Refinery All Lectures PDF

Petroleum Refinery Lab.
Distillation Methods:
Three distillation methods are used to obtain laboratory data on crude oil:
1. True Boiling Point Distillation (TBP)
2. ASTM Distillation (ASTM)
3. Equilibrium Flash Vaporization (EFV)
The degree of separation of the fractions obtained in these methods decreases as
one moves down the list from TBP through ASTM to EFV.
Standard Test Method for

ASTM Distillation at Atmospheric Pressure D 86-04
Objective: to separate a sample of crude into different cuts by ASTM distillation at
atmospheric pressure.
Introduction:
This test method covers the atmospheric distillation of petroleum products using
a laboratory batch distillation unit to determine quantitatively the boiling range
characteristics of such products as natural gasoline, aviation gasoline and similar
products, using manual or automated equipment.
The distillation tests give an indication of types and the quality of the products
that can be obtained from petroleum, and also to compare different petroleum
types. The basic method of distillation (ASTM D-86) is one of the oldest methods
in use because the distillation characteristics of hydrocarbons have an important
effect on safety and performance, especially in the case of fuels and solvents. The
boiling range gives information on the composition, the properties, and the
behavior of petroleum and its products during storage and use. Volatility is the
major determinant of the tendency of a hydrocarbon mixture to produce
potentially explosive vapors.
The distillation characteristics are critically important for both automotive and
aviation gasoline, affecting starting, warm-up, and tendency to vapor lock at high
operating temperature or at high altitude, or both. The presence of high boiling
point components in these and other fuels can significantly affect the degree of
formation of solid combustion deposits.
Petrochemical Dept. Page 1

The test is carried out at atmospheric pressure and is stopped at 300°C (572°F) to
avoid thermal decomposition. The distillate and the residuum can be further
examined by tests such as specific gravity, sulfur content and viscosity.
Test results are commonly expressed as percent recovered versus corresponding
temperature, either in a table or graphically, as a plot of the distillation curve.
TBP/ASTM distillation curves: are the most important characterization properties
of the crude oil and petroleum products. Both TBP, ASTM distillation curves are
measured at 1 atm pressure. In both these cases, the boiling points of various
volume fractions are being measured.
The basic difference between TBP curve and ASTM distillation curve is that while
TBP curve is measured using batch distillation apparatus consisting of no less than
100 trays and very high reflux ratio, the ASTM distillation is measured in a single
stage apparatus without any reflux, it operates without the presence of a contact
plate and a reflux ratio of zero. Therefore, the ASTM does not indicate a good
separation of various components.
Apparatus
1. Distillation Flask - flask with a side

arm shall be of a size that is at least
50 % larger than the volume of the
charge.
2. Capacitor pass through cooling bath
3. Magnetic stirring bar. Boiling chips
can be used as an alternative.
4. An electric heating mantle covering
the lower half of the flask.
5. Thermometer
6. Graduated cylinder to receive the
distillate
7. A sample of crude oil

Procedure:
1. Place (100) ml of the sample in the distillation flask.

2. Place few pieces of crushed glass on the bottom of the flask to control
boiling process.
3. Gradually raise the temperature, observe rising vapors and then record the
amount of distillate at the corresponding temperatures.
4. Determine the proportion of distillates and specific gravity and API Gravity
versus boiling points.
5. When you reach the boiling point to 350 oC, stop distillation process and
transfer residue to another device where complemented by fractional
distillation under reduced pressure less than 40 mm Hg.
6. Report the colour of each fraction.
Results:
Plot the distilled volume % vs. temperature (ASTM)
Discussion:
1. What information does the boiling range give on the composition and
properties of the crude oil?
2. How can distillation characteristics of hydrocarbons affect their safety and
performance?
3. What is the major determinant of the tendency of a hydrocarbon mixture
to produce potentially explosive vapour?
4. What are the factors affecting the accuracy of the results?

Worksheet
Experiment no.: 3
Title: ASTM Distillation
Name:
Class:
Date:
Data recording for Fractional Distillation test
Volume % Temperature, oC
0
10
20
30
40
50
60
70
80
90

Sample Calculations:
The following data are obtained from ASTM distillation test (example):
Volume percent Temperature

0
distilled C
0 (IBP) 54
5 59
10 65
20 74
30 83.5
40 94.5
50 104.5
60 114
70 125.5
80 141.5
90 173
95 178
FBP 180
Volume distilled = 96 ml
Residue left = 2 ml
1. Calculate % losses
2. Prepare ASTM Distillation Curve (Temperature vs. Volume distilled %)

Petroleum Refining / 3rd Stage
Petroleum refinery processes

Introduction
Crude oil is a complex mixture of naturally occurring hydrocarbons. The petroleum
refining industry converts crude oil into more than 2500 refined products, including
liquefied petroleum gas, gasoline, kerosene, aviation fuel, diesel fuel, fuel oil, lubricating
oil and petrochemical industry feedstock. Petroleum refining activities start with receipt
of the crude oil at the refinery, followed by multiple petroleum handling and refining
operations and terminate with storage of the refined products prior to shipment.
The petroleum refining industry employs a variety of processes to manufacture multiple
products. A refinery’s processing flow scheme is largely determined by the composition
of the crude oil feedstock and the petroleum products it chooses to manufacture.
Figure 1 illustrates a schematic for a crude oil refinery process.
Refining operations
Petroleum refining processes and operations can be separated into five basic areas:
1. Fractionation (distillation) is the separation of crude oil in atmospheric and
vacuum distillation towers into groups of hydrocarbon compounds of differing
boiling-point ranges called "fractions" or "cuts."
2. Conversion Processes change the size and/or structure of hydrocarbon
molecules. These processes include:
 Decomposition (dividing) by thermal and catalytic cracking;
 Unification (combining) through alkylation and polymerization; and
 Alteration (rearranging) with isomerization and catalytic reforming
3. Treatment Processes to prepare hydrocarbon streams for additional processing
and to prepare finished products. Treatment may include removal or separation
of aromatics and naphthenes, impurities and undesirable contaminants.
Treatment may involve chemical or physical separation e.g. dissolving,
absorption, or precipitation using a variety and combination of processes
including desalting, drying, hydrodesulfurizing, solvent refining, sweetening,
solvent extraction, and solvent dewaxing.
4. Formulating and Blending is the process of mixing and combining hydrocarbon
fractions, additives, and other components to produce finished products with
specific performance properties.
5. Other Refining Operations include:
 light-ends recovery;
 sour-water stripping;
 solid waste, process-water and wastewater treatment;
 cooling, storage and handling and product movement;
 hydrogen production;
 acid and tail-gas treatment;
 Sulfur recovery

Auxiliary Operations and Facilities include:

 Light, steam and power generation;
 Process and fire water systems;
 Flares and relief systems;
 Furnaces and heaters;
 Pumps and valves;
 Supply of steam, air, nitrogen, and other plant gases;
 Noise and pollution controls;
 Sampling, testing, and inspecting and laboratory;
Modern Petroleum Processing

Seven Basic Operations in Petroleum Processing
Physical and chemical processes

Figure 1: Overall Refinery flow
CRUDE OIL PRETREATMENT (DESALTING)

a. Crude oil often contains water, inorganic salts, suspended solids, and water-soluble
trace metals. As a first step in the refining process, to reduce corrosion, plugging, and
fouling of equipment and to prevent poisoning the catalysts in processing units, these
contaminants must be removed by desalting (dehydration).
b. The two most typical methods of crude-oil desalting, chemical and electrostatic
separation use hot water as the extraction agent. In chemical desalting, water and
chemical surfactant (demulsifiers) are added to the crude, heated so that salts and other
impurities dissolve into the water or attach to the water, and then held in a tank where
they settle out.
Electrical desalting is the application of high-voltage electrostatic charges to concentrate
suspended water globules in the bottom of the settling tank. Surfactants are added only
when the crude has a large amount of suspended solids. Both methods of desalting are
continuous. A third and less-common process involves filtering heated crude using
diatomaceous earth.
c. The feedstock crude oil is heated to between 150° and 350°F (65.6 to 176.7 oC) to
reduce viscosity and surface tension for easier mixing and separation of the water. The

temperature is limited by the vapor pressure of the crude-oil feedstock. In both

methods other chemicals may be added. Ammonia is often used to reduce corrosion.
Caustic or acid may be added to adjust the pH of the water wash. Wastewater and
contaminants are discharged from the bottom of the settling tank to the wastewater
treatment facility. The desalted crude is continuously drawn from the top of the settling
tanks and sent to the crude distillation (fractionating) tower.
Figure 2: Desalting of crude oil
Desalting Unit
Distillation:
Distillation is the most common separation technique and it consumes enormous
amounts of energy, both in terms of cooling and heating requirements.
Distillation can contribute to more than 50% of plant operating costs.
The various components of crude oil have different sizes, weights and boiling
temperatures; so, the first step is to separate these components.
Because they have different boiling temperatures, they can be separated easily by a
process called fractional distillation.
Fractional distillation is useful for separating a mixture of substances with narrow
differences in boiling points, and is the most important step in the refining process.
Very few of the components come out of the fractional distillation column ready for
market. Many of them must be chemically processed to make other fractions. For
example, only 40% of distilled crude oil is gasoline; however, gasoline is one of the
major products made by oil companies. Rather than continually distilling large quantities
of crude oil, oil companies chemically process some other fractions from the distillation
column to make gasoline; this processing increases the yield of gasoline from each
barrel of crude oil.
Distillation of crude oil occurs in distillation columns or towers.
Main Components of Distillation Columns:

 A vertical shell where separation of
liquid components is done.
 Column internals e.g. trays/plates
and/or packing which are used to
enhance component separations.
 A reboiler to provide the necessary
vaporization for the distillation
process.
 A condenser to cool and condense the
vapour leaving the top of the column.
 A reflux drum to hold the condensed
vapour from the top of the column so
that liquid (reflux) can be recycled back to the column.
Trays and plates:

Bubble cap trays
The tray is provided with holes, a riser or chimney is fitted over each hole, and a cap
covers the riser. The vapour rise through the chimney and directed downward by the
cap, finally discharging through slots in the cap, and bubbling through the liquid on the
tray.

