracking catalyst
• The metals deposit and accumulate on the catalyst and cause
a reduction in throughput.
• By increasing coke formation and decreasing the amount of
coke burn-off per unit air.
• This is due to the catalysis effect of the metal where the coke
is converted to carbon dioxide rather carbon monoxide.
243
Cracking catalyst
• It is generally accepted that nickel has four times the effect on
catalyst selectivity as vanadium.
• Although nickel and vanadium deposits reduce the catalyst
activity by occupying the catalyst’s active sites.
• The major effects are the promotion of the formation of gas
and coke and reduce the gasoline yield.
244
Cracking catalyst
• Metals removal processes can be used to reactivate the
catalyst.
• This is done by cycling a slip stream through a metals removal
system.
• This allows the equilibrium catalyst metal concentration to be
controlled at the level which fresh catalyst is required to
maintain activity and selectivity equals catalyst losses.
245
Catalytic hydrocracking
246
Overview
• Hydrocracking was commercially developed to convert liginite
to gasoline.
• It was then used to upgrade petroleum feedstocks and
products.
• It has the advantage of the production of hydrogen as a
byproduct in large amounts and at low cost.
247
Overview
The advantages of hydrocracking are
• Better balance of gasoline and distillate production.
• Greater gasoline yield.
• Improved gasoline pool octane quality and sensitivity.
• Supplementing of fluid catalytic cracking to upgrade heavy
cracking stocks, aromatics, cycle oils, and coker oils to
gasoline, jet fuels, and light fuel oils.
248
Overview
• In a modern refinery catalytic cracking and hydrocracking
work as a team.
• The catalytic cracker takes the more easily cracked paraffinic
atmospheric and vacuum gas oils.
• And the hydrocracker uses the more aromatic cycle oils and
coker distillates as feed. These streams resist catalytic cracking
even when the newly developed zeolites are used.
• The higher pressure and the hydrogen atmosphere makes
them easier to break.
249
Overview
• In addition to cycle oils and middle distillates, it is also
possible to use residual fuel oils and reduced crude as feed to
the hydrocracking unit.
250
Overview
There are two types of hydrocracking:
• Those which operate on distilled feed (hydrocracking).
• And those which operate on residual materials
(hydroprocessing).
• These processes are similar and some processes can be
adapted to operate on both types of feed.
• The major difference is in the type of catalyst and the
operating conditions.
251
The reactions
• There are hundreds of simultaneous reactions occurring in
hydrocracking. It is the general opinion that the mechanism of
hydrocracking is the mechanism of catalytic cracking with
hydrogen superimposed.
• Catalytic cracking is the breaking of a carbon-carbon single
bond.
• Hydrogenation is the addition of hydrogen to a double bond.
252
The reactions
253
The reactions
• This shows that cracking and hydrogenation are
complementary.
• Cracking provides olefins for hydrogenation.
• And hydrogenation provides heat for cracking.
• The cracking reaction is endothermic and the hydrogenation is
exothermic. The overall reaction provides excess heat.
254
The reactions
• This heat causes an increase in temperature and an increase
in the rate of the reaction.
• This is controlled by the injection of cold hydrogen as a
quench in the reactor to absorb the excess heat.
• Other reactions that occur are the hydrogenation of
condensed aromatics to cycloparafins and isomerization.
255
The process
• Hydrocracking is usually carried out at temperatures between
290 and 400oC an pressures between 8275 and 13800 kPa.
• The circulation of large quantities of hydrogen along with the
feedstocks prevent the excessive fouling of catalyst and allows
for long runs before catalyst regeneration is needed.
256
The process
• The hydrocracking catalyst is susceptible to poisoning by
metallic salts, oxygen, sulfur, and organic nitrogen compounds
present in the feedstocks.
• During hydrocracking molecules containing metals are cracked
and the metals are deposited on the catalyst.
• The nitrogen an sulfur compounds released are removed by
conversion to ammonia and hydrogen sulfide during the
reaction.
257
The process
• It is nectary to reduce the waster content of the feed to less
than 25 ppm, as at the temperatures required by
hydrocracking steam causes the crystalline structure of the
catalyst to collapse.
• This is accomplished by passing the feed through a silica gel or
molecular sieve dryer.
• On average, the hydrotreating process requires about 150 to
300 ft3 of hydrogen per barrel of feed.
258
The process
• The hydrocracking process may require one or two stages
depending on the process itself and the feed used.
• The GOFining process is a fixed bed regenerative process,
which has a molecular sieve catalyst impregnated with rare
earth metal.
• The process employs either single stage or two stage
hydrocracking with typical operating conditions ranging from
350-420oC and 6900-13800kPa.
259
The process
260
The process
• The decision weather to use single or two stage system
depends on the size of the unit and the product desired.
• For most feedstocks the use of a single stage will allow the
complete conversion of the feed to gasoline and lighter
products by recycling the heavier material to the reactor.
• The next slide has the figure of the two stage system. The one
stage system will have the same flow sheet with the addition
of the recycle of the fractionation tower bottoms to the
reactor feed.
261
The process
262
The process
• The fresh feed is mixed with the make up hydrogen and
recycle gas which also has a high hydrogen content and
passed through a heater then fed to the first reactor.
• If the heed has not been hydrotreated it is passed first
through a guard reactor.
263
The process
• This reactor is placed before the first hydrocracking reactor.
• It has a modified hydrotreating catalyst (cobalt based) which
converts organic sulfur and nitrogen compounds to hydrogen
sulfide, ammonia, and hydrocarbons.
• This is to protect the precious metals in the first reactor.
264
The process
265
The process
• The hydrocracking reactors are operated at a temperature
that is sufficiently high to convert 40-50 vol% of the effluent
from the reactor.
• The reactor effluent goes through a series of heat exchangers
to a high pressure separator.
• Where the hydrogen rich gasses are separated and recycled to
the first stage for mixing with the feed.
266
The process
• The liquid product from the separator is sent to a distillation
column.
• Where the C4 and lighter gasses are taken off as overhead.
• And the light and heavy Naphtha, jet fuel, and diesel boiling
point range streams as liquid side streams.
• The bottoms are used as feed to the second stage reactor
system.
267
The process
268
The process
• The bottoms stream from the fractionator is mixed with thee
recycle hydrogen from the second stage and sent through a
furnace to the second stage rector.
• In this reactor the temperature is maintained to bring the
total conversion of the unconverted product from the first
stage and the second stage recycle to 50-70 vol% per pass.
• The second stage product is combined with the first stage
product before fractionation.
269
The process
270
The process
• Both the first and second stage reactors contain several beds
of catalyst.
• The main reason for having separate beds is to provide
locations for the injection of the recycled cold hydrogen into
the reactors for temperature control.
• Also this will allow for the redistribution of the feed and
hydrogen between the beds.
• So allows for more uniform utilization of the catalyst.
271
The hydrocracking catalyst
• Most of the hydrocracking catalysts consist of a crystalline
mixture of silica-alumina.
•
With a small uniformly distributed amounts od rare earth
metals contained within the crystalline lattice.
• The silica-alumina part provides the cracking activity.
• While the rare earth metals promote hydrogenation.
272
The hydrocracking catalyst
• The catalyst activity decreases with use, and reactor
temperatures are raised during a run to increase reaction rate
and maintain conversion.
• The catalyst selectivity also changes with age, and more gas is
made and less naphtha is produced as the temperature is
raised to maintain the conversion.
• It will take 2 to 4 years with typical feedstocks for the catalyst
activity to decrease from the accumulation of coke and other
deposits for the level to require regeneration.
273
The hydrocracking catalyst
• Regeneration is done by burning off the catalyst deposits.
• After regeneration catalyst activity is restored to close to it’s
original level.
• The catalyst can undergo several regenerations before it is
necessary to replace it.
274
The hydrocracking catalyst
• Almost all hydrocracking catalysts use silica- alumina as the
cracking base.
• The use of the rare earth metals vary according to the
manufacturer.
• These include platinum, palladium, tungsten, and nickel.
275
Hydroprocessing and Resid processing
276
Hydroprocessing and Resid processing
• The term resid means the bottom of the barrel.
• It is usually the atmospheric tower bottoms with an initial
boiling point (IBP) of 343oC or vacuum tower bottoms with an
IBP of 566oC.
• In both cases the stream will have higher concentrations of
sulfur, nitrogen, and metals.
277
Hydroprocessing and Resid processing
• And the hydrogen/carbon ratios are much lower.
• This H/C ratio will give high carbon forming potentials of
resids. This will cause rapid catalyst deactivation and high
catalyst costs.
• Also the nickel and vanadium in the resid act as resid for the
formation of gas and coke.
• The case is more severe in the VRC case.
278
Hydroprocessing and Resid processing
• In recent years the density and sulfur content of crude oils
charged to the refineries changed.
• Consequently a higher fraction of crude is in the vacuum
residue.
• Previously it was sold as asphalt or as heavy fuel oil.
