Iocl industrial training_chemical_engineering_report

INDIAN OIL CORPORATION LIMITED
A VOCATIONAL TRAINING PROJECT REPORT
Period of training:
Branch: Chemical Engineering
Submitted To
Ms. Krishna Kumari
Asstt. Manager (L&D)
IOCL, Barauni Refinery
Submitted By
Afzal Reza
Enrollment No. 0103CM141005
In the partial fulfilment for the award of the degree of
Bachelor of Chemical Engineering
From
LAKSHMI NARAIN COLLEGE OF TECHNOLOGY, BHOPAL (MADHYA PRADESH)

PREFACE
Knowledge has two aspects- theoretical and practical and no theoretical concept is
complete without having knowledge of its practical application. A few weeks industrial
training was introduced as a part of curriculum of Bachelor of Engineering. This industrial
training programme proves beneficial to the future engineers as they are confronted with
the problems of actual work environment during their training period.
With the advancement of technologies, the older methods and machineries are replaced
by newer ones in all of the industries. This advancements have opened a way to great
opportunities to well qualified engineers. In order to tune up with the contemporary
technology efficiently the engineer requires formal training in their respective fields of
work. For that, he/she must have complete knowledge for the entire system to do the
troubleshooting in every possible way so that production could not be hampered.
I feel pleasured to be the part of this vocational training at INDIAN OIL CORPOATION
LIMITED, Barauni Refinery, during this, I got the opportunity to develop skills industrially
and defined my interest in technical and professional field.
In this vocational training report I have tried my best to introduce about all the important
sections and functions of this refinery where I got the chance to learn various things in
very short span of 28 days.
Yours sincerely
(Afzal Reza)

This project is an outcome of 4 weeks of vocational industrial training, which I have to
undergo for the partial fulfilment of the Bachelor of technology (Chemical Engineering).
The satisfaction and euphoria that accompany the successful completion of this project
could be incomplete without mentioning the names that made it possible without their
support the completion of this project would not have been possible.
I take this opportunity to express my whole hearted thanks to Mr. K.C. Daimary, D.G.M.
(M.S.Q,L&D), Ms. Krishna Kumari, A.M (L&D).
It is with great pleasure that I express my gratitude to Mr. Rajeev Acharya, Officer (L&D).
At last I would like to express my thanks to following people who helped me during training
period at Barauni Refinery:
AVU-1: Mr.B.K.Ram
AVU-2: Mr. Vijay Kumar Mishra
AVU-3: Mr.Sandeep Kumar
CRU: Mr.Durga Prashad Upadhyay
MSQ: Mr.V.K. Yadav
BXP: Mr. C. S. Mahato
DHDT: Mr. P. Das
SRU: Mr. Anup Kumar
It is with a profound sense of respect that I express my heartfelt gratitude to the
management, L&D department, and all the members of the organization who took time out
of their busy schedule and helped me in carrying out this project.
Regards,
Afzal Reza
ACKNOWLEDGEMENT

1. PETROLEUM REFINING: THE HISTORY BEHIND IT
2. IOCL: AN OVERVIEW
3. BARAUNI REFINERY: AT A GLANCE
4. FIRE AND SAFETY
5. AVU (ATMOSPHERIC AND VACUUM DISTILLATION UNIT)
6. BXP (BARAUNI EXTENSION PORJECT)
a. RFCCU (Reduced Fluidized Catalytic Unit)
b. DHDT (Dehydrotreating Unit)
c. HGU (Hydrogen Generation Unit)
d. SRU (Sulphur Recovery Unit)
7. MSQ (MOTOR SPIRIT QUALITY)
a. ISOM(Isomerization Unit)
b. NHDT (Naphtha Hydroreating Unit)
c. G+ (Gasoline + Unit)
8. CRU (CATALYTIC REFORMING UNIT)
a. NSU (Naphtha Splitter Unit)
b. HTU (Hydrotreater Unit)
c. CRU (Catalytic Reforming Unit)
9. COKER A&B
10. LRU
11. BIBLIOGRAPHY
TABLE OF CONTENTS