Valve trays
Perforations are covered by liftable caps lifted by vapour, which creates a flow area and
directs the vapour horizontally into the liquid.
Sieve trays
Sieve trays are simply metal plates with holes in them. Vapour passes straight upward
through the liquid on the plate. The arrangement, number and size of the holes are
design parameters.
 Each tray has 2 conduits called downcomers: one on each side. Liquid falls by
gravity through the downcomers from one tray to the tray below.
 A weir ensures there is always some liquid on the tray.
 Vapour flows up and is forced to pass through the liquid on each tray.

Packing
Packings are passive devices designed to increase the interfacial area for vapour-liquid
contact.
Basic operation:
•The feed is introduced somewhere near the middle of the
column to a tray known as the feed tray.
•The feed tray divides the column into a top (enriching or
rectification) and a bottom (stripping) section.
At the rectifying section, the more volatile component is removed
through contacting the rising vapour with the down-flowing liquid. At
the stripping section, the down-flowing liquid is stripped of the more
volatile component by the rising vapour.
•The feed flows down the column where it is collected in the
re-boiler.
•Heat (usually as steam) is supplied to the re-boiler to generate
vapour.
•The vapour from the re-boiler is re‐introduced into the unit at
the bottom of the column.
•The liquid removed from the re-boiler is known as the
bottoms product or simply, bottoms.

•Vapour moves up the column, exits the top, and is cooled in a condenser. The
condensed liquid is stored in a holding vessel known as the reflux drum. Some of this
liquid is recycled back to the top of the column and this is called the reflux. The
condensed liquid that is removed from the system is known as the distillate or top
product.
•Thus, there are internal flows of vapour and liquid within the column as well as
external flows of feeds and product streams, into and out of the column.
Crude distillation
The refining process is the separation of crude oil into various fractions or straight‐run
cuts by distillation in atmospheric and vacuum towers. The main fractions or "cuts"
obtained have specific boiling‐point ranges and can be classified in order of decreasing
volatility into gases, light distillates, middle distillates, gas oils, and residuum.
Atmospheric distillation:
Crude distillation unit (CDU) is also known as topping unit, or atmospheric distillation
unit. The unit produces raw products which have to be processed in downstream unit to
produce products of certain specifications. This involves the removal of undesirable

components like sulphur, nitrogen and metal compounds, and limiting the aromatic
contents.
Atmospheric Distillation Tower:

Crude oil contains salts which can be harmful to downstream equipment and must be
removed. To remove the salts, water is mixed with the crude oil and typically heated to
temperatures between about 215 oF to about 280 oF and allowed to separate in the de-
salter.
At the refinery, the desalted crude feedstock is preheated using recovered process heat
(heat exchangers network with hot products that need to be cooled).
Then, the preheated crude enters the furnace, where it is heated to about 340-372 oC.
The partially vaporized crude is fed into the feed region just above the bottom (called
flash zone) of the atmospheric column at pressures slightly above atmospheric, where
the vapor and liquid separate. The vapor includes all the components that comprise the
products, while the liquid is the residue with a small amount of components in the range
of gas oil. These components are removed from the residue by steam stripping at the
bottom of the column.
All but the heaviest fractions flash into vapor. As the hot vapor rises in the tower, its
temperature is reduced. Heavy fuel oil or asphalt residue is taken from the bottom. At
successively higher points on the tower, the various major products including naphtha,
gasoline, kerosene, and uncondensed gases (which condense at lower temperatures)
are drawn off from the side of the column and side strippers are used to help controlling
the composition of light components.
The fractionating tower is a steel cylinder typically 50 m (164 ft) high and is equipped
with about 30–50 horizontal steel trays for separating and collecting the liquids. At each
tray, vapors from below enter perforations and bubble caps. The vapors bubble through
the liquid on the tray, causing some condensation at the temperature of that tray. An
overflow pipe drains the condensed liquids from each tray back to the tray below
(through down comer), where the higher temperature causes re-evaporation. The
evaporation and condensing operation is repeated many times until the desired degree
of product purity is reached. Then side streams from certain trays are taken off to
obtain the desired fractions. Products ranging from uncondensed gases at the top to
heavy fuel oils at the bottom can be taken continuously from the tower. Steam is often
used in towers. The distillation process separates the major constituents of crude oil
into so-called straight-run products. Crude oil is "topped" by distilling off only the lighter
fractions; the heavy residue is often distilled further under high vacuum.

Atmospheric Distillation Unit
Streams taken directly from the distillation tower contain low boiling point components
and therefore they are pumped to the Stripping Tower to separate the light components
by distillation using steam, the stripped light components return to the distillation
tower as a reflux in a point above the point from which they were withdrawn.
The stripping tower is small and consists of a few trays (4-10); the steam enters at a
point below the bottom tray.
The objectives of stripping are:
1. To increase separation efficiency
2. To control the true boiling range
3. To obtain reflux inside the tower
Atmospheric Tower Products:

Typical products from the atmospheric distillation unit are:

1. Gases
2. Light straight run naphtha (also called
light gasoline or light naphtha)
3. Heavy gasoline (also called military jet
fuel)
4. Kerosene (also called light distillate or
jet fuel)
5. Middle distillates called diesel or light
gas oil (LGO)
6. Heavy distillates called atmospheric
gas oil (AGO) or heavy gas oil (HGO)
7. Crude column bottoms called
atmospheric residue or reduced crude
(RC) or long residue.
Vacuum Distillation:

To further distill the residuum or topped crude from the atmospheric distillation unit
without thermal cracking, reduced pressure is required. The process takes place in a
vacuum distillation unit. The atmospheric residue, the bottom from the atmospheric
distillation unit is sent to the vacuum distillation unit. The vacuum unit distillates are
light vacuum gas oil (LVGO), medium vacuum gas oil (MVGO), heavy vacuum gas oil
(HVGO), and vacuum residue.
The vacuum unit can also be used to produce lubrication oil grade feed stocks.
The principles of vacuum distillation are similar to those of atmospheric distillation
except that larger diameter columns are used to maintain vapor velocities at the
reduced pressures. The internal designs of some vacuum towers are different from
atmospheric towers in that random packing is used for fractionation instead of trays.
The atmospheric residue is heated in several exchangers by the hot products. Final
heating to 380–415 oC (716–779oF) is done in a fired heater. The feed enters the vacuum
tower at the lower part of the column.
The bottom zone is equipped with valve trays.
Vacuum distillation units have a system to create the vacuum in the column (25 – 40
mm Hg).
Process Description
The figure below shows the flow diagram of the vacuum distillation unit. The
atmospheric residue can be sent directly to the vacuum unit after heat extraction in the
crude pre-heat exchangers train. If it is sent to storage, the temperature should not be
below 150 oC (300 oF) to control the viscosity necessary for proper flow. It is then heated
in several exchangers by the hot products and pumparounds of the vacuum unit. Final
heating to 380–415 oC (716–779 oF) is done in a fired heater. To minimize thermal
cracking and coking, steam is injected in the heater tube passes. The feed enters the
vacuum tower at the lower part of the column. The distillate is withdrawn as LVGO and
two other cuts, MVGO and HVGO.
Vacuum distillation columns are equipped with packing for fractionation and heat
exchange zones. This is in order to reduce the pressure drop in the column which is
necessary for creating a low vacuum in the lower section of the column. The bottom
zone is equipped with valve trays. The vapours from the flash zone go through a wash
and fractionation zone where the heavy ends are condensed with HVGO reflux. Further
up, the column sections (consisting of a heat exchange and fractionation zone) are
separated by sprays of liquid from the pump around or the internal reflux.
Vacuum distillation units have a system to create the vacuum that uses either ejectors
or a combination of ejectors and liquid ring pumps. Ejectors recompress the gases
through a nozzle where vapours from the column are sucked into the venturi section of
the nozzle by a stream of medium or low pressure steam. The vapour phase at the

ejector exit is partially condensed in an exchanger with cooling water. The liquid phase
is then sent to the overhead drum. The vapour phase goes from the condenser to
another ejector-condenser stage.
Liquid ring pumps are similar to rotor gas compressors. They do not use steam and can
significantly reduce hydrocarbon-rich aqueous condensates in a system using ejectors.
Systems with ejectors are much more flexible and rapid to put into operation. The
higher investments required by liquid ring pumps are offset by reduced steam
consumption and lower installation costs.

