Mordern Petroleum Refining Operations.ppt

Introduction- What is petroleum ? 1
What is petroleum ?
• Petroleum is a thick, flammable, yellow-to-
black 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 ? 2
• 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.
What is petroleum ?

Introduction- Importance of petroleu
m
3
• 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.
Importance of Petroleum

Introduction- Production of petroleu
m- Generation, Migration, Accumelati
4
Steps of production in nature

m- Generation, Migration, Accumulat
5
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.
Generation

6
• In absence of oxygen conditions deposits are
changed to kerogen.
• At high temperature (greater than 110o
C) and
pressure kerogen is thermally degraded to oil and
gas.
• This process takes hundreds millions of years to
occur.
Generation

7
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).
Generation

8
• 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.
Migration

9
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.
Migration

10
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.
Migration

11
Migration
Introduction- Production of petroleum-
Generation, Migration, Accumulation

12
Migration
Generation, Migration, Accumulation

13
• 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.
Accumulation

14
• 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.
Accumulation

15
Accumulation

16
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)
Summary of Crude generation & migration

17
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.
Summary of crude generation & migration
Generation, Migration, Accumelation

18
Summary

Introduction- History 19
• 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.
History

Introduction- History 20
• 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.
History

Discussion- Characterization of crude
oil
21
• 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.
Characterization of crude oil

oil- Bulk properties
22
• 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.
1- Bulk properties

23
Important Bulk properties

24
• 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 15.6o
C.
• It should be noted that the API gravity decreases with
increase in specific gravity.
1- Specific gravity
Discussion- Characterization of crude oil-
Bulk properties

25
Specific gravity
Bulk properties

26
Specific gravity
Bulk properties

27
• 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 100o
F and 210o
F 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.
2- Viscosity

28
• 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.
3- Viscosity index

29
• 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.
4- Sulfur content

30
• 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.
5- Pour point & Dew point
Discussion- Characterization of crude oil- Bulk properties

31
• 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.
6- Bubble point & Flash point

32
• 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.
7- Fire point & Freeze point

33
• 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.
8- Smoke point & Cloud point
Bulk properties

34
• 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.
9- Aniline point & TBP curve

35
• 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.
10- C residue 7 Heating value
Bulk properties

36
Bulk properties
Properties of crude from different locations

37
• 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.
2- Fractional properties

oil- Fractional properties
38
Important fractional properties

39
• 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.
1- Octane number
Fractional properties

40
• 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% n-
heptane mixture.
Octane number

41
• 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.
Octane number

42
• 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.
Octane number

43
• 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.
Octane number

44
• 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.
2- Cetane number

45
• 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.
Cetane number

Discussion- Composition of crude oil 46
Composition 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.
Ultimate analysis of crude oil

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.
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.

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.

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- main products of the refin
ery
52
Main products of a refinery

ery
53
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

ery
54
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)

ery
55
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- The Refinery 56
The Refinery

Discussion- The Refinery- Overveiw 57
• 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.
Overview

Discussion- The Refinery- Overview 58
• 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.
Overview

Discussion- The Refinery- Overview 59
Overview

Discussion- The Refinery- Main refin
ery processes
60
• 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.
Different refinery processes

ery processes
61
• 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.

ery processes
62
• 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 units
of the refinery
63
Main units of the refinery

of the refinery
64
1. Crude distillation unit (CDU)
2. Vacuum distillation unit (VDU)
3. Thermal cracker
4. Hydrotreaters
5. Fluidized catalytic cracker
6. Separators
7. Naphtha splitter
8. Reformer
9. Alkylation and isomerisation
10. Gas treating
11. Blending pools
12. Stream splitters
Main Units of the refinery

65
Main Units of the refinery
of the refinery

Discussion- The Refinery- Distillation 66
1- Distillation, atmospheric & vacuum

Discussion- The Refinery- Overveiw
of Distillation
67
• 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.
Overview of distillation

Discussion- The Refinery- Overveiw
of Distillation
68
• 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- Overview
of Distillation
69
• 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 380-420o
C.
• Several unit operations that follow the “main” distillation step
also use smaller distillation columns to separate their products
into several streams.