279
Hydroprocessing and Resid processing
• Recent environmental emission standards made it more
difficult and expensive to burn these fuels.
• So the need aroused for converting more oil in the refinery
feedstock to transportation fuel blending stocks.
280
Hydroprocessing and Resid processing
281
Hydroprocessing and Resid processing
• As a result, catalytic processes for converting resid usually use
atmospheric reduced crude (ARC) for their feedstocks.
• And the vacuum reduced crude (VRC) are processed in non
catalytic units.
• The processes used for the ARC feedstocks are catalytic
cracking and hydro processing.
• Thermal cracking processes are used for VRC feedstocks.
282
Processing options
• The types of processes can be classified as catalytic or non
catalytic.
• Catalytic processes are used for ARC feedstocks.
• Non catalytic processes use VRC feed socks and include;
solvent extraction, delayed coking, and flexicoking.
283
Processing options
• The types of processes can be classified as catalytic or non
catalytic.
• Catalytic processes are used for ARC feedstocks.
• Non catalytic processes use VRC feed socks and include;
solvent extraction, delayed coking, and flexicoking.
284
Hydroprocessing
285
Hydroprocessing
• The term hydroprocessing is used to represent the processes
used to reduce the boiling point range of the feedstock and to
remove impurities.
• These impurities include metals, sulfur, nitrogen, and high
carbon forming compounds.
• Other names of this process are hydroconversion,
hydrorefining, and resid HDS.
286
Hydroprocessing
• In US refineries, hydroprocessing units are used to prepare
residual stream feedstocks for cracking and coking units.
• Vacuum resids can be used but most refineries use
atmospheric resids as feedstocks.
• This us due to that it has lower viscosities and impurity levels.
So give higher overall impurity reduction and better
operation.
287
Hydroprocessing
• The heavy naphtha fraction of the products will be
catalytically reformed to improve octanes.
• The atmospheric gas oil fraction is hydrotreated to decrease
the aromatic content and improve the cetane number.
• Vacuum gas oil fraction is used as conventional FCC unit feed.
• And the vacuum tower bottoms is sent to a heavy oil cracker
or coker.
288
Fixed bed reactors
289
Fixed bed reactors
• Most processes have fixed bed reactors and usually require
the units to shut down and the catalyst changed.
• This is when the catalyst activity declines below the accepted
level.
• All units operate at very high pressures (above 13.8 Mpa).
• And low space velocities of 0.2-0.5 v/hr/v.
290
Fixed bed reactors
291
Fixed bed reactors
• The low space velocities and high pressure limit the charge
rates to 4760-6360 M3/SD per train of reactors.
• Each train of reactors will have a guard reactor to reduce the
metals content and carbon forming potential of the feed
stock.
• This is followed by three to four hydroprocessing reactors in
series.
292
Fixed bed reactors
• The guard reactor’s catalyst has large pore sized (150-200 A˚)
silica-alumina catalyst with a low level loading of
hydrogenation metals such as cobalt and molybdenum.
• The catalysts in the other reactors are tailor-made for the
feedstock and the conversion levels desired.
• These may contain a range of pore size and particle size as
well as different catalytic metal loadings and types.
293
Fixed bed reactors
• Typical pore sizes will be in the range 80-100 A˚.
• The process flow is similar to that of the hydrocracking unit.
• With the exception of the amine absorption unit to remove
hydrogen sulfide from the recycle hydrogen stream and the
Guard reactor.
• This is added to protect the catalyst in the reactors train.
294
The process
• The heavy crude oil fed to the atmospheric distillation unit is
desalted to remove as much of the inorganic salt and
suspended solids.
• This is due to that these will be concentrated in the resids.
• The atmospheric resids are filtered before being fed to the
hydroprocessing unit to remove solids greater than 25 A˚ in
size.
295
The process
• After filtration the resid is mixed with the recycle hydrogen.
• Then heated to the reaction temperature, then charged to the
top of the guard reactor.
• Suspended solids in the feed will deposit in the top of the
guard reactor.
• And most of the metals will deposit on the catalyst.
296
The process
• There is a significant reduction in the Conradson and
Ramsbottom carbons in the guard reactor.
• And the feed to the following reactors is low in metals and
carbon forming materials.
• The reactors following the guard reactor are operated to
remove sulfur and nitrogen and to crack the 566+oC material
to lower boiling point compounds.
297
The process
298
The process
• The recycle hydrogen is separated and the hydrocarbon liquid
stream is fractionated in atmospheric and vacuum distillation
columns.
• The table shows the results of hydroprocessing in this reactor.
299
Expanded Bed Hydrocracking
300
Expanded Bed Hydrocracking
• The term expanded bed or elbullated bed is given by HRI and
C-E Lummus to a fluidized bed type operation which utilizes a
mixture of liquids and gasses to expand the catalyst bed
rather than just gases.
• Both use similar technologies but offer different mechanical
designs.
301
Expanded Bed Hydrocracking Hi-oil
302
Expanded Bed Hydrocracking LC-fining
303
Expanded Bed Hydrocracking LC-fining
304
Expanded Bed Hydrocracking
• The preheated feed, recycle and make up hydrogen are
charged to the first reactor of the unit.
• The liquid passes upward through the catalyst which is
maintained as an ebullient bed.
• The first- stage reactor effluent is sent to the second stage
reactor for additional conversion.
305
Expanded Bed Hydrocracking
• The product from the second reactor is passed through a heat
exchanger.
• Then sent to a high pressure separator where the recycle
(hydrogen) gas is removed.
• The liquid from the high pressure separator is sent to a low
pressure flash drum to remove additional gasses.
306
Expanded Bed Hydrocracking
• The liquid stream at low pressure is sent to a rectification
column for separation into products.
• The operating pressure is a function of feed boiling point. The
pressure can be as high as 3000 psig when charging with
vacuum tower resid.
• The operating temperature is a function of feed and
conversion and is in the range of 800-850oF.
307
Expanded Bed Hydrocracking
308
Expanded Bed Hydrocracking
The advantages of the ebullated bed reactor process are:
• The ability to add and remove catalyst while remaining on
stream.
• And to maintain catalyst activity by either regeneration or the
addition of fresh catalyst.
• Also the small solid particles are flushed out of the reactor
and do not contribute to plugging or increasing in pressure
drop.
309
Expanded Bed Hydrocracking
The advantages of the ebullated bed reactor process are:
• Because the unit runs all the time with an equilibrium activity
catalyst with a constant quality feedstock, and constant
operating conditions.
• The product yields and quality will also be constant.
310
Expanded Bed Hydrocracking
• It is necessary to recycle effluent from each reactor’s catalyst
bed into the feed of that reactor.
• This is in order to have velocities that are high enough to keep
the bed expanded, minimize channeling, to control the
reaction rates and to keep heat released by the exothermic
hydrogenation at a safe level.
311
Expanded Bed Hydrocracking
• This back mixing dilutes the reactants so slows down thee
rates of reactions compared to the fixed bed reactors.
• Ebullated bed reactors require up to 3 times the amount of
catalyst per barrel of feed to obtain the same conversion as
the fixed bed reactors.
312
Products from LC- fining cracking
313
Moving Bed Hydroprocessors
314
Moving Bed Hydroprocessors
• This technology combines advantages of fixed bed and
ebullated bed hydroprocessing.
• These systems use reactors designed for catalyst flow by
gravity from the top to bottom with mechanisms designed to
allow spent catalyst to be removed continuously or
periodically.
• This removal is from the bottom and fresh catalyst is added to
the top.
315
Moving Bed Hydroprocessors
• This allows low activity high metal catalyst to be removed
from the reactor and replaced with fresh catalyst while online.
• This design gives lower catalyst consumption rates than
ebullated bed systems.
• This is due to that the ebullated bed system, equilibrium
activity and metals loaded catalyst is removed rather than the
lowest activity spent catalyst.
316
Moving Bed Hydroprocessors
• As there is no recycling of product from the reactor outlets to
the reactor inlet, the reactors operate in a plug flow
condition.
• And reaction rates are the same as in a fixed bed operation.
317
Moving Bed Hydroprocessors
318
Solvent Extraction
319
Solvent extraction
• Solvent extraction is used to extract up to two thirds of the
vacuum reduced crude to be used as good quality feed for a
fluid catalytic cracking unit to convert it to gasoline and diesel
fuel blending stock.
• This technology uses light hydrocarbons (propanes to
pentanes) as the solvents and use subcritical extractions but
use supercritical techniques to recover the solvents.
320
Solvent extraction
• Light hydrocarbons have reverse solubility curves.
• As temperature increases the solubility of higher molecular
weight hydrocarbons decreases.
• Also, paraffinic hydrocarbons have higher solubilities than
aromatic hydrocarbons.
321
Solvent extraction
• A temperature can be selected at which all of the paraffins go
into solution along with the desired percentage of the resid
fraction.
• The higher the molecular weight resins will precipitate along
with asphaltenes.