The vacuum distillation column internals must provide good vapor-liquid contacting
while, at the same time, maintaining a very low pressure increases from the column top
to the column bottom. Therefore, refinery vacuum columns often use distillation trays
only where withdrawing products from the side of the column (referred to as side
draws). The remainder of the column uses packing material for the vapor-liquid
contacting because such packing has a lower pressure drop than distillation trays. This
packing material can be either structured sheet metal or randomly dumped packing
such as Raschig rings.

Petroleum Refining /3rd stage
Conversion Processes
The objective of the conversion processes is to convert low value atmospheric and
vacuum residues to valuable products such as naphtha, gasoline and gasoil.
Cracking
Cracking is a petroleum refining process in which heavy-molecular weight
hydrocarbons are broken up into light hydrocarbon molecules by the application of
heat and pressure, with or without the use of catalysts, to derive a variety of fuel
products. Cracking is one of the principal ways in which crude oil is converted into
useful fuels such as motor gasoline, jet fuel, and home heating oil.
- Typically cracking involves the thermal or catalytic decomposition of heavier
hydrocarbon feed stocks to lighter hydrocarbon feed stocks.
- Cracking can be carried out to any hydrocarbon feedstock but it is usually
applied for vacuum gas oil (VGO)
- Cracking can be with or without a catalyst.
- When cracking is carried out without a catalyst higher operating
temperatures and pressures are required. This is called as thermal cracking.
This was the principle of the old generation refineries.
- Now a day, cracking is usually carried out using a catalyst. The catalyst
enabled the reduction in operating pressure and temperature drastically.
Thermal Cracking
Thermal cracking is a refining process in which heat (~800°C) and pressure
(~700kPa - 101.5 psi) is used to break down, rearrange, or combine hydrocarbon
molecules. The first thermal cracking process was developed around 1913.
Distillate fuels and heavy oils were heated under pressure in large drums until they
cracked into smaller molecules with better antiknock characteristics. However, this
method produced large amounts of solid, unwanted coke. There are three types of
industrial thermal cracking processes.
1. A mild cracking (as in visbreaking) in which mild heating is applied to crack
the residue just enough to lower its viscosity and also to produce some light
products.
2. The second process is delayed coking in which moderate thermal cracking
converts the residue into lighter products, leaving coke behind.
3. The third process involves severe thermal cracking: part of the coke is
burned and used to heat the feed in the cracking reactor, as in fluid coking.

Visbreaking
Visbreaking is a mild thermal cracking of vacuum or atmospheric residues to
produce light products and 75–85% cracked material of lower viscosity that can be
used as fuel oil. The process is mainly used to reduce the viscosities and pour
points of vacuum tower bottoms to meet the requirements of fuel oil. It is also used
to increase catalyst cracker feed stocks and gasoline yields. Middle distillates may
also be produced, depending on product demand. The thermally cracked residue
tar accumulates in the bottom of the fractionation tower
The possible reactions in visbreaking are:
• Cracking of the side chains attached to cycloparaffin and aromatic rings so
the chains are either removed or shortened to methyl or ethyl groups.
• Cracking of resins to light hydrocarbons (primarily olefins) and compounds
which convert to asphaltenes.
• At temperatures above 900°F (480°C), some cracking of naphthene rings.
Product Yield and Properties

Four products are produced in the visbreaking process: gases (C - 4), Naphtha C5
_ 166 oC, gas oil 166–350 oC , residue or tar +350 oC.
Types of Visbreakers:
There are two types of visbreaker operation:
1. Coil or furnace visbreaker
It uses high furnace outlet temperature [885–930°F (473–500°C)], and reaction time
from 1-3 minutes.
The feed is heated in a furnace or coil and quenched as it exits the furnace with gas
oil or tower bottoms to slop the cracking reaction (Figure 1).
After quenching, the product enters the fractionation tower where it is separated
into gas, gasoline, gas oil and visbreaker tar (residue). The gas oil is steam-stripped
to remove volatile components. The visbreaker bottoms are withdrawn from the
fractionator, heat exchanged with the visbreaker feedstock, mixed with stripped gas
oil (optional) and routed to storage.

Figure 1 Coil Visbreaker
2. Soaker Visbreaker
The process scheme described above is called furnace or coil cracking. Some
visbreakers use a soaker between the visbreaker furnace and the quenching step,
similar to the conventional thermal cracking processes. This type of operation is
termed soaker cracking as shown in the Figure 2. The soaker cracking uses lower
furnace outlet temperatures [800–830°F (427–443°C)] and longer reaction times.
In soaker visbreaking, the bulk of the cracking occurs not in the furnace but in a
drum located after the furnace called the soaker. The oil is held at a high
temperature for a pre-determined period of time to allow cracking to occur before
being quenched. The oil then passes to a fractionator.
The conversion is mainly a function of two operating parameters, temperature and
residence time. Coil cracking is a high temperature, short residence time route
whereas soaker cracking is a low temperature, long residence time route.
The product yields and properties are similar, but the soaker operation with its lower
furnace outlet temperatures has the advantages of lower energy consumption and
longer run times before having to shut down to remove coke from the furnace
tubes. Run times of 3–6 months are common for furnace visbreakers and 6–18
months for soaker visbreakers. This apparent advantage for soaker visbreakers is
at least partially balanced by the greater difficulty in cleaning the soaking drum.
Coil cracking yields are more stable. Soaker cracking usually requires less capital
investment, consumes less fuel.

Figure 2 Soaker Visbreaker
Coking:
Coking are severe cracking operations designed to completely convert residual
products such as pitch or tar into gas, naphtha, heating oil, gas oil, and coke (The
process so completely reduces hydrogen that the residue is a form of carbon called
coke). Three typical types of coke are obtained (sponge coke, honeycomb coke,
and needle coke) depending upon the reaction mechanism, time, temperature, and
the crude feedstock.
The gas oil fraction represents the major product obtained used as a feed stock for
catalytic cracking units. The C5-220 oC naphtha may be used as a gasoline
blending agent, although its octane no. quality from 65 to 80 RON (unleaded), is
lower than the desirable, the coke is usually used as fuel.
The main uses of petroleum coke are as follows:
1. Fuel
2. Manufacture of anodes for electrolytic cells.
3. As chemical carbon source for manufacture of calcium carbide and silicon
carbide
4. Manufacture of electrodes for use in electric furnaces.
5. Manufacture of graphite

Coking Types:
The major coking processes in use today are:
1. Delayed Coking:
A semi- continuous process (Figure 3) in which the heated charge is transferred to
large coking drums which provide the long residence time needed to allow the
cracking reactions to proceed to completion, the feed to these units is normally an
atmospheric residue, although cracked tars and heavy catalytic cycle oils may be
also used.
Initially the heavy feedstock is fed to a furnace which heats the residuum to high
temperatures (900°-950° F) at low pressures (25-30 psi) and is designed and
controlled to prevent premature coking in the heater tubes (Figure 3). The mixture is
passed from the heater to one or more coker drums where the hot material is held
approximately 24 hours (delayed) at pressures of 25-75 psi, until it cracks into
lighter products. Vapors from the drums are returned to a fractionator where gas,
naphtha, and gas oils are separated out. The heavier hydrocarbons produced in the
fractionator are recycled through the furnace.
After the coke reaches a predetermined level in one drum, the flow is diverted to
another drum to maintain continuous operation.
Process Description:
Hot fresh liquid feed is charged to the fractionator two to four trays above the
bottom vapor zone. This accomplishes the following:
1. The hot vapors from the coke drum are quenched by the cooler feed liquid thus
preventing any significant amount of coke formation in the fractionator and
simultaneously condensing a portion of the heavy ends which are recycled.
2. Any remaining material lighter than the desired coke drum feed is stripped
(vaporized) from the fresh liquid feed.
3. The fresh feed liquid is further preheated making the process more energy
efficient. Vapors from the top of the coke drum return to the base of the fractionator.
These vapors consist of steam and the products of the thermal cracking reaction:
gas, naphtha, and gas oils.

Figure 3: Delayed Coking
2. Continuous (Fluid) Coking:

It is a continuous (contact or fluid) coking process which uses the fluidized - solids
technique to convert residues to more valuable products. The use of a fluid bed
permits the coking reaction to be conducted at higher temperature and shorter
contact times than those in delayed coking; steam is used for fluidizing the bed.
In continuous coking, thermal cracking occurs by using heat transferred from hot,
recycled coke particles to feedstock in a radial mixer, called a reactor, at a pressure
of 50 psi. Gases and vapors are taken from the reactor, quenched to stop any
further reaction, and fractionated. The reacted coke enters a surge drum and is
lifted to a feeder and classifier where the larger coke particles are removed as
product. The remaining coke is dropped into the preheater for recycling with
feedstock. Coking occurs both in the reactor and in the surge drum. The process is
automatic in that there is a continuous flow of coke and feedstock.