1. PETROLEUM REFINING: THE HISTORY BEHIND IT
The first refinery, started in 1861, produced kerosene by simple atmospheric distillation.Kerosene
remained the primary product in demand for the next 30 yearsuntil two significant events changed
the situation.
➢ Inventionof electric light
➢ Invention of Internal Combustion Engines based on Gasoline (Petrol) and Diesel
Due to these changes demand for Lighter Products and Middle Distillates increased so modern
technology and Environmental Considerations called for more and more high quality and superior
products.Today’s modern refinery employs more than 20 different operations.
The process of refining is
Each refinery has its own processing scheme which depends on product demand & specification
and individual economic consideration. There can be three types of refinery
➢ SIMPLE: Refinery performs crude distillation, reforming and sulphur treating. They
have limited products.
➢ COMPLEX: Theyinclude vacuum distillation, gas recovery, FCC, HC and Alkylation
other than simple refinery.
➢ INTEGRATED: They include recovery of material from VTB- coking other than
complex refinery. They produce all products.
The combination of refining processes and operations employed (complexity) varies from one
refinery to another.
• FACTORS DECIDING THE COMPLEXITY OF A REFINERY
➢ Nature/source of crude oils to be processed
➢ Demand pattern in the markets to be covered
➢ Product quality – current / future
➢ Production of feed stocks for downstream units
Crude
Oil
“Marketable”
Products
PETROLEUM REFINERY
Equipment
Energy
EMPLOYEES

➢ Inter-fuel substitution
➢ Environmental stipulations
• COMPLETE REFINERY PROCESS
2. IOCL: AN OVERVIEW
INDIAN OIL CORPORATION LIMITED is an Indian state-owned oil and gas company
headquartered at Mumbai, India. It was formed in 1964 by merger of Indian Refineries Ltd. (1958)
and Indian Oil Company Ltd. (1959). It is the leading Indian Corporate in Fortune's prestigious
‘Global 500’ listing of world's largest corporates at 161st
position for the year 2016, and has a
33,000 strong workforce.
Born from the vision of achieving self-reliance in oil refining and marketing for the nation,
IndianOil has gathered a luminous legacy of more than 100 years of accumulated experiences in all
areas of petroleum refining by taking into its fold, the Digboi Refinery commissioned
in1901.IndianOil controls 11 of India’s 23 refineries. The group refining capacity is 80.7 million
metric tonnes per annum (MMTPA) - the largest share among refining companies in India. It
accounts for 35% share of national refining capacity.The strength of IndianOil springs from its
experience of operating the largest number of refineries in India and adapting to a variety of
refining processes along the way. The basket of technologies, which are in operation in IndianOil
refineries include: Atmospheric/Vacuum Distillation; Distillate FCC/Residue FCC; Hydrocracking;
Catalytic Reforming, Hydrogen Generation; Delayed Coking; Lube Processing Units; Vis-
breaking; Merox Treatment; Hydro-Desulphirisation of Kerosene&Gasoil streams; Sulphur
recovery; De-waxing, Wax Hydro finishing; Coke Calcining, etc. The Corporation has
commissioned several grassroots refineries and modern process units. Procedures for
commissioning and start-up of individual units and the refinery have been well lay out and

enshrined in various customised operating manuals, which are continually updated.
IndianOil refineries have an ambitious growth plan for capacity augmentation, de-bottlenecking,
bottom up gradation and quality up gradation. On the environment front, all IndianOil refineries
fully comply with the statutory requirements. Several Clean Development Mechanism projects
have also been initiated. To address concerns on safety at the work place, a number of steps were
taken during the year, resulting in reduction of the frequency of accidents.
Innovative strategies and knowledge-sharing are the tools available for converting challenges into
opportunities for sustained organisational growth. With strategies and plans for several value-added
projects in place, IndianOil refineries will continue to play a leading role in the downstream
hydrocarbon sector for meeting the rising energy needs of our country.
3. BARAUNI REFINERY: AT A GLANCE
Barauni Refinery is the second oil refinery in the public sector and forms an important part in
Indian petrochemical industry. Barauni refinery was built in collaboration with Russia and
Romania situated 125 km from Patna. Barauni refinery was commissioned in 1964 with a refinery
capacity of 1 million metric ton per annum (MMTPA). It was dedicated to the nation by the union
minister of petroleum, Prof. HUMAYUN KABIR in January 1965. With various revised and
expansion projects at Barauni refinery, capability for processing high-sulphur crude has been
added, thereby increasing not only the capacity but also the profitability of the refinery.
Barauni refinery was initially designed to process low sulphur crude oil(sweet crude) of Assam.
After establishment of other refineries in the north-east, Assam crude is unavailable for this
refinery. Hence, sweet crude is being sourced from Africa, East Asian and Middle East countries.
The refinery receives crude oil by pipeline from Paradip on the east coast via Haldia,
There are 3 AVU units from which AVU-3 is designed for high-sulphur crude and producing
Bitumen. Matching secondary processing facilities such Residue Fluidized Catalytic Cracking Unit
(RFCCU); diesel hydrotreater(DHDT), sulphur recovery unit(SRU) have been added. These state
of the art eco-friendly technologies have enabled the refinery to produce green fuels company with
international standards. The third reactor has been installed in the DHDT unit to produce diesel that
complies with the Bharat Stage-III auto fuel emission norms. The MS quality up gradation project
has been newly added to remove benzene and some sulphur thus increasing octane number also.
• THE VARIOUS PRODUCTS OBTAINED AT BARAUNI REFINERY ARE:
➢ LPG
➢ Motor spirit ( petrol)
➢ Naphtha
➢ Kerosene
➢ Diesel
➢ Sulphur
➢ Raw petroleum coke
➢ Bitumen
➢ LCO (light cycle oil)