• The extract is then separated from the precipitated raffinate
fraction and stripped from the solvent by increasing the
temperature to above the critical temperature of the solvent.
322
Solvent extraction
• At the critical temperature the oil plus resin portion will
separate from the solvent.
• And the solvent can be recovered without having to supply
latent heat of vaporization.
• This will reduce the energy requirements by 20-30%
compared to recovery by evaporation.
323
Solvent extraction
• The solvent used is feedstock dependent.
• As the molecular weight of the solvent increases (propane to
pentane), the amount of solvent needed for a given amount
of material extracted decreases.
• But the selectivity of the solvent also decreases.
324
Solvent extraction
• Therefore, the choice of solvent is an economic choice.
• Because for a given recovery of FCC unit feedstock from a
resid, propane will give better quality extract but will use
more solvent.
• Solvent recovery cost will be greater than if the higher
molecular weight solvent is used because more solvent must
be recovered.
325
Solvent extraction
• The higher the molecular weight solvents give lower solvent
recovery cost.
• However, for a given feedstock and yield, give a lower quality
extract and has higher capital costs due to that the critical
pressure of the solvent increases with molecular weight.
• So higher equipment design pressure must be used.
326
Solvent extraction
• Since 80-90% of the metals in the crude are in the
asphaltenes.
• And most of the remaining metals are in the resin fraction. A
good quality FCC unit feed stock is obtained.
• The figure shows the solvent extraction unit flow.
327
Solvent extraction
328
Summary of resid treatment
329
Summary of resid treatment
• Thermal processes (delayed coking and Flexicoking) have the
advantage that the vacuum reduced crude is eliminated so
there is no residual fuel for disposal.
• And most of the VRC is converted to lower-boiling
hydrocarbon fractions suitable for feedstocks to other
processing units to convert them into transportation fuels.
• However, for high-sulfur crude oils, delayed coking produces a
fuel grade coke of high sulfur content.
330
Summary of resid treatment
• This coke may be very difficult to sell. The alternative is
to hydroprocess the feed to the coker to reduce the
coker feed sulfur level and make a low-sulfur coke.
• Flexicoking is more costly than delayed coking, both from
a capital and operating cost viewpoint.
• But has the advantage of converting the coke to a low
heating value fuel gas to supply refinery energy needs
and elemental sulfur for which there is a market.
331
Summary of resid treatment
• A disadvantage is that the fuel gas produced is more than the
typical refinery can use and energy of compression does not
permit it to be transported very far.
• It can be used for cogeneration purposes or sold to nearby
users.
• Hydroprocessing reduces the sulfur and metal contents of the
VRC and improves the hydrogen/carbon ratio of the products
by adding hydrogen.
332
Summary of resid treatment
• But the products are very aromatic and may require a severe
hydrotreating operation to obtain satisfactory middle distillate
fuel blending stocks.
• Crude oils with high sulfur and metal levels will also have high
catalyst replacement costs.
• Solvent extraction recovers 55–70% of the VRC for FCC or
hydrocracker feedstocks to be converted into transportation
fuel blending stocks, but the asphaltene fraction can be
difficult process or sell.
333
Catalytic reforming and Isomerization
334
Catalytic reforming and Isomerization
• The demand of today’s cars for high octane number gasolines
has stimulated the use of catalytic reforming.
• Catalytic reforming products furnish about 30-40% of the US
gasoline requirements.
• This is however expected to decrease due to the
implementation of restrictions on the aromatics (produced in
reforming) content of gasoline.
335
Catalytic reforming and Isomerization
• The catalytic reforming does not change the boiling point of
the feed significantly.
• This is because the small hydrocarbons rearranged to give
higher octane number aromatics.
• With only a minor amount of cracking.
336
Catalytic reforming and Isomerization
• This means that catalytic reforming increases the octane
number of gasoline rather than increasing it’s yield.
• In fact the yield decreases slightly due to the hydrocracking
reactions which are side reaction to the main reforming
operation.
• The feedstocks to catalytic reforming are heavy straight-run
(HSR) gasolines and naphthas (82-190oC) and heavy
hydrocracker naphthas.
337
Catalytic reforming and Isomerization
• These are composed mainly of paraffins, olefins, naphthenes,
and aromatics (PONA analysis).
• The table shows typical PONA analysis for the feed and
products of catalytic reforming.
338
Catalytic reforming and Isomerization
• The paraffins and naphthenes undergo two types of reactions
while being converted to higher octane number components.
• These reactions are crystallization and isomerization.
• The ease and probability of either of these occurring increases
with the number of carbon atoms in the molecules.
• This is why only HSR gasoline is used for catalytic reformer
feed.
339
Catalytic reforming and Isomerization
• The light straight run gasoline (C5 82oC) is largely composed of
lower molecular weight paraffins.
• These tend to break to butane and lighter fractions.
• This makes it not economic to process this stream in a
catalytic reformer.
• Hydrocarbons with high boiling point (204oC) are easily
hydrocracked and cause excessive carbon deposit on catalyst.
340
Reactions
341
Reactions
• In any series of complex reactions, side reactions occur which
produce undesirable products along with the main reaction
producing the desired products.
• Reaction conditions must be chosen to favor the desired
reactions over the undesired ones.
342
Reactions
Desirable reactions in a catalytic reformer all lead to the
formation of aromatics and iso-paraffins:
• Paraffins are isomerized and to some extent converted to
naphthenes. The naphthenes are subsequently converted to
aromatics.
• Olefins are saturated to form paraffins which then react as
previous.
• Naphthenes are converted to aromatics.
• Aromatics are left essentially unchanged.
343
Reactions
Reactions leading to the formation of undesirable products:
• Dealkylation of side chains on naphthenes and aromatics to
form butane and lighter paraffins
• Cracking of paraffins and naphthenes to form butane and
lighter paraffins
344
Reactions
• As the catalyst ages, it is necessary to change the process
operating conditions.
• This is to maintain the reaction severity.
• And so suppress the undesired side reactions which give the
undesired products.
345
Reactions
There are four major reactions that take place during reforming:
• Dehydrogenation of naphthenes to aromatics.
• Dehydrocyclization of paraffins to aromatics.
• Isomerization.
• Hydrocracking.
The first two of these reactions involve dehydrogenation and will
be discussed together.
346
Dehydrogenation Reactions
347
Dehydrogenation Reactions
• The dehydrogenation reactions are highly endothermic and
cause a decrease in temperature as the reaction goes on.
• Also they have the highest rates of the reforming reactions
which necessitates the use of interheaters between catalyst
beds.
• This is to keep the mixture at sufficiently high temperature for
the reactions to proceed as the desired rates.
348
Dehydrogenation Reactions
The major dehydrogenation reactions are:
1- Dehydrogenation of alkylcyclohexanes to aromatics.
349
Dehydrogenation Reactions
The major dehydrogenation reactions are:
2- Dehydroisomerization of alkylcyclopentanes to aromatics.
350
Dehydrogenation Reactions
The major dehydrogenation reactions are:
3- Dehydrocyclization of paraffins to aromatics.
351
Dehydrogenation Reactions
• The dehydrogenation of cyclohexane derivatives is much
faster than the dehydroisomerization and the
dehydrocyclization.
• However all three reactions take place simultaneously.
• And are necessary to obtain the aromatic concentration
needed the reformate product.
352
Dehydrogenation Reactions
• Aromatics have higher liquid density than paraffins or
naphthenes with the same number of carbon atoms.
• So 1 volume of paraffins produces 0.77 volumes of aromatics.
• And 1 volume of naphthenes produces 0.87 volume of
aromatics.
• Also conversion to aromatics increases the gasoline end point
because the boiling point of aromatics is higher than that of
paraffins and naphthenes with the same number of C atoms.
353
Dehydrogenation Reactions
The yield of aromatics is increased by:
• High temperature (increases reaction rate but adversely
affects chemical equilibrium).
• Low pressure (shifts chemical equilibrium ‘‘to the right’’).
• Low space velocity (promotes approach to equilibrium).
• Low hydrogen-to-hydrocarbon mole ratios (shifts chemical
equilibrium ‘‘to the right’’)
354
Isomerization reactions
355
Isomerization reactions
• Isomerization of paraffins and cyclopentanes usually results in
lower octane products than conversion to aromatics.
• However there is a significant increase over the un-isomerized
materials.
• These are fairly rapid reactions with small heat effects.
356
Isomerization reactions
Isomerization reactions include:
1- Isomerization of normal paraffins to isoparaffins.
357
Isomerization reactions
Isomerization reactions include:
2- Isomerization of alkylcyclopentanes to cyclohexanes and
subsequent conversion to benzene.
358
Isomerization reactions
Isomerization yield is increased by:
• High temperature (which increases reaction rate).
• Low space velocity.
• Low pressure.
• There is no isomerization effect due to the hydrogen to
carbon mole ratio. But high hydrogen to carbon ratios reduce
the carbon partial pressure thus favor the formation of
isomers.