The heated feed is fed to a fluidized bed where fine coke particles would aid fluidization.
After coking, lighter products are withdrawn and coke formed is removed continuously.
The fluid coker also has a scrubber which will remove heavier compounds from the vapors
and send them back with the feed stream. Here, the feed stream absorbs heavier
hydrocarbons from the vapors generated. The coke after coking reaction is cold coke.
Therefore, to generate hot coke, a burner is used to heat the coke. The off gases from the
burner are sent to the vent. The hot coke obtained is recycled back to the fluidized bed.
Distillation unit:
Feed enters distillation column and not the coker: This is to remove light ends from
the feed and don’t subject them to cracking. Light ends are valuable and we don’t
want to lose them to cheap coke product. The bottom product from the distillation
column is fed to the furnace for pre-heating and subsequent coking operation.
Live steam in distillation to remove lighter hydrocarbons in various sections.
Circulatory reflux (Pump around units): to provide good amount of liquid reflux in
various sections of the main column.
Catalytic Cracking
Catalytic cracking is the most important and widely used refinery process for
converting heavy oils into more valuable gasoline and lighter products. Originally
cracking was accomplished thermally but the catalytic process has almost
completely replaced thermal cracking because more gasoline having a higher
octane and less heavy fuel oils and light gases are produced. It also produces
byproduct gases more valuable, than those produced by thermal cracking.

The produced light gases contain more olefins than those produced by thermal
cracking.
The catalysts facilitate the conversion of the heavier molecules into lighter products.
The catalysts are solid materials (zeolite, aluminum hydro-silicate, treated betonies
clay, bauxite and silica-alumina) as powders, beads, pellets or shaped materials.
The cracking process produces carbon (coke) which remains on the catalyst
particle and rapidly lowers its activity. To maintain the catalyst activity at a useful
level, it is necessary to regenerate the catalyst by burning off this coke with air. As a
result, the catalyst is continuously moved from reactor to regenerator and back to
reactor. The cracking reaction is endothermic and the regeneration reaction
exothermic. Some units are designed to use the regeneration heat to supply that
needed for the reaction and to heat the feed up to reaction temperature.
Catalytic cracking rearranges the molecular structure of hydrocarbons to convert
heavy fractions into lighter fractions such as kerosene, gasoline, liquified petroleum
gas (LPG) and heating oil.
Use of a catalyst in the cracking reaction increases the yield of better quality
products under much less severe operating conditions than in thermal cracking.
Temperature is 455°- 510° C at much lower pressures of 10-20 psi.
There are three basic functions in the catalytic cracking process:
➢ Reaction: Feedstock reacts with catalyst and cracks into different
hydrocarbons;
➢ Regeneration: Catalyst is reactivated by burning off coke; and
➢ Fractionation: Cracked hydrocarbon stream is separated into various
products.
The catalytic cracking process is very flexible, and operating conditions can be
adjusted to meet product demand. In addition to cracking, catalytic activities include
dehydrogenation, hydrogenation, and isomerization.
The catalytic-cracking processes in use today can all be classified as either moving-
bed or fluidized-bed units.
The Thermafor catalytic cracking process (TCC) is representative of the moving-
bed units and the fluid catalytic cracker (FCC) of the fluidized-bed units. There are
very few TCC units in operation today and the FCC unit has taken over the field.
The FCC units can be classified as either bed or riser (transfer line) cracking units
depending upon where the major fraction of the cracking reaction occurs.
1. Fluid Catalytic Cracking (FCC)

Fluid catalytic cracking is the most important conversion process used in petroleum
refineries. It is used to convert the high-boiling hydrocarbon fractions to more
valuable gasoline, olefinic gases and other products. Fluid catalytic cracking or "cat
cracking," is the basic gasoline-making process. It uses high temperature (about
538 oC), low pressure and a catalyst in the form of very fine particles [average
particle size about 70 micrometers (microns)] which behave as a fluid when aerated
with a vapor.
Two basic types of FCC units in use today are the ‘‘side-by-side’’ type, where the
reactor and regenerator are separate vessels adjacent to each other, and the
Orthoflow, or stacked type, where the reactor is mounted on top of the regenerator.
The cracker consists of a catalyst section and a fractionating section. The catalyst
section contains the reactor and regenerator which, with the standpipe and riser,
form the catalyst circulation unit.
The fluidized powdered catalyst is circulated between the reactor and the
regenerator using air, oil vapors, and steam as the conveying media.
Figure 4 FCC Unit

A typical FCC process (figure 4) involves mixing a preheated hydrocarbon charge
with hot, regenerated catalyst as it enters the riser leading to the reactor. The
charge is combined with a recycle stream within the riser, vaporized, and raised to
reactor temperature (900°-1,000° F) by the hot catalyst. As the mixture travels up
the riser, the charge is cracked at 10-30 psi. In the more modern FCC units, all
cracking takes place in the riser. The "reactor" no longer functions as a reactor; it
merely serves as a holding vessel for the cyclones. This cracking continues until the
oil vapors are separated from the catalyst in the reactor cyclones. The resultant

product stream (cracked product) is then charged to a fractionating column where it

is separated into fractions, and some of the heavy oil is recycled to the riser.
Reactor
The "reactor" is a vessel in which the cracked product vapors are:
(a) separated from spent catalyst by flowing through a set of two-stage cyclones in
the reactor
(b) the spent catalyst flows downward through a stripping section to remove
hydrocarbon vapors by steam before the spent catalyst returns to the catalyst
regenerator.
The cracked product is then charged to a fractionating column where it is separated
into fractions, and some of the heavy oil is recycled to the riser.
Spent catalyst is regenerated to get rid of coke that collects on the catalyst during
the process. Spent catalyst flows through the catalyst stripper to the regenerator,
where most of the coke deposits burn off at the bottom where preheated air and
spent catalyst are mixed. The regenerated catalyst leaves from bottom and mixed
with the feed stream.
Fresh catalyst is added and worn-out catalyst removed to optimize the cracking
process.
Regenerator
The catalyst is regenerated by burning off the deposited coke with air blown into the
regenerator. The regenerator temperature is about 715°C and a pressure of about
35 psi. The combustion of the coke is exothermic, it produces a large amount of
heat, a part is used for the vaporization of the feedstock and a part for endothermic
cracking reactions. For that reason, FCC units are heat balanced.
The hot flue gas exits the regenerator after passing through multiple sets of two-
stage cylones that remove catalyst from the flue gas.
Distillation column
The reaction product vapors (at 535 °C and a pressure of 25 psi) flow from the top
of the reactor to the bottom section of the distillation column (fractionator) where
they are distilled into the FCC end products of cracked naphtha, fuel oil and off-gas.
After further processing for removal of sulfur compounds, the cracked naphtha
becomes a high-octane component of the refinery's blended gasoline.

The off-gas is sent to a gas recovery unit where it is separated into butanes and
butylenes, propane and propylene, hydrogen, methane, ethylene and ethane.
Many FCC fractionators produce light cracked naphtha (lower boiling range) and
heavy cracked naphtha.
The bottom product oil from the fractionator contains residual catalyst particles
which were not removed by the cyclones in the reactor. For that reason, part of that
bottom oil is recycled back into the main fractionators. The remaining oil is pumped
through a settler. The bottom oil contains most of catalyst particles and is recycled
back into the catalyst riser by combining it with the feedstock.
Thermofor Catalytic Cracking

In a typical Thermofor catalytic cracking unit, the preheated feedstock flows by
gravity through the catalytic reactor bed. The vapors are separated from the
catalyst and sent to a fractionating tower. The spent catalyst is regenerated, cooled,
and recycled. The flue gas from regeneration is sent to a carbon monoxide boiler
for heat recovery.