➢ HCO (heavy cycle oil)
Crude oil is separated into fractions by fractional distillation. The fractionating column is cooler at
the top than at the bottom because the fractions at the top have lower boiling points than the
fractions at the bottom. The heavier fractions that emerge from the bottom of the fractionating
column are often broken up (cracked) to make more useful products. All of the fractions are
subsequently routed to other refining units for further processing.
Raw oil or unprocessed oil is not very useful in the form it comes in out of the ground. Although
“light, sweet” (low viscosity, low sulfur) oil has been used directly as a burner fuel for steam vessel
propulsion, the lighter elements form explosive vapors in the fuel tanks and so it is quite dangerous,
especially so in warships. For this and many other uses, the oil needs to be separated into parts and
refined before use in fuels and lubricants, and before some of the byproducts could be used in
petrochemical processes to form materials such as plastics, and foams. Petroleum fossil fuels are
used in ship, automobile and aircraft engines. These different hydrocarbons have different boiling
points, which mean they can be separated by distillation. Since the lighter liquid elements are in
great demand for use in internal combustion engines, a modern refinery will convert heavy
hydrocarbons and lighter gaseous elements into these higher valve products using complex and
energy intensive processes.
Oil can be used in so many various ways because it contains hydrocarbons of varying molecular
masses, forms and lengths such as paraffin’s, aromatics, naphthenes ( or cycloalkanes), alkenes, di-
enes, & alkynes. Hydrocarbons are molecules of varying length and complexity made of only
hydrogen and carbon atoms. Their various structures give them their differing properties and
thereby uses. The trick in the oil refinement process is separating and purifying these.

4. FIRE AND SAFETY TRAINING
The products which are processed and the process which are used are highly dangerous and
hazardous. So, safety is very essential in avoiding the accidents and mishaps in the field. For this
purpose all the work men are given safety training before going inside the plant.
• THE MAIN CAUSE OF ACCIDENTS IS
➢ Unawareness of process and equipments
➢ Poor supervision
➢ Unsafe conditions and acts
➢ Overconfident
➢ Without proper test permits are given
Whenever any work man enters the plant, he/she should be equipped with all the PPE’S i.e.
personal protecting equipment.
1) SAFETY HELMET: It is very important equipment used for the safety of head of a person
from injuries that can result from the falling objects and also at places where operating space is
less.
2) SAFETY SHOES: It is used for protecting our feet from any strike or any chemicals falling on
the floor.
3) SAFETY GOOGLES: It is used for protecting our eyes.
4) EAR PLUGS: To guard our ears from any loss to the eardrums due to loud noise.
5) HAND GLOVES: To handle very reactive or explosive chemicals also in jobs where regular
touching of hot or cool objects are alone.
6) NOMEX: It is full body covering clothing which is to be worn when going to Nomex
Designated area.
Industrially, some main hazards are standardised which could be most critical to the people
working there. They are namely:
➢ Falling objects
➢ Electrical shock
➢ Striking objects
➢ Asphyxiation
➢ Burns from fire/explosion
• SAFETY MEASURES THAT MUST BE TAKEN:
1. All employees must wear PPE’s while working in the plant.
2. Whenever gaseous fumes are present in the plant, a person should be equipped with breathing
apparatus. Breathing
3. Apparatus contains the oxygen cylinder, face mask and a safety helmet with a black pack to
hold the cylinder.
4. Proper ladders and staircase must be provided with handrails in the different levels of the plant.
A periodic check of the stairs must be carried out.
5. Rail guards must be used when climbing above 2 metres.