359
Hydrocracking Reactions
360
Hydrocracking Reactions
• The hydrocracking reactions are exothermic and result in the
production of lighter liquid and gas products.
• They are relatively slow reactions and therefore most of the
hydrocracking occurs in the last section of the reactor.
• The concentration of paraffins in the charge stock determines
the extent of the hydrocracking reaction.
• But the relative fractions of isomers produced in any
molecular weight group is independent of the charge stock.
361
Hydrocracking Reactions
• The major hydrocracking reactions involve cracking and
saturation of paraffins.
362
Hydrocracking Reactions
Hydrocracking yields are increased by:
• High temperature.
• High pressure.
• Low space velocity.
• In order to obtain high product quality and yields, it is
necessary to control the hydrocracking and aromatization
reactions. This is done by monitoring the reactor
temperatures. To observe the extent of each reaction.
363
Feed preparation
• The active material in most catalytic reforming catalysts is
platinum.
• Some metals along with hydrogen sulfide, ammonia, and
organic nitrogen and sulfur compounds will deactivate the
catalyst.
• Feed preparation in the form of hydrotreating is usually
employed to remove these materials.
364
Feed preparation
• The hydrotreater employs a cobalt-molybdenum catalyst to
convert organic sulfur and nitrogen compounds to hydrogen
sulfide and ammonia.
• These are then removed from the system with the unreacted
hydrogen.
• The metals in the feed are retained by the hydrotreater
catalyst.
365
Feed preparation
• Hydrogen needed for the hydrotreater is obtained from the
catalytic reformer.
• If the boiling point range of the charge stock must be changed
the feed is redistilled before being charged to the catalytic
reformer.
366
Catalytic reforming process
367
Catalytic reforming process
• Reforming processes are classified as continuous, cyclic, or
semiregenerative depending upon the frequency of catalyst
regeneration.
• The equipment for the continuous process is designed to
permit the removal and replacement of catalyst during
operation.
• As a result, the catalyst can be regenerated continuously and
maintained at a high activity.
368
Catalytic reforming process
• As increased coke laydown and thermodynamic equilibrium
yields of reformate are both favored by low pressure.
• The ability to maintain high catalyst activities and selectivities
by continuous catalyst regeneration is the major advantage of
the continuous type.
• This advantage has to be evaluated with respect to the higher
capital costs and possible lower operating costs due to lower
hydrogen recycle rates and pressure needed to keep coke
laydown as low as possible.
369
Catalytic reforming process
• The semi regenerative unit is at the other end of the
spectrum and has the advantage of minimum capital cost.
• Regeneration requires the unit to be taken off-stream.
• Depending upon the severity of operation, regeneration is
required at intervals of 3 to 24 months.
• High hydrogen recycle rates along with the operating
pressures are utilized to minimize coke laydown.
370
Catalytic reforming process
• The cyclic process is a compromise between these extremes
and is characterized by having a swing reactor in addition to
those on-stream.
• Which catalyst can be regenerated without shutting the unit
down.
• When the activity of the catalyst in one of the on-stream
reactors drops below the desired level, this reactor is isolated
from the system and replaced by the swing reactor.
371
Catalytic reforming process
• The catalyst in the replaced reactor is then regenerated by
feeding hot air to it to burn the carbon off the catalyst.
• After regeneration it is used to replace the next reactor
needing regeneration.
• The reforming process can be done as continuous or
semiregenerative operation.
• And other processes as either continuous, cyclic or
semiregenerative.
372
The process
• The reforming semiregenerative process is typically a fixed
bed reactor.
• The pretreated feed and recycle hydrogen are heated to 500520oC then fed to the first reactor.
• In the first reactor the major reaction is the dehydrogenation
of naphthenes to aromatics.
• This reaction is strongly endothermic, so a large drop in
temperature occurs.
373
Continuous reforming
374
Semi regenerative reforming
375
The process
• To maintain the reaction rate, the gases are reheated before
being passed over the catalyst in the second reactor.
• As the charge proceeds through the reactors, the reaction
rate decreases and the reactors become larger, and the reheat
needed becomes less.
• Three or four reactors are sufficient to provide the desired
degree of reaction and heaters are needed before each
reactor to bring the mixture to the reaction temperature.
376
Semi regenerative reforming
377
The process
• Several heaters can be used or one heater with several
separate coils.
• The table shows the gas composition leaving each reactor.
378
The process
• The reaction mixture from the last reactor is cooled and the
liquid products are condensed.
• The hydrogen rich gas stream is split into a hydrogen recycle
stream and a net hydrogen by-product.
• This is used in hydrotreating or hydrocracking or as fuel.
379
Operating conditions
• The reformer operating pressure and hydrogen/feed ratio are
compromised among obtaining maximum yields, long
operating times between regeneration, and stable operation.
• The operating pressure is 350-2400 kPa. And the hydrogen to
charge ratio is 3-8 mol hydrogen/mol feed.
• The liquid hourly space velocity is in the range of 1-3.
380
The process
• The original reforming process is classified as a semi
regenerative type.
• Because catalyst regeneration is infrequent and runs 6 to 24
months before needing regeneration.
• The cyclic process regeneration is done on a 24 or a 48 hour
cycle.
381
The process
• And a spare reactor is provided so regeneration can be done
while on stream.
• Because of the extra facilities the cyclic process is more
expensive.
• But offer the advantaged of lower pressure operation and
higher yields of reformate at the same severity.
382
Reforming Catalyst
383
Reforming Catalyst
• The reforming catalysts used today contain platinum
supported on an alumina base.
• In most cases rhenium is combined with platinum to form a
more stable catalyst which permits operation at lower
pressures.
• Platinum serves as a catalytic site for hydrogenation and
dehydrogenation reactions.
384
Reforming Catalyst
• And chlorinated alumina provides acid sites for isomerization,
cyclization, and hydrocracking reactions.
• Reforming catalyst activity is a function of surface area, pore
volume, and active platinum and chloride content.
• Catalyst activity is reduced during operation by coke
deposition and chloride loss.
385
Reforming Catalyst
• In a high pressure process, up to 200 barrels of feed can be
processed per pound of catalyst before regeneration is
needed.
• The catalyst can be regenerated by high temperature
oxidation of the carbon followed by chlorination.
• This process is referred to as semiregenerative and can
operate for 6-24 month periods between regenerations.
386
Reforming Catalyst
• The activity of the catalyst decreases during the on stream
period and the reaction temperature is increased as the
catalyst ages to maintain the desired severity.
• Normally the catalyst can be regenerated in situ at least 3
times before It has to be replaced and returned to the
manufacturer for reclamation.
387
Reforming Catalyst
• Catalysts for fixed bed reactors are extruded into cylinders
0.8-1.6 mm diameter with lengths about 5mm.
• Catalyst for continuous units is spherical with diameters
approximately 0.8 to 1.6 mm.
388
Reactor Design
389
Reactor Design
• Fixed bed reactors used for semi regenerative and cyclic
catalytic vary in size and mechanical details.
• But all have the same basic features.
• Very similar reactors are used for hydrotreating,
isomerization, and hydrocracking.
390
Reactor Design
• The reactors have an internal refractory lining which is
provided to insulate the shell from the high reaction
temperatures.
• Thus reduces the metal thickness needed.
• Metal parts exposed to the high temperature hydrogen
atmosphere are constructed from steel.
• Containing at least 5% chromium and 0.5% molybdenum.
391
Reactor Design
• This steel is used to resist hydrogen embrittelment.
• Proper distribution of the inlet vapor is necessary to make
maximum use of the available catalyst.
• Some reactor designs provide radial vapor flow rather than
the simpler straight-through type in the figure.
392
Reactor Design
393
Reactor Design
• The important feature of vapor distribution is to provide
maximum contact time with minimum pressure drop.
• Temperature measurement of 3 elevations in the catalyst bed
is considered essential.
• This is to determine the catalyst activity and as an aid during
coke burn off operation.
394
Reactor Design
• The catalyst pellets are generally supported on a bed of
ceramic spheres about 30-40 cm deep.
• The spheres vary in size from about 25mm on the bottom to
about 9mm on the top.
395
Isomerization
396
Isomerization
• The octane number of the LSR naphtha (C5 82oC) can be
improved by the use of an isomerization process.
• This is to convert normal paraffins to their isomers.
• This results in significant octane increases as n-pentane has an
octane number of 61.7 and isopentane has a rating of 92.3.
397
Isomerization
• In once through isomerization where thermodynamic
equilibrium is reached the octane number of naphtha
increased from 70 to 84.
• If the normal components are recycled the resulting octane
number will be 87-93.
• All octane numbers specified are research octane numbers
(ROC).
398
Isomerization
• Reaction temperatures of about 95-205oC are preferred to
higher temperatures.
• Because the equilibrium conversion to isomers is enhanced at
lower temperatures.