Discussion- The Refinery- Atmospher
ic Distillation
70
Atmospheric distillation

ic Distillation
71
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.

ic Distillation
72

ic Distillation- The tower
73
• 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.
The atmospheric tower

74
Packing and Trays

75
• 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.

76
• 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.

77
• After leaving the atmospheric tower the products are
transferred to storage tanks of fed to other equipment to
undergo further processing.

ic Distillation- The tower- Design & P
79
• 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.
Design and principle

80
• 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.

81
• The feed can be liquid, vapor or a liquid-
vapor 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.

82
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.

83
• 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.

84
• 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.

85
• 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.

86
• 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.

87
• 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.

88
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.

89
• 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).

90
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.

91
• 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.

92
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.

93

94
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.

95
• 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.

96
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.
Side operations
Discussion- The Refinery-
Atmospheric Distillation-
The tower- Side ops.

ic Distillation- The tower- Side ops.
97
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.
Side operations

ic Distillation- The tower- Side ops.
98
• 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.
Side operations

99
Products of Atmospheric distillation

100

101
Each of these products goes to a different unit to undergo further processing to
give the final product. Examples are

102
Atmospheric column schematic
Preheating,
desalting, tower,
side strippers,
pump arounds,
cooler, reboiler,
and products.

104
• 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 380-420o
C.
• 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.
Overview

105
• 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.
Overview

106
• 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.
Overview

107
• 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.
Types of vacuum distillation

108

109

110
• 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.

111
• 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 noncondensables and the steam injected
in the process.
Definitions

112
• 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.
Definitions

113
• The atmospheric residue is sent directly to the vacuum tower,
it is sometimes stored at 150o
C 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 380-415o
C and fed to the
distillation column. It should be noted that flashing occurs in
the transfer line.
The vacuum tower

114
• 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.
The vacuum tower

115
• 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.
The vacuum tower

117
• 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.
Description of the column

118
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.
Preparing the feed for catalytic units

119
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.

120
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.

121
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.

122
• 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.
Vacuum distillation design to give lube oils

123
• 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.
Vacuum distillation design to produce bitumen

124
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.
Choosing the type of vacuum distillation

126
• 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.
Packing and distributors

127
• 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.
Packing and distributors

128
• 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.
Vacuum pumps and ejector- condensers

129

130

131
• 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.

132
• 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.

133

134
Types of vacuum pumps

135

136
The whole tower with the vacuum system

137
Products of the vacuum distillation unit

138
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.

139
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.
Vacuum distillation summary

140
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.
Vacuum distillation summary

142
• 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.
Overview

143
• 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.
Overview

145
• 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.
Thermal cracking

146
• The operating temperature is about 450-500o
C.
• And the operating pressure is 2-3 bar.
Thermal cracking

147
• Products (Residue) from the atmospheric and vacuum column
are used.
• The feed is preheated in a furnace to about 1000o
F.
• 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.
The process

148
• 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.
The process

149
• 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.
The process

152
• 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.
Coking

153
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
Coking

154
• 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.
Delayed coking

155
• 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.
Delayed coking

157
• 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.
Delayed coking

158
• 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.
The process

159
• 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.
The process

160
• 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).
The process

162
• 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.
Coke removal

163
• 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.
Coke removal

164
• 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.
Coke removal

165
• 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.
Coke removal

166
• 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.
Coke removal

167
• 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.
Coke removal

169
• 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.
Operation

170
• The table shows time schedules for the different stages of
operation of the unit.
Operation

171
• 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%.
Operation

174
• 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 370o
C 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 510-540o
C.
Flexicoking

175
• 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.
Flexicoking

176
• 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.
Flexicoking

177
• 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 600o
C.
• The coke heater is also a fluidized bed with the primary
function of transferring heat from the gasifier to the reactor.
Flexicoking

179
• 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.
Flexicoking

181
• 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.
Flexicoking

182
• The system can be designed and operated to gasify about 60-
97% 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.
Flexicoking