6. In case of fire or emergency one should dial 333/4444, IOCL fire and safety departments
numbers.
7. Full proof guarding of motors and pumps and other electrical or mechanical machineries must
be done so that no injuries happen to the worker operating it or working nearby.
8. All cranes must be equipped with weight limit switch.
9. Auto sprinklers and smoke detectors must be present.
10. Flame proof coating of wire cables used in plants.
11. Miniature circuit board (MCB’s), Moulded Case Circuit Board (MCCB’s), Earth Leakage
Circuit Board(ELCB’s) must be present so that it trips the electric supply if there is some fault
in the electrical circuit.
12. Fire extinguishers should be present at suitable positions to avoid fire.

5. ATMOSPHERIC AND VACUUM DISTILLATION UNIT
In IOCL, Barauni refinery there is 3 AVU units namely AVU1, AVU2 and AVU3. AVU1 &
AVU2 are almost identical with same capacity of 1.75 MMTPA. They are only for low-sulphur
crude. AVU3 is different from above two as it can process high-sulphur crude and has capacity of
3MMTPA. It also contains steam generation and Gasoline & LPG caustic wash.
AVU is a mother unit of any refinery. Crude is first of all processed in this unit and products
formed are either stored or send to various units as a feed.
Distillation is a method of separating the components of a solution which depends on distribution
of the substance between gas and liquid phases. Distillation exploits the vapour pressure of
different components i.e. relative volatility in creation of a second phase by addition of heat. By
appropriate manipulation of the process or by the repeated vaporisation and condensation, it is
possible to make complete separation.
In distillation, the new phase differs from the original by its hear content, but heat is readily
removed or added. In distillation the feed is introduced more or less centrally in vertical cascade of
stages. Vapour rising in the section called the enriching or rectification section is washed with
liquid to remove or absorb the more volatile component.
Since no extraneous material is added, condensing the vapour issuing from the top which is rich in
more volatile component provides washing liquid. The liquid return to the top of the tower called
reflux and the material permanently removed is called the distillate, which is a liquid rich in more
volatile component.
In the section below the feed called the stripping or exhausting section, the liquid stripped of
volatile component by vapour produced at the bottom by partial vaporisation of the bottom liquid in
the re-boiler.
• OPERATION SEQUENCE OF AVU:
➢ FEED PREHEAT
➢ DESALTING
➢ FEED VAPORISATION
➢ FEED DISTILLATION
➢ PRODUCT COOLING AND STORAGE
• PROCESS DESCRIPTION:
Crude oil received from pipelines is pumped from tanks through heat exchangers after exchangers
heat with various hot stream, the crude stream the crude streams attain a temperature of (120 to
130) degree Celsius. After attaining temperature the two crude flowscombine together and enter in
a de-salter for separation and removal of water and salt. Inside the unit crude is pumped to de-salter
through two parallel passes of pre-de-salter heat exchanger train and heating is done with various
product streams from different columns. Both the passes combine in a single header and enter the
de-salter from bottom through 2 separate nozzles after splitting. Then pre-topping column carries
to the main fractionators where the distillation is carried out.
The main column is provided with valve trays in top section.

The trim cooler, the condensed gasoline at a temperature of 45degree Celsius is collected in a 3-
way reflux vessel.
A part of the gasoline is sent as reflux to the column under flow control for maintaining the
temperature of the column top. The other part is pumped to naphtha caustic wash. Sour water
collected in the boot is drained under level control of the vessel. Gases from the top of the reflux
vessel are sent to the flare under control of the hydrocarbon level.
The next side stream from the column is of kerosene. A part of this kerosene goes to the kero
stripper where the lighter ends are stripped by steam. The vapour from the stripper goes back to the
main fractionating column. The stripped bottom is sent to rundown via heat exchangers. The
balance kero is pumped as circulating reflux-exchanging heat with incoming crude in various heat
exchangers for maintaining the temperature of the column.
The next side stream is of LGO & LGO CR. LGO product is condensed while the LGO CR is sent
back to the column as circulating reflux.
• MAIN FRACTIONATOR:
Inside the tower, the liquids and vapours are always at their bubble points or dew points
respectively. So highest temperature is at the bottom and lowest temperature is at the top of the
column.
Stripping steam is given in the bottom of the column, which decrease the partial pressure and thus
the boiling point of the hydrocarbon inside the column and therby strips out the lighter portion of
the feed. It is also an alternative source of heat.
The overhead vapours from the main fractionating column is condensed and cooled in the air
condenser to 65 degree Celsius and further cooled in the trim cooled. The condensed gasoline at a
temperature of 45 degree Celsius is collected in the 3-way reflux vessel.
A part of the gasoline is sent as reflux to the column under flow control for maintaining the
temperature of the column top. The other part is pumped to
➢ Kero/LGO section
➢ Structured packing in LGO/HGO section
➢ The bottom stripping section
➢ Over flash section
• PRODUCTS OBTAINED:
➢ LPG
➢ HEAVY NAPTHA
➢ NAPTHA
➢ KEROSENE
➢ LGO & HGO
➢ ATF
➢ LVGO
➢ HVGO
➢ SHORT RESIDUE
• PRE TOPPING COLUMN:

As the name suggests this column is used before main fractionating column. This is done for
increasing the productivity of the process and making it more efficient. The desalted crude at a
temperature of 230 degree Celsius enters the column and flashes into liquid and vapour.
Inside the tower, the liquids and vapours are always at their bubble points or dew points
respectively. So highest temperature is at the bottom and therby strips out the light portion of the
feed. It is also an alternative source of heat. The overhead vapour from the main fractionator is
condensed and cooled in CR are sent through heat exchangers for heating the crude. From the
outlet of heat exchangers HVGO CR is returned to the column.
The third side stream is of SLOP & over flash. A part of it is sent to stripping section as overflash
while balance is sent to suction of SR pumps.
The bottom product of the column is short residue, while is pumped to rundown via heat
exchangers. SR also acts s a feed to various units like COKER & RFCCU.
• THE VACUUM COLUMN IS PROVIDED WITH:
➢ Structured packing in LVGO pump around section.
➢ LVGO/HGVO fractionation section.
➢ Wash section and valve trays in the bottoms stripping section.
RCO from main fractionating column is feed to the vacuum column because further heating in
main fractionators can cause cracking in the column. Vacuum column operates below atmospheric
pressure. Lowering the pressure decreases the boiling point of the various components in the crude
and thus it can be further separated in the vacuum column. This increases the overall yield.
Top of the vacuum column in provided with a demister to minimize the entraining of liquid
droplets in the vapour going to the overhead condenser. The overhead condensers are taken to the
pre-condensers where the steam and condensable are condensed. The sour water is pumped back to
the de-salter water tank.
❖ Atmospheric & Vacuum Distillation Unit Flow Diagram

6. BARAUNI REFINERY EXTANSION PROJECT(BXP)
• INTRODUCTION:
The Barauni Refinery Expansion project was envisaged for augmenting crude processing capacity
from 4.2 MMTPA to 6.0 MMTPA along with matching secondary processing facilities. The main
objective of Barauni Refinery expansion project is to produce market oriented pattern of
environment friendly high value products like LPG, Diesel and motor spirit. BXP was launched in
2002.
The project mainly consists of
➢ Residue Fluidized catalytic cracking unit (RFCCU)
➢ Diesel Hydro treating unit (DHDT)
➢ Hydrogen Generation unit (HGU)
➢ Sulphur Recovery unit (SRU)
➢ Amine Regeneration unit (ARU)
➢ Sour water stripping unit (SWSU)
➢ Catalytic Reforming unit (CRU)
UNIT FEED PRODUCT
RFCCU
Blend of short residue &
HVGO( heavy vacuum gas
oil)
Fuel gas oil, LPG, gasoline,
diesel, DCO
DHDTU
High sulphur low cetane
diesel
Low sulphur high Cetane
diesel
HGU Naphtha Hydrogen(99.99% pure)
SWSU
Rich amine containing high
amount of dissolved H2S
from DHDT/RFFCCU
Lean amine (containing less
amount of dissolved H2S) to
DHDT, RFCCU acid gas of
SRU
SWSU
Sour water( containing high
amount of dissolved H2S
from DHDT, RFCCU,
AVU,s COKERS
UNIT CAPACITY FEED OBTAINED
RFCCU 1.3 MMTPA
Stone & Webster engineering
corp. Ltd. USA
LPG Recovery unit
GASOLINE TURBINE
UNIT
245000T MERICHEM USA
DHDT 2.2 MMTPA UOP, USA
SRU 2X40 TPD STORK, Netherlands
ARU 201 TPH UOP, USA
SWSU 93 TPH UOP, USA
HGU 34000 TPA HTAS, Denmark