• At these low temperatures, very active catalyst is necessary to
provide a reasonable reaction rate.
399
Isomerization
• The available catalysts used for isomerization contain
platinum on various bases.
• Some types of catalysts require the continuous addition of
very small amounts of organic chlorides to maintain high
catalyst activities.
• This is converted to hydrogen chloride in the reactor and
consequently the feed to these units must be free of water
and other oxygen sources to avoid catalyst deactivation.
400
Isomerization
• The second type of catalyst used is the molecular sieve base,
and is reported to tolerate feeds saturated with water at
ambient temperature.
• The third type of catalyst is the type that contains platinum
supported on a novel metal oxide base.
• This catalyst has 83oC higher activity than conventional zeolite
isomerization catalyst and can be regenerated.
401
Isomerization
• Catalyst life is usually 3 years or more for all these catalysts.
• Hydrogen at 1 atmosphere is used to minimize carbon
deposits on the catalyst.
• Hydrogen consumption in this process is negligible.
• The composition of the reactor products can closely approach
chemical equilibrium.
402
Isomerization
• The actual product distribution is dependent upon the type
and age of the catalyst, the space velocity, and the reactor
temperature.
• The pentane fraction of the reactor product is about 75-80
wt% iso-pentane, and the hexane fraction is 86-90 wt%
hexane isomers.
403
Isomerization
• If the normal pentane in the reactor product is separated and
recycled, the product RON can be increased from 83 to 86.
• If both normal pentane and normal hexane are recycled, the
product RON can be improved to about 87-90.
• Separation of the normals from the isomers can be done by
fractionation or by vapor phase adsorption of the normals on
a molecular sieve bed.
404
Isomerization
• Some hydrocracking occurs during the reactions, resulting in a
loss of gasoline and the production of light gas.
• The amount of gas formed varies with the catalyst type and
age and is sometimes a significant economic factor.
• The light gas produced is typically in the range of 1-4 wt% of
the HC feed.
405
Isomerization
406
Isomerization
• The composition of the gas can be assumed to be 95 wt%
methane and 5 wt% ethane.
• For refineries that do not have hydrocracking facilities to
supply isobutane for alkylation unit feed.
• The necessary isobutane can be made from n-butane by
isomerization.
407
Isomerization
• The process is very similar to LSR gasoline isomerization but a
feed deisobutanizer is used to concentrate the n-butane in
the reactor charge.
• The reactor product is about 58-62 wt% isobutane.
408
Isomerization
409
Isomerization operating conditions
410
Alkylation and Polymerization
411
Alkylation and Polymerization
• The alkylation reaction is the addition of an alky group to any
compound.
• But in petroleum refining terminology the term alkylation is
used for the reaction of a low molecular weight olefin with an
iso paraffin to form higher molecular weight iso paraffins.
• Although this reaction is simply the reverse of cracking, the
belief that paraffin hydrocarbons are chemically inert delayed
its discovery until about 1935.
412
Alkylation and Polymerization
• The need for high-octane aviation fuels during World War II
acted as a stimulus to the development of the alkylation
process for production of isoparaffinic gasolines of high
octane number.
• Although alkylation can take place at high temperatures and
pressures without catalysts, the only processes of commercial
importance involve low-temperature alkylation conducted in
the presence of either sulfuric or hydrofluoric acid.
413
Alkylation and Polymerization
• The reactions occurring in both processes are complex and
the product has a rather wide boiling range.
• By proper choice of operating conditions, most of the product
can be made to fall within the gasoline boiling range.
•
With motor octane numbers from 88 to 94 and research
octane numbers from 94 to 99.
414
Alkylation Reactions
415
Alkylation Reactions
• In alkylation processes using hydrofluoric or sulfuric acids as
catalysts, only iso-paraffins with tertiary carbon atoms, such
as iso butane or iso pentane, react with olefins.
• In practice only iso butane is used because iso pentane has a
sufficiently high octane number and low vapor pressure to
allow it to be effectively blended directly into finished
gasolines.
• The process using sulfuric acid as a catalyst is much more
sensitive to temperature than the hydrofluoric acid process.
416
Alkylation Reactions
• With sulfuric acid it is necessary to carryout the reactions at
5to 21°C or lower.
• To minimize oxidation reduction reactions which result in the
formation of tars and the evolution of sulfur dioxide.
• When anhydrous hydrofluoric acid is the catalyst, the
temperature is usually limited to 38°C or lower.
417
Alkylation Reactions
• In both processes the volume of acid employed is about equal
to that of the liquid hydrocarbon charge.
• And sufficient pressure is maintained on the system to keep
the hydrocarbons and the acid in the liquid state.
• High iso paraffin/olefin ratios (4:1 to 15:1) are used to
minimize polymerization and to increase product octane.
418
Alkylation Reactions
• Efficient agitation is needed to promote contact between the
acid and hydrocarbon phases to ensure high product quality
and yields.
• Contact times from 10 to 40 minutes are in general use.
• The yield, volatility, and octane number of the product is
regulated by adjusting the temperature, acid/hydrocarbon
ratio, and iso paraffin/olefin ratio.
419
Alkylation Reactions
• At the same operating conditions, the products from the
hydrofluoric and sulfuric acid alkylation process are quite
similar.
• In practice, however, the plants are operated at different
conditions and the products are somewhat different.
420
Alkylation Reactions
For both processes the more important variables are:
•
•
•
•
Reaction temperature.
Acid strength.
Isobutane concentration.
Olefin space velocity.
421
Alkylation Reactions
• The main reactions which occur in alkylation are the
combination of olefins with iso paraffins.
Isobutane
Isobutylene
2, 2, 4-trimethylpentane
(Isooctane)
422
Alkylation Reactions
• Another significant reaction in propylene alkylation is the
combination of propylene with iso butane to form propane
plus isobutylene. The isobutylene then reacts with more iso
butane to form 2,2,4-trimethylpentane (isooctane).
423
Alkylation Reactions
• The first step involving the formation of propane is referred to
as a hydrogen transfer reaction.
• Research on catalyst modifiers is being conducted to promote
this step since it produces a higher octane alkylate than is
obtained by formation of iso heptanes.
• The alkylation reaction is highly exothermic, with the
liberation of 124,000 to 140,000Btu per barrel of iso butane
reacting.
424
Process Variables
The most important process variables are:
• Reaction temperature:
Greater effect in sulfuric acid processes. Lower temperature
means higher quality.
• Acid strength:
Has varying effects on alkylate quality depending on the
effectives of the reactor mixing and the water content in the
acid. The water concentration in the acid lowers it’s catalytic
activity about 3 to 5 times as much as the HC diluents.
425
Process Variables
• Iso butane concentration:
Is expressed in terms of iso butane/olefin ratio. High ratio
increases the octane number and yield and reduce the side
reactions and acid consumption.
• Olefin space velocity:
Is defined as the volume of olefin charged per hour divided by
the volume of the acid in the reactor. Lowering it reduces the
amount of high boiling HC and increases the octane. It is used to
express the reaction time.
426
Alkylation Feedstocks
427
Alkylation Feedstocks
• Olefins and iso butane are used as alkylation unit feedstocks.
• The chief sources of olefins are catalytic cracking and coking
operations.
• Butenes and propene are the most common olefins used, but
pentenes are included in some cases.
• Some refineries include pentenes in alkylation unit feed to
lower the FCC gasoline vapor pressure and reduce the
bromine number in the final gasoline blend.
428
Alkylation Feedstocks
• Alkylation of pentenes is also considered as a way to reduce
the C5 olefin content of final gasoline blends.
• And reduce its effects on ozone reduction and visual pollution
in the atmosphere.
• Olefins can be produced by dehydrogenation of paraffins, and
isobutane is cracked commercially to provide alkylation unit
feed.
429
Alkylation Feedstocks
• Hydrocrackers and catalytic crackers produce a great deal of
the iso butane used in alkylation.
• But it is also obtained from catalytic reformers, crude
distillation, and natural gas processing.
• In some cases, normal butane is isomerized to produce
additional isobutane for alkylation unit feed.
430
Alkylation Products
431
Alkylation Products
• The products leaving the alkylation unit include the alkylate
stream.
• And propane and normal butane that enter with the saturated
and unsaturated feed streams.
• As well as a small quantity of tar produced by polymerization
reactions.
432
Alkylation Products
The product streams leaving an alkylation unit are:
• LPG grade propane liquid.
• 2.Normal butane liquid.
• C5+alkylate.
• Tar.
433
Catalysts
434
Catalysts
• Concentrated sulfuric and hydrofluoric acids are the only
catalysts used commercially today for the production of high
octane alkylate gasoline.
• However other catalysts are used to produce ethyl benzene,
cumene, and long-chain C12to C16) alkylated benzenes.
435
Catalysts
• As previously discussed, the desirable reactions are the
formation of C8 carbonium ions and the subsequent
formation of alkylate.
• The main undesirable reaction is polymerization of olefins.