183
• 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.
Flexicoking

185
• 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.
Fluid coking

186
• 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.
Fluid coking

187
• 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.
Fluid coking

188
• 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.
Yields from Flexicoking and Fluid coking

190
• 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.
Visbreaking

191
• 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.
Visbreaking

192
• 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.
Visbreaking

193
• 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 15-35o
F 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.
Visbreaking

194
• 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 538o
C are highly complex and
are classified as oils, resins, and asphaltenes according to
solubility in light paraffinic hydrocarbons.
Visbreaking

195
• The oil fraction is soluble in propane.
• The resin fraction is soluble in either pentane, hexane, n-
heptane, or octane. Depending on the investigator.
• The solvent selected has an effect on the amounts and
properties of the fractions obtained.
Visbreaking

196
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.
Visbreaking

197
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.
Visbreaking

198
• 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.
Visbreaking

199
• 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.
Visbreaking

200
• Coil cracking uses higher furnace outlet temperatures 473-
500o
C and reaction times from 1 to 3 minutes.
• While soaker cracking use lowers the furnace outlet
temperatures (427-443o
C) 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.
Visbreaking

202
• 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.
Visbreaking

207
• 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 475-500o
C.
• Then the feed is quenched with gas oil or tower bottoms.
• This is to stop the cracking reaction.
Process

208
• In soaker cracking operation the feed leaves the furnace at
425-440o
C.
• 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.
Process

209
• In furnace cracking, fuel consumption accounts for nearly 80%
of the operating cost.
• Fuel requirement for soaker visbreaking is about 30-35%
lower.
Process

210
• 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.
products

214
• 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.
Overview

215
• 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.
Overview

216
• 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.
Overview

217
• 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.
The process

218
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.
The process

220
• 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.
The process

221
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.

223
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.

225
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
620-845o
C, most of which is transferred to the feed in the
riser.
• The regenerated catalyst contains 0.01-0.4 weight % coke.

226
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.

227
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.

228
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.

231
FCC
• The products formed in catalytic cracking are the result of
primary and secondary reactions.
• The primary reactions are these having the initial carbon-
carbon bond breaking and the immediate neutralization of
the carbonium ion.

232
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.
FCC

233
• 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.
FCC

234
• 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.
New designs for fluidized bed catalytic cracking units

235
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.
Cracking catalyst

236
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.
Cracking catalyst

237
• Lower coke yield.
• Increased isobutane production.
• Ability to go to higher conversions per pass without
overcracking.
Cracking catalyst

238
• 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.
Cracking catalyst

239
• 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.
Cracking catalyst

240
• 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.
Cracking catalyst

241
• 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.
Cracking catalyst

243
• 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.
Overview

244
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.
Overview

245
• 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.
Overview

246
• 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.
Overview

247
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.
Overview

248
• 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.
The reactions

250
• 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.
The reactions

251
• 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.
The reactions

252
• Hydrocracking is usually carried out at temperatures between
290 and 400o
C 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.
The process

253
• 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.
The process

254
• 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.
The process

255
• 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
350-420o
C and 6900-13800kPa.
The process

257
• 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.
The process

259
• 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.
The process

260
• 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.
The process

262
• 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.
The process

263
• 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.
The process

265
• 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.
The process

267
• 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.
The process

268
• 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.
The hydrocracking catalyst

269
• 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.

270
• 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.

271
• 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.

272
Hydroprocessing and Resid processing

273
• The term resid means the bottom of the barrel.
• It is usually the atmospheric tower bottoms with an initial
boiling point (IBP) of 343o
C or vacuum tower bottoms with an
IBP of 566o
C.
• In both cases the stream will have higher concentrations of
sulfur, nitrogen, and metals.

274
• 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.

275
• 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.

276
• 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.

277

278
• 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.

279
• 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.
Processing options

280
• 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.
Processing options

282
• 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.
Hydroprocessing

283
• 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.
Hydroprocessing

284
• 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.
Hydroprocessing

286
• 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.
Fixed bed reactors

288
• 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.
Fixed bed reactors

289
• 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.
Fixed bed reactors

290
• 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.
Fixed bed reactors

291
• 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.
The process

292
• 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.
The process

293
• 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+o
C material
to lower boiling point compounds.
The process

295
• 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.
The process

296
Expanded Bed Hydrocracking

297
• 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.