Process Variables:
In addition to the nature of the charge stock, the major operating variables affecting
the conversion process are the cracking temperature, catalyst/oil ratio, space
velocity, catalyst type and activity, and recycle ratio.
Generally increasing reaction temperature, catalyst / oil ratio, catalyst activity and
contact time results in an increase in conversion, while a decrease in space velocity
increases conversion. It should be noted that an increase in conversion does not
necessarily mean an increase in gasoline yield, as an increase in temperature
above a certain level can increase conversion, coke and gas yields, and octane
number of the gasoline but decrease gasoline yield.
Comparison between thermal and catalytic cracking

Catalytic cracking differences with Thermal Cracking
➢ Uses a catalyst
➢ Lower temperature
➢ Lower pressure
➢ More flexible
➢ Different reaction mechanisms
➢ High thermal efficiency
➢ High yields of gasoline and other distillates
➢ Low gas yields
➢ High product selectivity
➢ High octane number

Hydrocracking
Hydrocracking is a two-stage process combining catalytic cracking and
hydrogenation, wherein heavier feed stocks are cracked in the presence of
hydrogen to produce more desirable products. The process employs high pressure,
high temperature, a catalyst, and hydrogen. Hydrocracking is used for feed stocks
that are difficult to process by either catalytic cracking or reforming, since these
feed stocks are characterized usually by high polycyclic aromatic content and/or
high concentrations of the two principal catalyst poisons, sulfur and nitrogen
compounds.
The hydrocracking process largely depends on the nature of the feedstock and the
relative rates of the two competing reactions, hydrogenation and cracking. Heavy
aromatic feedstock is converted into lighter products under a wide range of very
high pressures (1,000-2,000 psi) and fairly high temperatures (750°-1,500° F), in
the presence of hydrogen and special catalysts. When the feedstock has a high
paraffinic content, the primary function of hydrogen is to prevent the formation of
polycyclic aromatic compounds. Another important role of hydrogen in the
hydrocracking process is to reduce tar formation and prevent buildup of coke on the
catalyst. Hydrogenation also serves to convert sulfur and nitrogen compounds
present in the feedstock to hydrogen sulfide and ammonia.
Hydrocracking produces relatively large amounts of isobutane for alkylation
feedstock. Hydrocracking also performs isomerization for pour-point control and
smoke-point control, both of which are important in high-quality jet fuel.
Hydrocracking Process
In the first stage, preheated feedstock is mixed with recycled hydrogen and sent to
the first-stage reactor, where catalysts convert sulfur and nitrogen compounds to
hydrogen sulfide and ammonia.
Limited hydrocracking also occurs. After the hydrocarbon leaves the first stage, it is
cooled and liquefied and run through a hydrocarbon separator. The hydrogen is
recycled to the feedstock. The liquid is charged to a fractionator. Depending on the
products desired (gasoline components, jet fuel, and gas oil), the fractionator is run
to cut out some portion of the first stage reactor outturn.
Kerosene-range material can be taken as a separate side-draw product or included
in the fractionator bottoms with the gas oil.

Two-Stage Hydrocracking Unit
Difference between FCC and HYDCRC

FCC HYDCRC
Carbon rejection Hydrogen addition
Endothermic Exothermic
Acid catalyst Metal catalyst on acid support
More gas less gas
More coke less coke but a costly process
Catalytic Reforming:
Catalytic reforming is an important process used to convert low-octane naphtha into
high-octane gasoline blending components called reformates. It uses platinum as
the catalyst.
Since the catalyst is easily poisoned by the presence of sulfur, oxygen, nitrogen,
and metallic components, it is essential to pretreat naphtha before reforming. This,
in fact, is done simultaneously in a catalytic hydrogen pretreatment reactor.

Catalytic hydrotreating (Naphtha Pretreatment):

Catalytic hydrotreating is a hydrogenation process used to remove about 90% of
contaminants such as nitrogen, sulfur, oxygen, and metals from liquid petroleum
fractions. These contaminants, if not removed from the petroleum fractions as they
travel through the refinery processing units, can have detrimental effects on the
equipment, the catalysts, and the quality of the finished product. Typically,
hydrotreating is done prior to processes such as catalytic reforming so that the
catalyst is not contaminated by untreated feedstock. Hydrotreating is also used
prior to catalytic cracking to reduce sulfur and improve product yields.
Naphtha from the naphtha distillation column is usually desulfurised in a catalytic
hydrogenation unit and is then sent to a platinum reforming unit where high octane
gasoline is produced.
The following reactions take place in the reactor:
Desulfurisation reaction: RSH + H2 = RH + H2S ↑
Deoxygenation reaction: ROH + H2 = RH + H2O ↑
Denitrogenation reaction: RNH + H2 = RH + NH3 ↑
Demetallation reaction: RM + H2 = RH + *MH
*MH indicates metals adsorbed on the surface of catalyst.
In the catalytic hydrogenation unit, the feed naphtha is premixed with hydrogen and
heated by heat exchangers and a heater to raise the temperature up to 350°C and
passed in the presence of hydrogen under a pressure of 20–25 kg/cm2 over a
catalyst packed bed reactor. The product mixture from the reactor is cooled to 50°C
and flashed in a separator vessel to separate hydrogen, and recycle it back to the
reactor. The product mixture containing hydrocarbon gases (C1–C4), hydrogen
sulfide, ammonia, moisture, etc., enters with steam into a stripping column.
Desulfurised naphtha comes out from the bottom and further cooled before it is sent
to storage. A flow sheet of naphtha pretreatment is shown in Figure below:

Catalytic Reforming:
Reforming represents the total effect of numerous reactions such as cracking,
polymerization, dehydrogenation, and isomerization taking place simultaneously
Hydrogen, a significant by-product, is separated from the reformate for recycling
and use in other processes.
Feedstock and Product
Feedstock: Heavy Naphtha (Paraffins 45-55 %, Olefins 0-2 %, Naphthenes 30-40
%, Aromatics 5-10 %)
Product: High Octane Gasoline: (Paraffins 30-50 %, Olefins 0 %, Naphthenes 5 –
10 %, Aromatics 45-60 %)
Most processes use platinum as the active catalyst. Sometimes platinum is
combined with a second catalyst (bimetallic catalyst) such as rhenium or another
noble metal.
There are many different commercial catalytic reforming processes including
platforming, powerforming, ultraforming, and Thermofor catalytic reforming.
Reforming are classified as :
1) Continuous: Catalyst can be regenerated continuously and maintained at a high
activity. (Higher capital cost).

2) Semi- regeneration: Regeneration is required at intervals 3 to 24 months

depending on the severity of operation. (Low capital cost). High H2 recycle rates
and operating pressure is utilized to minimize coke.
3) Cyclic: compromise between the two extremes having a swing reactor for
regeneration.
Naphtha Platinum Reforming (Platforming):

Desulfurised naphtha is catalytically converted to high octane gasoline by the
reaction of a platinum catalyst in a reactor in a hydrogen environment. This type of
treatment is also known as platforming.
The major reactions involved during platforming are:
1- Dehydrogenation of paraffins and naphthenes:
n-paraffins = alkenes + hydrogen
naphthenes = aromatics + hydrogen
These reactions are endothermic.
2- Dehydrocyclisation of paraffins:
n-paraffins = naphthenes + hydrogen
This reaction is also endothermic.
3- Isomerisation of paraffins:
n-paraffins = i-paraffins
This reaction is nearly thermo-neutral.
4- Hydrocracking:
n-paraffins + hydrogen = hydrocarbon gases + lighter paraffins
naphthenes + hydrogen = hydrocarbon gases + lighter naphthenes
These reactions are exothermic.
5- Hydrogenation
alkenes + hydrogen = alkanes
aromatics + hydrogen = naphthenes
These reactions are exothermic.
6- Coking reactions:
hydrocarbons = carbon or cokes

Desulfurised naphtha and hydrogen are mixed and preheated by heat exchangers
followed by heating in a furnace to raise the temperature of the vapour mixture to
around 500°C. A reformer catalyst contains 0.3–0.35% wt of platinum. Since, during
the reaction, coke formation takes place over the surface of the catalyst, the
reactivity of the catalyst comes down and the temperature has to be raised to
maintain the uniform reactivity.
The temperature is not raised further than 520°C to avoid damage to the catalyst.
Traces of sulfur, nitrogen, and oxygen present in the feed naphtha deactivate the
catalyst and that is why naphtha pretreatment is carried out before reforming. In
order to reduce coke formation, hydrogen circulation must be maintained.
Usually, three reactors in a series are used while regeneration is carried out after
complete shutdown of the unit.
A typical reforming unit is shown in Figure below. Three reactors are used and the
catalyst is loaded and distributed in these reactors.
Since the overall reactions are endothermic in nature, the product temperature falls
while exiting from a reactor and is reheated by the intermediate furnace before it
enters the second and third reactor. Finally, the product mixture is cooled and
separated from hydrogen in a vessel at a temperature of 50°C. Hydrogen is partly
recycled back to the reactors and a part is sent to other hydrogen consuming units
in the refinery. The product from the bottom of the vessel is sent to a plated column
to separate the butane and lighter hydrocarbons from the final product, known as
the de-butanised reformate, which is cooled before storage.