• Only strong acids can catalyze the alkylation reaction but
weaker acids can cause polymerization to take place.
436
Catalysts
• Therefore, the acid strengths must be kept above 88% by
weightH2SO4or HF in order to prevent excessive
polymerization.
• Sulfuric acid containing free SO3also causes undesired side
reactions and concentrations greater than 99.3% H2SO4 are
not generally used.
437
Catalysts
• Iso butane is soluble in the acid phase only to the extent of
about 0.1% by weight in sulfuric acid.
• And about 3% in hydrofluoric acid.
• Olefins are more soluble in the acid phase and a slight amount
of polymerization of the olefins is desirable.
•
This is due to that polymerization products dissolve in the
acid and increase the solubility of iso butane in the acid
phase.
438
Catalysts
• If the concentration of the acid becomes less than 88%, some
of the acid must be removed and replaced with stronger acid.
•
In hydrofluoric acid units the acid removed is redistilled and
the polymerization products removed as a thick, dark ‘‘acid
soluble oil’’ (ASO).
• The concentrated HF is recycled in the unit. The net
consumption is about 0.3 lb per barrel of alkylate produced
439
Catalysts
• Unit inventory of hydrofluoric acid is about 25–40 lb acid per
BPD of feed.
• The sulfuric acid removed usually is regenerated in a sulfuric
acid plant which is generally not a part of the alkylation unit.
• The acid consumption typically ranges from 13 to 30 lb per
barrel of alkylate produced.
• Makeup acid is usually 98.5 to 99.3 wt% H2SO4.
440
Yields and Isobutane Requirements
441
Yields and Isobutane Requirements
• Only about 0.1% by volume of olefin feed is converted into tar.
• This is not truly a tar but a thick dark brown oil containing
complex mixtures of conjugated cyclopentadienes with side
chains
442
Operating Conditions
443
Hydrofluoric Acid Processes
444
Hydrofluoric Acid Processes
• Both the olefin and isobutane feeds are dehydrated by
passing the feed-stocks through a solid bed desiccant unit.
• Good dehydration is essential to minimize potential corrosion
of process equipment which results from addition of water to
hydrofluoric acid.
• After dehydration the olefin and isobutane feeds are mixed
with hydrofluoric acid at sufficient pressure to maintain all
components in the liquid phase.
445
Hydrofluoric Acid Processes
446
Hydrofluoric Acid Processes
• The bottom product from the rerun column is a mixture of tar
and an HF–water azeotrope.
• These components are separated in a tar settler (not shown
on the flow diagram).
• The tar is used for fuel and the HF–water mixture is
neutralized with lime or caustic.
• This rerun operation is necessary to maintain the activity of
the hydrofluoric acid catalyst.
447
Hydrofluoric Acid Processes
• The reaction mixture is allowed to settle into two liquid layers.
• The acid has a higher density than the hydrocarbon mixture
and is withdrawn from the bottom of the settler.
•
And passed through a cooler to remove the heat gained from
the exothermic reaction.
• The acid is then recycled and mixed with more fresh feed,
thus completing the acid circuit.
448
Hydrofluoric Acid Processes
• A small slip-stream of acid is withdrawn from the settler and
fed to an acid rerun column to remove dissolved water and
polymerized hydrocarbons.
• The acid rerun column contains about five trays and operates
at 1034 kPa.
• The overhead product from the rerun column is clear
hydrofluoric acid which is condensed and returned to the
system.
449
Hydrofluoric Acid Processes
• The hydrocarbon layer removed from the top of the acid
settler is a mixture of propane, isobutane, normal butane, and
alkylate along with small amounts of hydrofluoric acid.
• These components are separated by fractionation and the iso
butane is recycled to the feed.
• Propane and normal butane products are passed through
caustic treaters to remove trace quantities and hydrofluoric
acid.
450
Hydrofluoric Acid Processes
• Although the flow sheet shows the fractionation of propane,
isobutane, normal butane, and alkylate to require three
separate fractionators.
• Many alkylation plants have a single tower where propane is
taken off overhead.
• A partially purified isobutane recycle is withdrawn as a liquid
several trays above the feed tray.
451
Hydrofluoric Acid Processes
• A normal butane product is taken off as a vapor several trays
below the feed tray and the alkylate is removed from the
bottom.
• The design of the acid settler–cooler–reactor section is critical
to the good conversion in a hydrofluoric acid alkylation
system.
• Many of the reactor systems are similar to a horizontal shell
and tube heat exchanger with cooling water flowing inside the
tubes to control the reaction temperatures.
452
Hydrofluoric Acid Processes
453
Hydrofluoric Acid Processes
• Good mixing is achieved in the reactor by using a recirculating
pump to force the mixture through the reactor.
• A second type of reactors design is that acid circulation in this
system is by gravity differential.
•
Thus a relatively expensive acid circulation pump is not
necessary.
454
Hydrofluoric Acid Processes
455
Hydrofluoric Acid Processes
• In portions of the process system where it is possible to have
HF–water mixtures, the process equipment is fabricated from
Monel metal or Monel-cladsteel. The other parts of the
system are carbon steel.
• Special precautions are taken to protect maintenance and
operating personnel from injury by accidental contact with
acid.
456
Hydrofluoric Acid Processes
• In portions of the process system where it is possible to have
HF–water mixtures, the process equipment is fabricated from
Monel metal or Monel-cladsteel. The other parts of the
system are carbon steel.
• Special precautions are taken to protect maintenance and
operating personnel from injury by accidental contact with
acid.
457
Hydrofluoric Acid Processes Yields
458
Alkylate Properties
459
Sulfuric Acid Alkylation Process
460
Sulfuric Acid Alkylation Process
• There are two major processes that use sulfuric acid as
catalyst.
• Autorefrigeration process, and the effluent refrigeration
process.
• The autorefrigeration process uses a multistage cascade
reactor with mixers in each stage to emulsify the
hydrocarbon–acid mixture.
461
Sulfuric Acid Alkylation Process
• Olefin feed or a mixture of olefin feed and isobutane feed is
introduced into the mixing compartments.
• And enough mixing energy is introduced to obtain sufficient
contacting of the acid catalyst with the hydrocarbon reactants
to obtain good reaction selectivity.
• The reaction is held at a pressure of approximately 69 kPag in
order to maintain the temperature at about 5°C.
462
Sulfuric Acid Alkylation Process
• In the Stratco, or similar type of reactor system, pressure is
kept high enough 310–420 kPag to prevent vaporization of
the hydrocarbons.
• In the first process, acid and iso butane enter the first stage of
the reactor and pass in series through the remaining stages.
• The olefin hydrocarbon feed is split and injected into each
of the stages.
463
Sulfuric Acid Alkylation Process
• Then the olefin feed is mixed with the recycle isobutane and
introduces the mixture into the individual reactor sections.
• The gases vaporized to remove the heats of reaction and
mixing energy are compressed and liquefied.
• A portion of this liquid is vaporized in an economizer to cool
the olefin hydrocarbon feed before it is sent to the reactor.
• The vapors are returned for recompression.
464
Sulfuric Acid Alkylation Process
• The remainder of the liquefied hydrocarbon is sent to a
depropanizer column for removal of the excess propane
which accumulates in the system.
• The liquid isobutane from the bottom of the depropanizer is
pumped to the first stage of the reactor.
• The acid–hydrocarbon emulsion from the last reactor stage is
separated into acid and hydrocarbon phases in a settler.
465
Sulfuric Acid Alkylation Process
• The acid is removed from the system for reclamation, and the
hydrocarbon phase is pumped through a caustic wash
followed by a water wash to eliminate trace amounts of acid
and then sent to a deisobutanizer.
• The deisobutanizer separates the hydrocarbon feed stream
into isobutane, n-butane, and alkylate product.
466
Autorefrigeration sulfuric acid alkylation unit
467
Sulfuric Acid Alkylation Process
• The effluent refrigeration process (Stratco) uses a single-stage
reactor in which the temperature is maintained by cooling
coils.
• The reactor contains an impeller that emulsifies the acid–
hydrocarbon mixture and recirculates it in the reactor.
• Average residence time in the reactor is on the order of 20 to
25 minutes.
468
Stratco contactor
469
Sulfuric Acid Alkylation Process
• Emulsion removed from the reactor is sent to a settler for
phase separation.
• The acid is recirculated and the pressure of the hydrocarbon
phase is lowered to flash vaporize a portion of the stream and
reduce the liquid temperature to about -1°C.
• The cold liquid is used as coolant in the reactor tube bundle.
470
Sulfuric Acid Alkylation Process
• The flashed gases are compressed and liquefied, then sent to
the depropanizer where LPG grade propane and recycle
isobutane are separated.
• The hydrocarbon liquid from the reactor tube bundle is
separated into isobutane, n-butane, and alkylate streams in
the deisobutanizer column.
• The isobutane is recycled and n-butane and alkylate are
product streams.