298
Expanded Bed Hydrocracking Hi-oil

299
Expanded Bed Hydrocracking LC-fining

300
Expanded Bed Hydrocracking LC-fining

301
• 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.

302
• 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.

303
• 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 800-850o
F.

304

305
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.

306
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
• The product yields and quality will also be constant.

307
• 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.

308
• 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.

309
Products from LC- fining cracking

310
Moving Bed Hydroprocessors

311
• 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.

312
• This allows low activity high metal catalyst to be removed
from the reactor and replaced with fresh catalyst while on-
line.
• 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.

313
• 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.

314

316
• 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.
Solvent extraction

317
• 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.
Solvent extraction

318
• 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.
Solvent extraction

319
• 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.
Solvent extraction

320
• 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.
Solvent extraction

321
• 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.
Solvent extraction

322
• 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.
Solvent extraction

323
• 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.
Solvent extraction

325
Summary of resid treatment

326
• 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.

327
• 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.

328
• 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.

329
• 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.

330
Catalytic reforming and Isomerization

331
• 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.

332
• 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.

333
• 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 (82-190o
C) and heavy
hydrocracker naphthas.

334
• 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.

335
• 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.

336
• The light straight run gasoline (C5 82o
C) 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 (204o
C) are easily
hydrocracked and cause excessive carbon deposit on catalyst.

338
• 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.
Reactions

339
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.
Reactions

340
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
Reactions

341
• As the catalyst ages, it is necessary to change the process
• This is to maintain the reaction severity.
• And so suppress the undesired side reactions which give the
undesired products.
Reactions

342
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.
Reactions

344
• 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.
Dehydrogenation Reactions

345
The major dehydrogenation reactions are:
1- Dehydrogenation of alkylcyclohexanes to aromatics.

346
2- Dehydroisomerization of alkylcyclopentanes to aromatics.

347
3- Dehydrocyclization of paraffins to aromatics.

348
• 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.

349
• 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.

350
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’’)

352
• 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.
Isomerization reactions

353
Isomerization reactions include:
1- Isomerization of normal paraffins to isoparaffins.

354
Isomerization reactions include:
2- Isomerization of alkylcyclopentanes to cyclohexanes and
subsequent conversion to benzene.

355
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.

357
• 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.
Hydrocracking Reactions

358
• The major hydrocracking reactions involve cracking and
saturation of paraffins.

359
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.

360
• 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.
Feed preparation

361
• 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.
Feed preparation

362
• 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.
Feed preparation

363
Catalytic reforming process

364
• 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.

365
• 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.

366
• 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.

367
• 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.

368
• 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.

369
• The reforming semiregenerative process is typically a fixed
bed reactor.
• The pretreated feed and recycle hydrogen are heated to 500-
520o
C 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.
The process

371
Semi regenerative reforming

372
• 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.
The process

373
Semi regenerative reforming

374
• Several heaters can be used or one heater with several
separate coils.
• The table shows the gas composition leaving each reactor.
The process

375
• 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.
The process

376
• 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.
Operating conditions

377
• 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.
The process

378
• 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.
The process

380
• 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.
Reforming Catalyst

381
• 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.
Reforming Catalyst

382
• 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.
Reforming Catalyst

383
• 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.
Reforming Catalyst

384
• 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.
Reforming Catalyst

386
• 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.
Reactor Design

387
• 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.
Reactor Design

388
• 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.
Reactor Design

390
• 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.
Reactor Design

391
• 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.
Reactor Design

393
• The octane number of the LSR naphtha (C5 82o
C) 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.
Isomerization

394
• 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).
Isomerization

395
• Reaction temperatures of about 95-205o
C 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.
Isomerization

396
• 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.
Isomerization

397
• 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 83o
C higher activity than conventional zeolite
isomerization catalyst and can be regenerated.
Isomerization

398
• 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.
Isomerization

399
• 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.
Isomerization

400
• 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.
Isomerization

401
• 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.
Isomerization

403
• 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.
Isomerization

404
• 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.
Isomerization

406
Isomerization operating conditions

407
Alkylation and Polymerization

408
• 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.