Petroleum Refinery Lab
Experiment No. 4

Research Octane Number of Spark-Ignition Engine Fuel, D2699
Objective: quantitative determination of the knock rating of liquid spark-ignition engine fuel in
terms of Octane number.
Theory:
Octane Number is defined as the volume percentage of iso octane in blend of normal heptane
and iso octane, which produces the same knock intensity as the test fuel under standard test
conditions in an ASTM internal combustion engine.
The key indication of performance property of gasoline under various engine conditions is its
octane number (ON) which included: Research Octane Number (RON) and Motor Octane
Number (MON).Finished gasoline must meet certain octane number specifications.
To determine octane number of gasoline an engine test is carried out at two different speeds
and the octane umber are defined as the research octane number (RON) and the motor octane
number (MON), which are conducted at two different speeds, 600 and 900 rpm, respectively.
MON is always less than RON for the same fuel. Octane number shown on pumps at fuel
stations is the average of RON and MON.
Research and Motor Octane numbers (RON, MON) constitute the main quality characteristics of
the gasoline, as they provide a sensitive indication of the anti-knocking behavior of the fuel. The
higher the octane number the better the gasoline resists detonation and the smoother the
engine runs.
Antiknock Index (AKI) or Pump Octane Number (PON; sometimes Posted Octane Number) is a
measure of a fuel’s ability to resist engine knock or octane quality. The AKI is an arithmetic
average of RON and MON. The AKI of a motor fuel is the average of the RON and MON as
determined by the formula (R+M)/2
Anti-knock additives:
1. Oxygenates: ethers—methyl tertiary-butyl ether (MTBE), ethyl tertiary-butyl ether (ETBE),
tertiary-amyl methyl ether (TAME), di-isopropyl ether (DIPE); alcohols— methanol, ethanol,
tertiary butyl alcohol (TBA).
2. Aromatic hydrocarbons (aromatics): toluene, xylene, and benzene. The latter is toxic
(including carcinogenicity) and therefore its amount is restricted by 1 % vol. Maximum
allowable concentration of aromatics in gasoline is 35 % vol.
3. Aromatic amines: m-toluidine, p-toluidine, p-tert-butylaniline, technical pseudocumidine, N
methylaniline, and cumidines.
4. Organometallic compounds : Like the first anti-knock additive tetra-ethyl lead (TEL) is based
on Pb, these additives also are based on metals Mn and Fe.

Digital Octane Tester K 88600 XL:
Apparatus & Description:
Other parts:
Light shield
Sample holder


Discussion:
1. Define Octane number.
2. Why do we measure octane number of gasoline?
3. Which hydrocarbons have highest ON and which one has the lowest?
4. What is meant by RON, MON and AKI?
5. How can gasoline ON be increased?

Worksheet
Experiment no.:
Title: Octane Number
Name:
Class:
Date:
Sample 1
RON =
MON =
AKI =
Sample 2
RON =
MON =
AKI =

Petroleum Refinery
Experiment No.: 1
Title: Standard Test Method for

Conradson Carbon Residue of Petroleum Products D189
Objective: To determine the amount of carbon residue left after evaporation
and pyrolysis of crude oil.
Introduction:
Carbon residue is defined as the residue formed by evaporation and thermal
degradation of a carbon containing material.
When a petroleum fraction is heated and vaporized in the absence of air at
atmospheric pressure, the nonvolatile compounds have a carbonaceous
residue known as carbon residue CR, therefore heavier fractions with more
aromatic contents have higher carbon residues while volatile and light
fractions such as naphthas and gasolines have no carbon residues, CR is
particularly an important characteristic of crude oils and residues. Higher CR
values indicate low quality fuel and less hydrogen content. In most cases CR is
reported in wt% by conradson method as %CCR.
Carbon residue can be correlated to a number of other properties. It increases
with an increase in carbon to hydrogen ratio (C/H), sulfur content, nitrogen
content and asphaltenes content. As hydrogen content increases the carbon
residue decreases. The hydrogen content is expressed in terms of H/C. The
following relation can be used to estimate CCR from H/C:
%CCR = 148.7 – 86.96 H/C
Apparatus & Materials:

Conradson carbon residue apparatus includes the
following:
1. Porcelain Crucible
2. Iron Crucible— Skidmore iron crucible

Petroleum Refinery
3. Iron Crucible
4. Wire Support
5. Hood
6. Insulator—Asbestos block, refractory ring, or hollow sheet-metal box
7. Burner
8. Sample of crude oil
Procedure:
1- Weigh accurately the empty dry and clean crucible on the analytical
balance, M1, gm.
2- Shake thoroughly the sample to be tested, first heating to 50°C when
necessary to reduce its viscosity.
3- A 10 g sample is weighed (free of moisture & suspended matter) into a
porcelain crucible containing 2 glass beads (M2).
4- The crucible is placed in the center of skidmore crucible which is set at
the center of the iron crucible and covers are applied to both of
skidmore & iron crucible.
5- A strong flame is applied from the gas burner to have high heat for a
period of 10 min.
6- When smoke appears form the chimney the burner is moved or tilted to
ignite the vapor then removed temporarily.
7- When the vapors cease to burn the heat is reapplied until the bottom of
the sheet iron crucible is cherry red.
8- The burner is removed and the apparatus is cooled until no smoke
appears then the cover of skidmore crucible is removed (about 15 min)
9- The porcelain or silica crucible is removed, cooled and weighed again
accurately, M3, gm and the % of carbon residue is calculated based on
the original sample.

Petroleum Refinery
Results & Calculations:

Calculate the carbon residue of the Sample, from the equation:
Where;
is the mass of empty crucible, in grams;
is the mass of crucible + test Portion, in grams;
is the mass of crucible + residue, in grams.
Discussion:
1- What are the most important factors that affect the accuracy of the
results of this experiment?
2- What is the impact of carbon on the devices and equipment which treats
crude oil and petroleum products with high percentage of carbon
residue?
3- Do impurities and suspended matters have any effect on the results?
How can you eliminate this effect?
4- Which hydrocarbons are expected to have a higher carbon residue?
Why?

Petroleum Refinery
Worksheet
Experiment no.: 1
Title: Conradson Carbon Residue (CCR)
Name:
Class:
Date:
Mass of empty crucible, ,g
Mass of crucible + test Portion, ,g
Mass of crucible + residue, ,g

Petroleum Refining-Practical/ 3rd Stage
Boiling points and Distillation curves

For any pure component, a single temperature generally represents the boiling
point for the component. However, a mixture of different components such as crude
oil or petroleum fractions, where the boiling point differs from more volatile
components to less volatile components. Therefore, the boiling points of a crude oil
of unknown composition can be represented by a curve of different boiling point
temperatures versus volume % of crude oil distilled (Riazi, Characterization and
properties of petroleum fractions, 2005). A typical TBP curve is shown in figure
below.
True boiling points curve is the presentation of volatility characteristics of petroleum

fractions or crude oils. The boiling point of the lightest hydrocarbon component is
called as initial boiling point (IBP). The boiling of the heaviest hydrocarbon
component is called as final boiling point (FBP). The temperature range between
initial boiling point and final boiling point is called boiling point range. For a
particular petroleum fraction or crude oil, IBP and FBP points are not as reliable as
the middle points of boiling range. In reality, it is very difficult to predict the final
boiling point for heavy hydrocarbons. However, the FBP is estimated for the crude
oil, the heaviest hydrocarbon may not vaporize at that temperature. If boiling points
are estimated up to 70% of total crude oil feed, then the remaining 30 % of crude is
referred as a residue.
There are several methods to determine boiling points and develop true boiling
point curve of petroleum fractions that are described below.

Laboratory Test Methods

ASTM D86
ASTM D86 is a batch distillation operation for determining and reporting boiling
points of crude oils, and petroleum fractions. It is a simple and convenient method
mostly applied to the distillation of motor gasoline, aviation gasoline, aviation
turbine fuel, naphtha, kerosene, gas oil, distillate fuel oil, and similar petroleum
products.
The distillation is conducted at atmospheric pressure, which required a very small
amount of sample for the experiment. ASTM D86 operation is partly similar to a
simple distillation operation; the system consists of apparatus such as a flask with
attached glass tube condenser, temperature sensor on the top of the flask, and
heating source. The system does not consist of packed or tray column (of minimum
15 theoretical plates) and reflux arrangement causes the operation not to attain a
high degree of separation; therefore the boiling points from this standard method
are not true boiling points of petroleum fractions. The boiling points from ASTM D86
need to be converted to the true boiling points.
ASTM D1160
ASTM D1160 is nothing but the vacuum distillation frequently used for the
determination of boiling points of heavy hydrocarbons such as atmospheric residue
after ASTM D86 method. As mentioned earlier ASTM D86 is an atmospheric
distillation. All heavy hydrocarbons cannot be vaporized in the atmospheric
distillation. Actually above 300℃ in the atmospheric distillation, heavy hydrocarbons
usually undergo a cracking process in which they start to break down in to lighter
molecules. Therefore, there is a need to execute the further distillation at reduced
pressure in order to avoid the cracking process.
ASTM D1160 is the test method in which the distillation is carried out at reduced
pressures without any significant cracking
approximately one theoretical plate fractionation; therefore, the boiling point curves
from ASTM D1160 are closer to true boiling point curves.

ASTM D2892
includes
an atmospheric distillation as well as a reduced pressure distillation.
ASTM D2892 system contains column of 14 to 18 theoretical plates and operates
on reflux ratio of 5:1 which gives high degree of fractionation. Therefore, the
distillation curves obtained from the system is in the form of true boiling point (TBP)
and it can be expressed with mass or volume.
ASTM D2892 is the laboratory standard which plays crucial part in estimation of
crude oil value, determination of yields of fractions of different boiling points, and
technical discussions for fixing the commercial values of petroleum products.
Because of high degree of separation, the products obtained from this laboratory
technique can be used for analytical studies, engineering, and products quality
evaluations.
True Boiling Point Method

The boiling curves from all ASTM test methods except ASTM D 2892 are not true
boiling point curves for crude oil or fractions.
TBP distillations require columns with 15-100 theoretical plates and high reflux
ratios (5:1 or greater) to achieve accurate separation of components in a mixture.
TBP distillations are difficult, time consuming, and expensive as compared to
Laboratory test methods.
ASTM D2892 is only laboratory test method gives high degree of fractionation
because the system has column with 15 theoretical stages and it operates at reflux
ratio of 5:1. This method offers the compromise between efficiency and time so that
the comparison of distillation data from different laboratories can occur (ASTM
D2892, 1998).