471
Sulfuric Acid Alkylation Process
• A separate distillation column can be used to separate the nbutane from the mixture or it can be removed as a side
stream from the deisobutanizing column.
• Separating n-butane as a side stream from the
deisobutanizing can be restricted because the pentane
content is usually too high to meet butane sales
specifications.
• The side-stream n-butane can be used for gasoline blending.
472
Sulfuric Acid Alkylation Process yields and qualities
473
Polymerization
474
Polymerization
• Propene and butenes can be polymerized to form a highoctane product boiling in the gasoline boiling range.
• The product is an olefin having unleaded octane numbers of
97 RON and 83 MON.
• The polymerization process was widely used in the 1930s and
1940s to convert low-boiling olefins into gasoline blending
stocks.
475
Polymerization
• But was supplanted by the alkylation process after World War
II.
• The mandated reduction in use of lead in gasoline and the
increasing proportion of the market demand for unleaded
gasolines created a need for low-cost processes to produce
high-octane gasoline blending components.
• Polymerization produces about 0.7 barrels of polymer
gasoline per barrel of olefin feed as compared with about 1.5
barrels of alkylate by alkylation.
476
Polymerization
• And the product has a high octane sensitivity, but capital and
operating costs are much lower than for alkylation.
• As a result, polymerization processes are being added to some
refineries.
477
Polymerization Reactions
• while iC4H8 reacts to give primarily diisobutylene, propene
gives mostly trimers and dimers with only about 10%
conversion to dimer.
478
Polymerization Reactions
• The most widely used catalyst is phosphoric acid on an inert
support.
• This can be in the form of phosphoric acid mixed with
kieselguhr (a natural clay).
• Or a film of liquid phosphoric acid on crushed quartz.
• Sulfur in the feed poisons the catalyst and any basic materials
neutralize the acid and increase catalyst consumption.
479
Polymerization Reactions
• Oxygen dissolved in the feed adversely affects the reactions
and must be removed.
•
Normal catalyst consumption rates are in the range of one
pound of catalyst per 100 to 200 gallons of polymer produced
(830 to 1660 l/kg).
480
The process
• The feed, consisting of propane and butane as well as
propene and butene, is contacted with an amine solution to
remove hydrogen sulfide.
• Then caustic washed to remove mercaptans.
• It is then scrubbed with water to remove any caustic or
amines and then dried by passing through a silica gel or
molecular sieve bed.
481
The process
• Finally, a small amount of water (350–400 ppm) is added to
promote ionization of the acid.
• Then the olefin feed steam is heated to about 204°C and
passed over the catalyst bed.
• Reactor pressures are about 3450 kPa.
• The polymerization reaction is highly exothermic and
temperature is controlled either by injecting a cold propane
quench or by generating steam.
482
The process
• The propane and butane in the feed act as diluents and a heat
sink to help control the rate of reaction and the rate of heat
release.
• Propane is also recycled to help control the temperature.
• After leaving the reactor the product is fractionated to
separate the butane and lighter material from the polymer
gasoline.
483
The process
• Gasoline boiling range polymer production is normally 90–97
wt% on olefin feed or about 0.7 barrel of polymer per barrel
of olefin feed.
• The next slide has the process flow diagram for the (Universal
oil products company (UOP) unit. And the following has the
operating conditions.
484
The UOP Unit
485
Operating Conditions
486
The process
• Insitut Francais du Petrole licenses a process to produce
dimate (isohexene) from propene.
•
Tis uses a homogeneous aluminum alkyl catalyst which is not
recovered.
• The process requires a feed stream that is better than 99%
propane.
• And propene because C2s and C4s poison the catalyst.
487
The process
• Dienes and triple bonded hydro-carbons can create problems.
• And in some cases it is necessary to selectively hydrogenate
the feed to eliminate these compounds.
• The major advantage of this process is the low capital cost
because it operates at low pressures.
488
The Insitut Francais du Petrole Unit
489
Product Blending
490
Product Blending
• Increased operating flexibility and profits result when refinery
operations produce basic intermediate streams that can be
blended to produce a variety of on-specification finished
products.
• For example, naphthas can be blended into either gasoline or
jet fuel, depending upon the product demand.
• Aside from lubricating oils, the major refinery products
produced by blending are gasolines, jet fuels, heating oils, and
diesel fuels.
491
Product Blending
• The objective of product blending is to allocate the available
blending components in such a way as to meet product
demands and specifications.
• At the least cost and to produce incremental products which
maximize overall profit.
• The volumes of products sold, even by a medium-sized
refiner, are so large that savings of a fraction of a cent per
gallon will produce a substantial increase in profit over the
period of one year.
492
Product Blending
• For example, if a refiner sells about one billion gallons of
gasoline per year (about 65,000 BPCD; several refiners sell
more than that in the United States).
• A saving of one one-hundredth of a cent per gallon results in
an additional profit of $100,000 per year.
• Today most refineries use computer-controlled in-line
blending for blending gasolines and other high-volume
products.
493
Product Blending
• Inventories of blending stocks, together with cost and physical
property data are maintained in the computer.
• When a certain volume of a given quality product is specified,
the computer uses linear programming models to optimize
the blending operations.
• This is to select the blending components to produce the
required volume of the specified product at the lowest cost.
494
Product Blending
• To ensure that the blended streams meet the desired
specifications, stream analyzers measuring the properties of
the product are needed.
• These include boiling point, specific gravity, RVP, and research
and motor octane.
• These analyzers provide feedback control of additives and
blending streams.
495
Product Blending
• Blending components to meet all critical specifications most
economically is a trial-and-error procedure.
• Which is easy to handle with the use of a computer.
• The large number of variables makes it probable there will be
a number of equivalent solutions that give the approximate
equivalent total overall cost or profit.
496
Product Blending
• Optimization programs permit the computer to provide the
optimum blend to minimize cost and maximize profit.
• The same basic techniques are used for calculating the
blending components for any of the blended refinery
products.
• Gasoline is the largest volume refinery product and will be
used as an example to help clarify the procedures.
497
Reid Vapor Pressure
498
Reid Vapor Pressure
• The desired RVP of a gasoline is obtained by blending nbutane with C5 193°C naphtha.
• The amount of n-butane required to give the needed RVP is
calculated by:
499
Reid Vapor Pressure
• The theoretical method for blending to the desired Reid vapor
pressure requires that the average molecular weight of each
of the streams be known.
• There are accepted ways of estimating the average molecular
weight of a refinery stream from boiling point, gravity, and
characterization factor.
• However a more convenient way is to use the empirical
method developed by Chevron Research Company.
500
Reid Vapor Pressure
• Vapor pressure blending indices (VPBI) have been compiled as
a function of the RVP of the blending.
• The Reid vapor pressure of the blend is closely approximated
by the sum of all the products of the volume fraction (v) times
the VPBI for each component.
501
Reid Vapor Pressure
• In equation form:
• In the case where the volume of the butane to be blended for
a given RVP is desired:
• A(VPBI)a + B(BPBI)b + ⋅ ⋅ ⋅ + W(VPBI)w = (Y + W)(VPBI)m
502
Blending component values for gasoline blending
503
Octane Blending
• Octane numbers are blended on a volumetric basis using the
blending octane numbers of the components.
• True octane numbers do not blend linearly and it is necessary
to use blending octane numbers in making calculations.
504
Octane Blending
• Blending octane numbers are based upon experience and are
those numbers which, when added on a volumetric average
basis, will give the true octane of the blend.
• True octane is defined as the octane number obtained using a
CFR test engine.
505
Octane Blending
• The formula used for calculations is:
506
Blending For Other Properties
• There are several methods of estimating the physical
properties of a blend from the properties of the blending
stocks.
• One of the most convenient methods of estimating properties
that do not blend linearly is to substitute for the value of the
inspection to be blended another value which has the
property of blending approximately linear.
• Such values are called blending factors or blending index
numbers.
507
Blending For Other Properties
• The Chevron Research Company has compiled factors or index
numbers for vapor pressures, viscosities, flash points, and
aniline points.
• The table in the next slide is for the blending values of octane
improvers.
• Since it is more complicated than the others, viscosity
blending is more fully discussed in the next few slides.
508
Blending values of Octane improvers
509
Blending For Other Properties
• Viscosity is not an additive property.
• And it is necessary to use special techniques to estimate the
viscosity of a mixture from the viscosities of its components.
• The method most commonly accepted is the use of special
charts developed by and obtainable from ASTM.
• Blending of viscosities may be calculated conveniently by
using viscosity factors.
510
Blending For Other Properties
• It is usually true to a satisfactory approximation that the
viscosity factor (VF) of the blend can be easily calculated by a
simple equation.
• Which is the sum of all the products of the volume fraction
times the viscosity factor for each component.
In equation form:
511
Cost Estimation
512
Cost Estimation
All capital cost estimates of industrial process plants can be
classified as one of four types:
1. Rule-of-thumb estimates.
2. Cost-curve estimates.
3. Major equipment factor estimates.
4. Definitive estimates.
The capital cost data presented in this work are of the second
type—cost-curve estimates.