409
• 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.

410
• 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.

412
• 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.
Alkylation Reactions

413
• 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.

414
• 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.

415
• 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.

416
• 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.

417
For both processes the more important variables are:
• Reaction temperature.
• Acid strength.
• Isobutane concentration.
• Oleﬁn space velocity.

418
• The main reactions which occur in alkylation are the
combination of oleﬁns with iso parafﬁns.
Isobutane Isobutylene 2, 2, 4-trimethylpentane
(Isooctane)

419
• 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).

420
• 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.

421
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.
Process Variables

422
• 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.
Process Variables

424
• 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.
Alkylation Feedstocks

425
• 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.

426
• 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.

428
• 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.
Alkylation Products

429
The product streams leaving an alkylation unit are:
• LPG grade propane liquid.
• 2.Normal butane liquid.
• C5+alkylate.
• Tar.
Alkylation Products

431
• 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.
Catalysts

432
• 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.
Catalysts

433
• 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.
Catalysts

434
• 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.
Catalysts

435
• 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
Catalysts

436
• 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.
Catalysts

437
Yields and Isobutane Requirements

438
• 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
Yields and Isobutane Requirements

440
Hydrofluoric Acid Processes

441
• 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.

442

443
• 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.

444
• 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.

445
• 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.

446
• 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.

447
• 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.

448
• 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.

449

450
• 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.

451

452
• 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.

453
• 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.

454
Hydrofluoric Acid Processes Yields

456
Sulfuric Acid Alkylation Process

457
• 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.

458
• 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.

459
• 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.

460
• 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.

461
• 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.

462
• 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.

463
Autorefrigeration sulfuric acid alkylation unit

464
• 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.

466
• 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.

467
• 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.

468
• A separate distillation column can be used to separate the n-
butane 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.

469
Sulfuric Acid Alkylation Process yields and qualities

471
• Propene and butenes can be polymerized to form a high-
octane 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.
Polymerization

472
• 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.
Polymerization

473
• 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.
Polymerization

474
• while iC4H8 reacts to give primarily diisobutylene, propene
gives mostly trimers and dimers with only about 10%
conversion to dimer.
Polymerization Reactions

475
• 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.

476
• 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).

477
• 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.
The process

478
• 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.
The process

479
• 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.
The process

480
• 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
The process

483
• 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.
The process

484
• 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.
The process

485
The Insitut Francais du Petrole Unit

487
• 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.
Product Blending

488
• 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.
Product Blending

489
• 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.
Product Blending

490
• 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.
Product Blending

491
• 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.
Product Blending

492
• 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.
Product Blending

493
• 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.
Product Blending

495
• The desired RVP of a gasoline is obtained by blending n-
butane with C5 193°C naphtha.
• The amount of n-butane required to give the needed RVP is
calculated by:
Reid Vapor Pressure

496
• 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.
Reid Vapor Pressure

497
• 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.
Reid Vapor Pressure

498
• 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
Reid Vapor Pressure

499
Blending component values for gasoline blending

500
• 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.
Octane Blending

501
• 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.
Octane Blending

502
• The formula used for calculations is:
Octane Blending

503
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.

504
• 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.

505
Blending values of Octane improvers

506
• 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.

507
• 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:

509
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.

510
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%.

511
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.

512
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:

513
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.

514
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.

515
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.

516
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.

517
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%.

518
Summary Form For Cost Estimates

519
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

520
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.

521
• 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.

522
• 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.

523
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 18-
to 24-month intervals rather than on day-to-day processing
requirements.

524
• 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.

525
• 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.

526
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.

527
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.

528
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.

529
• 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.

530
• 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.

531
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.

532
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.

533
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.

535
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.

536
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.

538
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.

539
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 .

540
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.

542
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.

Mordern Petroleum Refining Operations.ppt

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