Characterization Factors:
Watson K
Since the early days of the petroleum industry it was desired to define a
characterization parameter based on measurable parameters (some physical
properties of crude oil) to classify and identify hydrocarbon types.
The Watson characterization factor Kw is one of the oldest characterization factors
originally defined by Watson et al. of the Universal Oil Products (UOP) in mid
1930s. For this reason the parameter is sometimes called UOP characterization
factor and is defined as:
Where:
= mean average boiling point,

SG = specific gravity
The purpose of definition of this factor was to classify the type of hydrocarbons in
petroleum mixtures. Depending on the value of the Watson characterization factor,
crude oils are classified as
Paraffinic (Kw = 11-12.9),
Naphthenic (Kw = 10-11), or
Aromatic (Kw < 10)
Given the ASTM D86 distillation the volume average boiling point (VABP) can
be calculated as the average of the five boiling temperatures at 10, 30, 50, 70
and 90 percent distilled.
where all temperatures are in F.

The Mean Average Boiling Point (MeABP) is calculated using the following
equation:

Example:
Calculate the MeABP of a petroleum fraction if the API gravity of this fraction
is 62 and calculate the Watson’s characterization factor.
Solution:
The D86 distillation temperatures are converted to F. The VABP is obtained
from equation:

ASTM D 86 and TBP Conversion:

If aistillation data are available in the form of ASTM D 86 and desired distillation is
TBP, the following procedure can be followed:
The results of ASTM D 86 distillations can be converted into an atmospheric ASTM

2892 TBP by using an equation proposed by Riazi and published by the API
Riazi-Dauber Method
. . . . . . . . . . . . . . . . . (1)
Correlation Constants for Equation (1)

ASTM D 86
Vol.% a b
range, oC
0 0.9177 1.0019 20-230
10 0.5564 1.0900 35-305
30 0.7617 1.0425 50-315
50 0.9013 1.0176 55-320
70 0.8821 1.0226 65-330
90 0.9552 1.0110 75-345
95 0.8177 1.0355 75-400
Example:
A low boiling naphtha has the ASTM D86 temperatures of 77.8, 107.8, 126.7, 155
and 184.4 0C at 10, 30, 50, 70 and 90 vol.% distilled. Calculate VABP and MeABP
for this fraction.
Solution:
Using equations above VABP and SL are calculated as follows:
VABP = (77.8 + 107.8 + 126.7 + 155 + 184.5) / 5 = 130.3 oC = 403.5 oK
SL = (184.4 - 77.8) / 80 = 1.333 oC (K)/%

From the following Equation, correction temperature is calculated:
o
Δ = C

MeABP =
MeABP = 121.7 oC
Example:
ASTM D 86 and TBP distillation data for a kerosene sample are given in the
following table. Predict the TBP curve from ASTM data using Riazi-Daubert method
and calculate AAD for the method.
Vol. % ASTM D 86 TBP
distilled Exp. oC Exp. oC
0 165.6 146.1
10 176.7 160.6
30 193.3 188.3
50 206.7 209.4
70 222.8 230.6
90 242.8 255.0
Solution: The Riazi-Daubert method for conversion of ASTM data is presented by

equation (1) and constants in table given above.
The summary of results is given in table below. The average absolute deviation is
calculated as 2.2 oC.
Vol. % ASTM D 86 TBP TBP

AD, oC
distilled Exp. oC Exp. oC Calculated, oC
0 165.6 146.1 134.1 12.0
10 176.7 160.6 160.6 0.0
30 193.3 188.3 188.2 0.1
50 206.7 209.4 208.9 0.5
70 222.8 230.6 230.2 0.4
90 242.8 255.0 254.7 0.3
AAD, oC 2.2

Transformation of atmospheric TBP curve to ASTM D 86- A relationship

established by Riazi (1982)
. . . . . . . . . . . . . . . . . (2)
Where:
Temperature TBP [K] and Temperature of ASTM D 86 [K]
a, b = Transformation Coefficients (See application example)
Example:
Distillation ASTM D86 to TBP (Riazi Method)
Vol. % Coefficient Coefficient Temp. Temp.

distilled a b D 86, oC TBP, oC
0 0.9177 1.0019 36.5 14.1
10 0.5564 1.0900 54.1 33.4
30 0.7617 1.0425 76.9 68.9
50 0.9013 1.0176 101.5 101.6
70 0.8821 1.0226 131.0 135.1
90 0.9552 1.0110 171.0 180.5
95 0.8177 1.0355 186.5 194.1
The accuracy of method depends on the smoothness of curve. Errors affect the
points in the low % distilled ranges. Average error is in order of 5 °C for smooth
curve.

Determination of Viscosity Index
For determining the VI of particular oil, first its kinematic viscosity is measured at 100 C.
Assume the measured kinematic viscosity at 100 C is 6 mm2/s (Cst). Then the corresponding oil,
i.e. one whose kinematic viscosity at 100 C is also 6 mm2/s, is selected from the series of
viscosity index 0 (L). The other corresponding oil, i.e. one whose kinematic viscosity at 100 C is
also 6 mm2/s, is also selected from the series of viscosity index 100 (H). Thus, we deal with
three oils, all having kinematic viscosity 6 mm2/s at 100 C:
 The particular oil (oil U) with unknown VI
 The selected oil (oil L) with VI=0
 The selected oil (oil H) with VI=100
Now all three oils are cooled down to 40 C, and their viscosity is measured at that temperature.
Naturally, each of the three viscosities will be higher than that at 100 C, but viscosity of the
worst oil increases most. Suppose that viscosity of oil L increases to 25 mm²/s, the viscosity of
oil H increases to 20 mm²/s, and the viscosity of our particular oil U increases to 21 mm²/s
(Unknown viscosity index).
where VI is viscosity index, U is

kinematic viscosity of the examined
oil at 40 C (mm²/s). L is kinematic
viscosity of the oil at 40 C (mm²/s)
with viscosity index 0 and kinematic
viscosity at 100 C equals with that of
the examined oil. H is kinematic
viscosity of the oil at 40 C (mm²/s)
with viscosity index 100 and
kinematic viscosity at 100 C equals
with that of the examined oil. D=L-H
is a difference of viscosities at 40 C.
Kinematic viscosity of the basic oils with index 0 and 100 and on temperatures 100 C and 40 C
are listed in tables. Thus, for a given viscosity at 100 C, the corresponding values of L, U, and D
can be read out from a table. The calculated VI value must be rounded to integer numbers.

Standard Practice for

Calculating Viscosity Index from Kinematic Viscosity at 40 and 100°C
Viscosity index is an arbitrary number used to characterize the variation of the kinematic
viscosity of a petroleum product with temperature. For oils of similar kinematic viscosity, the
higher the viscosity index, the smaller the effect of temperature on its kinematic viscosity.
The viscosity index is a widely used and accepted measure of the variation in kinematic viscosity
due to changes in the temperature of a petroleum product between 40 and 100°C. A higher
viscosity index indicates a smaller decrease in kinematic viscosity with increasing temperature
of the lubricant. The viscosity index is used in practice as a single number indicating
temperature dependence of kinematic viscosity.
Scope
This practice specifies the procedures for calculating the viscosity index of petroleum products,
such as lubricating oils from its kinematic viscosities at 40 and 100°C.
Procedure A—for petroleum products of viscosity index up to and including 100
Procedure B—for petroleum products of which the viscosity index is 100 or greater
Table 1 given in this practice applies to petroleum products with kinematic viscosities between
2 and 70 mm2/s (cSt) at 100°C. Equations are provided for calculating viscosity index for
petroleum products having kinematic viscosities above 70 mm2/s (cSt) at 100°C.
Procedure A—For Oils of Viscosity Index Up to and Including 100

If the kinematic viscosity of the oil at 100°C is less than or equal to 70 mm2/s (cSt), find from
Table 1 the corresponding values for L and H. Measured values that are not listed, but are
within the range of Table 1, may be obtained by linear interpolation. The viscosity index is not
defined for oils of kinematic viscosity of less than 2.0 mm2/s (cSt) at 100°C.
If the kinematic viscosity is above 70 mm2/s (cSt) at 100°C, calculate the values of L and H as
follows:
where:
L = kinematic viscosity at 40°C of an oil of 0 viscosity index having the same kinematic viscosity
at 100°C as the oil whose viscosity index is to be calculated, mm2/s (cSt),
Y = kinematic viscosity at 100°C of the oil whose viscosity index is to be calculated, mm2/s (cSt),
H = kinematic viscosity at 40°C of an oil of 100 viscosity index having the same kinematic
viscosity at 100°C as the oil whose viscosity index is to be calculated mm2/s (cSt).
Calculate the viscosity index, VI, of the oil as follows:

where:
U = kinematic viscosity at 40°C of the oil whose viscosity index is to be calculated mm2/s (cSt).
Calculation Example:
Measured kinematic viscosity at 40°C of the oil whose VI is to be calculated = 73.30 mm2/s (cSt)
kinematic viscosity at 100°C of the oil whose VI is to be calculated = 8.86 mm2/s (cSt)
From Table 1 (by interpolation) L = 119.94
From Table 1 (by interpolation) H = 69.48
Substituting in Eq 3 and rounding to the nearest whole number:
Procedure B—For Oils of Viscosity Index of 100 and Greater