513
1- Rule Of- Thumb Estimates
• The rule-of-thumb estimates are, in most cases, only an
approximation of the order of magnitude of cost.
• These estimates are simply a fixed cost per unit of feed or
product.
• These rule-of-thumb factors are useful for quick ballpark
costs.
• Many assumptions are implicit in these values and the
average deviation from actual practice can often be more
than 50%.
514
1- Rule Of- Thumb Estimates
Some examples are:
• Complete coal-fired electric power plant: $2,500/kW.
• Complete synthetic ammonia plant: $200,000/TPD.
• Complete petroleum refinery: $25,000/BPD.
515
2- Cost- Curve Estimates
• The cost-curve method of estimating corrects for the major
deficiency in the previous method.
• By reflecting the significant effect of size or capacity on cost.
•
These curves indicate that costs of similar process units or
plants are related to capacity by an equation of the following
form:
516
2- Cost- Curve Estimates
• This relationship was reported by Lang, who suggested an
average value of 0.6 for the exponent (X).
• It is important to note that most of the cost plots have an
exponent which differs somewhat from the 0.6 value.
• Some of the plots actually show a curvature in the log–log
slope which indicates that the cost exponent for these process
units varies with capacity.
517
Major Equipment Factor Estimates
• Major equipment factor estimates are made by applying
multipliers to the costs of all major equipment required for
the plant or process facility.
• Different factors are applicable to different types of
equipment, such as pumps, heat exchangers, pressure vessels,
etc.
• Equipment size also has an effect on the factors.
• It is obvious that prices of major equipment must first be
developed to use this method.
518
3- Major Equipment Factor Estimates
• This requires that heat and material balances be completed in
order to develop the size and basic specifications for the
major equipment.
• This method of estimating, if carefully followed, can predict
actual costs within 10 to 20%.
• A shortcut modification of this method uses a single factor for
all equipment. A commonly used factor for petroleum refining
facilities is 4.5.
519
4- Definitive estimates
• Definitive cost estimates are the most time-consuming and
difficult to prepare but are also the most accurate.
• These estimates require preparation of plot plans, detailed
flow sheets and preliminary construction drawings.
• Scale models are sometimes used. All material and equipment
are listed and priced.
520
4- Definitive estimates
• The number of man-hours for each construction activity is
estimated.
• Indirect field costs, such as crane rentals, costs of tools,
supervision, etc., are also estimated.
• This type of estimate usually results in an accuracy of +/-5%.
521
Summary Form For Cost Estimates
522
Summary Form For Cost Estimates
The items to be considered when estimating investment from
cost-curves are:
•
•
•
•
•
•
Process units
Storage facilities
Steam systems
Cooling water systems
Subtotal A
Offsites
•
•
•
•
•
•
•
Subtotal B
Special costs
Subtotal C
Location factor
Subtotal D
Contingency
Total
523
1- Storage Facilities
• Storage facilities represent a significant item of investment
costs in most refineries.
• Storage capacity for crude oil and products varies widely at
different refineries.
• The following must be considered: the number and type of
products, method of marketing, source of crude oil, and
location and size of refinery.
524
1- Storage Facilities
• Installed costs for ‘‘tank-farms’’ vary from $60 to $80 per
barrel of storage capacity.
• This includes tanks, piping, transfer pumps, dikes, fire
protection equipment, and tank-car or truck loading facilities.
• The value is applicable to low vapor pressure products such
as gasoline and heavier liquids.
525
1- Storage Facilities
• Installed costs for butane storage ranges from $90 to $120 per
barrel, depending on size.
• Costs for propane storage range from $100 to $130 per barrel.
526
2- Land And Storage Requirements
• Each refinery has its own land and storage requirements.
• Depending on location with respect to markets and crude
supply, methods of transportation of the crude and products,
and number and size of processing units.
• Availability of storage tanks for short-term leasing is also a
factor as the maximum amount of storage required is usually
based on shutdown of processing units for turnaround at 18to 24-month intervals rather than on day-to-day processing
requirements.
527
2- Land And Storage Requirements
• As the land area required for storage tanks is a major portion
of refinery land requirements.
• Three types of tankage are required: crude, intermediate, and
product.
• For a typical refinery which receives the majority of its crude
by pipeline and distributes its products in the same manner,
about 13 days of crude storage and 25 days of product storage
should be provided.
528
2- Land And Storage Requirements
• The 25 days of product storage is based on a three-week
shutdown of a major process unit.
• This generally occurs only every 18 months or two years, but
sufficient storage is necessary to provide products to
customers over this extended period.
•
A rule-of-thumb figure for total tankage, including
intermediate storage, is approximately 50 barrels of storage
per BPD crude oil processed.
529
3- Steam Systems
• An investment cost of $150.00 per lb/hr of total steam
generation capacity issued for preliminary estimates.
• This represents the total installed costs for gas-or oil-fired,
forced draft boilers, operating at 250 to 300 psig.
• And all appurtenant items such as water treating, deaerating,
feed pumps, yard piping for steam, and condensate.
530
3- Steam Systems
• Total fuel requirements for steam generation can be assumed
to be 1200Btu (LHV) per pound of steam.
• A contingency of 25% should be applied to preliminary
estimates of steam requirements.
• Water makeup to the boilers is usually 5 to 10% of the steam
produced.
531
4- Cooling Water Systems
• An investment cost of $150.00 per gpm of total water
circulation is recommended for preliminary estimates.
• This represents the total installed costs for a conventional
induced-draft cooling tower, water pumps, water treating
equipment, and water piping.
• Special costs for water supply and blow down disposal are not
included.
532
4- Cooling Water Systems
• The daily power requirements (kWh/day) for cooling water
pumps and fans is estimated by multiplying the circulation
rate in gpm by 0.6.
• This power requirement is usually a significant item in total
plant power load and should not be ignored.
• The cooling tower makeup water is about 5% of the
circulation.
533
4- Cooling Water Systems
• This is also a significant item and should not be overlooked.
• An ‘‘omission factor,’’ or contingency of 15%, should be
applied to the cooling water circulation requirements.
534
5- Other Utility Systems
• Other utility systems required in a refinery are electric power
distribution, instrument air, drinking water, fire water, sewers,
waste collection, and others.
• Since these are difficult to estimate without detailed
drawings, the cost is normally included in the offsite facilities.
535
Offsites
• Offsites are the facilities required in a refinery which are not
included in the costs of major facilities.
A typical list of offsites is:
• Electric power distribution.
• Fuel oil and fuel gas facilities.
• Water supply, and treatment.
• Air systems.
• Fire protection systems.
• Flare, drain and waste systems.
• Plant communication systems.
•
•
•
•
•
Roads and walks Railroads.
Fence.
Buildings.
Vehicles.
Product and additives.
Blending facilities.
• Product loading facilities.
536
Offsites
• Obviously, the offsite requirements vary widely between
different refineries.
• Offsite costs for the addition of individual process units in an
existing refinery can be assumed to be about 20 to 25% of the
process unit costs.
537
Offsites
538
6- Special Costs
• Special costs include the following: land, spare parts,
inspection, project management, chemicals, miscellaneous
supplies, and office and laboratory furniture.
• For preliminary estimates these costs can be estimated as 4%
of the cost of the process units, storage, steam systems,
cooling water systems, and offsites.
• Engineering costs and contractor fees are included in the
various individual cost items.
539
7- Contingencies
• Most professional cost estimators recommend that a
contingency of at least 15% be applied to the final total cost
determined by cost-curve estimates of the type presented.
• The term contingencies covers many loopholes in cost
estimates of process plants.
• The major loopholes include cost data inaccuracies when
applied to specific cases and lack of complete definition of
facilities required.
540
Escalation
541
Escalation
• All cost data presented in this book are based on U.S. Gulf
Coast construction averages for the year 1999.
• Therefore, in any attempt to use the data for current
estimates some form of escalation or inflation factor must be
applied.
• Escalation or inflation of refinery investment costs is
influenced by items which tend to increase costs as well as by
items which tend to decrease costs.
542
Escalation
Items which increase costs include major factors:
1. Increased cost of steel, concrete, and other basic materials.
2. Increased cost of construction labor and engineering.
3. Increased costs for higher safety standards and pollution
control regulations.
4. Increase in the number of reports and amount of superfluous
data necessary to obtain construction permits .
543
Escalation
Items which tend to decrease costs are basically all related to
technological improvements
• 1. Process improvements developed by the engineers in
research, design, and operation.
• 2. More efficient use of engineering and construction
manpower.
544
Plant Location
545
Plant location
• Plant location has a significant influence on plant costs.
• The main factors contributing to these variations are climate
and its effect on design requirements and construction
conditions; local rules, regulations, codes, taxes, etc; and
availability and productivity of construction labor.
546
Thank you
547