If the measured kinematic viscosity at 100°C is greater than 70 mm2/s (cSt), calculate the value
of H as follows:
Calculate the viscosity index, VI, of the oil as follows:
where:
Calculation Example:
(1) Measured kinematic viscosity at 40°C of the oil whose VI is to be calculated = 22.83 mm2/s
(cSt), kinematic viscosity at 100°C of the oil whose VI is to be calculated = 5.05 mm2/s (cSt)
From Table 1 (by interpolation) H = 28.97
Substituting by Eq 8 (by logarithms):
(2) Measured kinematic viscosity at 40°C of the oil whose VI is to be calculated = 53.47 mm2/s
(cSt), kinematic viscosity at 100°C of the oil whose VI is to be calculated = 7.80 mm2/s (cSt)
From Table 1, H = 57.31
Substituting in Eq 8 (by logarithms):

Petroleum Refining Lab.
Experiment No. 2

Water in Crude Oil by Distillation D 4006 – 81 (Reapproved 2000)
Objective: To find the percentage of water in a sample of crude oil by

distillation (Dean Stark) method.
Introduction
Water is present with crude oil in reservoir rocks and it enters the pores with
oil during some stimulation processes which are carried to stimulate the well,
such as Acidizing and Fracturing. The water forms with oil emulsions of two
types: Hydrophilic (water in oil) and Hydrophobic (oil in water). The stability
of petroleum emulsions depends on the nature and composition of the film
material surrounding the water droplets, which prevents their mixing with
each other.
This test method covers the determination of water in crude oil by distillation.
The sample is heated under reflux conditions with a water immiscible solvent
which co-distills with the water in the sample. Condensed solvent and water
are continuously separated in a trap—the water settles in the graduated
section of the trap, and the solvent returns to the distillation flask.
The water and sediment content of crude oil is significant because it can cause
corrosion of equipment and problems in processing, it leads to high pressure
in the tower and to loss of energy used to heat the oil in addition to the salts in
water which deposit on the distillation devices and inside the pipes.
A determination of water and sediment content is required to measure
accurately net volumes of actual oil in sales, taxation, exchanges, and custody
transfers.
If the water content in oil is more than 2%, it complicates the process of
distillation to a large extent. The presence of water in petroleum products and
fuels is also undesirable, especially in cold weather conditions.

Apparatus & Materials:

The apparatus, shown in Fig. 1, consists of:
1. A glass distillation flask —a 1000-mL (or
500ml) round-bottom, glass, distillation
flask
2. A 5-mL calibrated, graduated water trap
with 0.05-mL graduations connected to
the distillation flask.
3. A 400-mm condenser fitted with the
trap.
4. A drying tube filled with desiccant (to
prevent entrance of atmospheric
moisture) is placed on top of the
condenser.
5. An electric heating mantle that can
uniformly distribute heat to the entire
lower half of the flask.
6. Solvent: different solvents can be used.
Toluene, xylene or a mixture of both or
naphtha. The solvent is miscible with oil
but immiscible with water.
7. A sample of crude oil.
Procedure:
1. Measure (100 ml) of the crude oil sample in a graduated cylinder and
transfer it to the distillation flask.
2. Add 100 ml solvent to the flask in three stages 50 ml, 25ml and 25ml
using the graduated cylinder of step one (total solvent volume 100 ml).
3. Use glass beads or other boiling aids to reduce bumping distillation
flask.
4. Assemble the apparatus as shown in Fig. 1, making sure all connections
are vapor and liquid-tight.
5. Insert a drying tube containing an indicating desiccant into the end of
the condenser to prevent condensation of atmospheric moisture inside
the condenser.

6. Circulate water, between 20 and 25°C, through the condenser jacket.

7. Apply heat to the flask. Heat should be applied slowly during the initial
stages of the distillation (condensation rate 2-5 drops/ second) to
prevent bumping and possible loss of water from the system.
8. Continue heating until no water is visible in the condenser and the
volume of water in the trap remains constant for at least 5 min.
9. Allow the trap and contents to cool to 20°C. Dislodge any drops of water
adhering to the sides of the trap and transfer them to the water layer.
Read the volume of the water in the trap.
Results & Calculations:

1. Record the final volume of water in the trap to the nearest 0.025 ml.
2. Calculate the water in the sample as follows:
Water volume % = (water volume / sample volume) * 100
Discussion:
1- What is the source of water and sediments in crude oil?
2- What are the factors affecting accuracy of the result?
3- What are the disadvantages of the presence of water with crude oil?
4- How is oil – water emulsion treated in oil industry?
5- Is the process of separating the water in this experiment physical or
chemical and why the solvent is used?

Work Sheet
Experiment No. 2
Water Content in Crude Oil by Distillation Method
Name:
Class:
Date:
Volume of water in the graduated trap =


to Rankine
from Rankine
Celsius [°C] = ([°R] − 491.67) × 5⁄9 [°R] = ([°C] + 273.15) × 9⁄5
Fahrenheit [°F] = [°R] − 459.67 [°R] = [°F] + 459.67
Kelvin [K] = [°R] × 5⁄9 [°R] = [K] × 9⁄5
to Celsius
from Celsius
Fahrenheit [°F] = [°C] × 9⁄5 + 32 [°C] = ([°F] − 32) × 5⁄9
Kelvin [K] = [°C] + 273.15 [°C] = [K] − 273.15
Rankine [°R] = ([°C] + 273.15) × 9⁄5 [°C] = ([°R] − 491.67) × 5⁄9
to kelvins
from kelvins
Celsius [°C] = [K] − 273.15 [K] = [°C] + 273.15
Fahrenheit [°F] = [K] × 9⁄5 − 459.67 [K] = ([°F] + 459.67) × 5⁄9
Rankine [°R] = [K] × 9⁄5 [K] = [°R] × 5⁄9
to Fahrenheit
from Fahrenheit
Celsius [°C] = ([°F] − 32) × 5⁄9 [°F] = [°C] × 9⁄5 + 32
Kelvin [K] = ([°F] + 459.67) × 5⁄9 [°F] = [K] × 9⁄5 − 459.67
Rankine [°R] = [°F] + 459.67 [°F] = [°R] − 459.67

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Petroleum Refinery Lab.

Standard Test Method for

Petrochemical Dept. Page 1

1. Distillation Flask - flask with a side

Petrochemical Dept. Page 2

1. Place (100) ml of the sample in the distillation flask.

Petrochemical Dept. Page 3

Data recording for Fractional Distillation test

Petrochemical Dept. Page 4

Volume percent Temperature

Petrochemical Dept. Page 5

Petroleum refinery processes

Petrochemical Dept. Page 1

Auxiliary Operations and Facilities include:

Modern Petroleum Processing

Physical and chemical processes

Petrochemical Dept. Page 2

Figure 1: Overall Refinery flow

CRUDE OIL PRETREATMENT (DESALTING)

Petrochemical Dept. Page 3

temperature is limited by the vapor pressure of the crude-oil feedstock. In both

Figure 2: Desalting of crude oil

Main Components of Distillation Columns:

Trays and plates:

Petrochemical Dept. Page 5

Petrochemical Dept. Page 6

Petrochemical Dept. Page 7

Petrochemical Dept. Page 8

Atmospheric Distillation Tower:

Petrochemical Dept. Page 9

Atmospheric Distillation Unit

Atmospheric Tower Products:

Petrochemical Dept. Page 10

Petrochemical Dept. Page 11

Petrochemical Dept. Page 12

Petrochemical Dept. Page 13

Petrochemical Dept. Page 14

Petrochemical Dept. Page 1

Product Yield and Properties

Petrochemical Dept. Page 2

Figure 1 Coil Visbreaker

Petrochemical Dept. Page 3

Figure 2 Soaker Visbreaker

Petrochemical Dept. Page 4

Petrochemical Dept. Page 5

Figure 3: Delayed Coking

2. Continuous (Fluid) Coking:

Petrochemical Dept. Page 6

Petrochemical Dept. Page 7

1. Fluid Catalytic Cracking (FCC)

Petrochemical Dept. Page 8

Figure 4 FCC Unit

Petrochemical Dept. Page 9

product stream (cracked product) is then charged to a fractionating column where it

Petrochemical Dept. Page 10

Thermofor Catalytic Cracking

Petrochemical Dept. Page 11

Comparison between thermal and catalytic cracking