a. RESIDUE FLUIDISED CATALYTIC CRACKING UNIT (RFCCU)
The main products of cracking reaction in a fluid catalytic cracking (FCC) reactor are
➢ Absorbed Gas
➢ Liquefied Petroleum Gas(LPG)
➢ Heavy Naphtha
➢ Light cycle oil(LCO)
➢ Heavy cycle oil(HCO)
➢ Slurry oil
• REACTION SYSTEM:
o GENERAL
The riser is designed to rapidly and infinitely mix the hot regenerated catalyst with liquid feed
stocks. Fresh feed is pumped to the base of the riser and divided into equal flows to each of four
bed injectors. The feed which has been preheated is finally atomized and mixed with dispersion
steam in the feed injector mixing chamber and injected into the riser. The small droplets of feed
contact hot regenerated vaporized oil internally mixes with the catalyst particles and cracks into
lighter more valuable products along with slurry oil, coke and gas located further up the riser. In
addition to these oil injectors, injectors are provided to feed naphtha at the riser bottom. Injectors
are provided to recycle the filtrate from the slurry filter to the riser.
o FRESH FEED PREHEAT
Fresh feed is pumped on flow control from the feed surge drum to the feed preheat exchanger to
recover heat from the process. The feed is heated against HCN, LCO, HCO recycle, and slurry
product and slurry pump around before being set to the riser feed nozzles. The feed pump is
automatically controlled by partial bypassing the fresh feed side of the slurry pump around feed
exchangers.
o FEED
Oil feed to the riser is preheated before entering the reaction system. Dispersion steam is supplied
to each fresh injector to promote fresh feed atomization and vaporization, the total dispersion steam
is flow controlled with flow to each feed injector balanced by hand controlled glove valves.
o RISER REACTOR
Supplied by the hot regenerated catalyst riser outlet temp (ROT) is regulated controlling the
regenerated catalyst admitted to the riser through the regenerated. The sensible heat, heat of
vaporization and heat of reaction by the oil feed catalyst side valve (RCSV).
The reaction stem design begins at the reactor or riser base. The bottom section may cause
turbulence and uneven catalyst flow pattern. Therefore a high density zone is provided to absorb
shocks and stabilize the catalyst flow during the transition to upward flow. Reactor pressure floats
on the main fractionators press and the therefore is not directly controlled at the converter section.
A press controller at the wet gas compressor knock out drum provides for steady operating press of
the reaction system.

The initial separator and reactor cyclone separates the product vapours from spent catalyst and
return the catalyst to the stripper bed. The cyclone dip legs are equipped with surrounded trickle
valve to prevent reverse flow of gas up the dip legs.
o STRIPPER
Catalyst exiting the inertial separator is pre-stripped with steam from steam rings just below the dip
legs. This is an important feature for reducing coke yield. The catalyst is further stripped by steam
from the main steam ring as the catalyst flows down the stripper.
A series of baffles enhance the contacting of steam and spent catalyst. The stripper bed is fluidized
by the stripping steam which displaces the volatile hydrocarbon contained on and in the catalyst
particles before they enter the first stage regenerator. Coke remaining on the catalyst is burned off
in the regenerators. A fluffing steam ring is located in the bottom head of the stripper to ensure the
catalyst is fluidized before entering the spent catalyst standpipe. The catalyst is aerated in the spent
catalyst standpipe to maintain proper density for stable head gain. The main steam ring, plus the
fluffing ring and the pre-stripping rings are designed to provide about 5 kg of steam per metric ton
of catalyst. Normal rate for all three rings is 3 kg of steam per metric ton of catalyst.
A. REACTION SYSTEM- SPENT CATALYST TRANSFER
The stripped spent catalyst flows down the spent catalyst standpipe and through the spent catalyst
slide valve (SCSV). Aeration steam is added to the standpipe at several elevations to maintain
proper density and fluid characteristics of the spent catalyst. The spent catalyst slide valve controls
the stripper’s level by regulating the flow of spent catalyst from the stripper. Spent catalyst flows
into the first stage regenerator through a distributor, which drops catalyst onto theregenerator
catalyst bed stone & Webster’s spent catalyst distributor is a “bathtub” design with weirs for even
catalyst flow. To maintain properly fluidized catalyst fluidization aims introduction through
Spurger pipes located along the “bathtub” distributor’s bottom section. This special distributor
ensures that the entering coke laden catalyst is spread across the regenerator bed.
B. REGENERATOR SYSTEM- GENERAL
The first stage regenerator burns 60 to 70 per cent of the coke and the remainder is burned in the
second stage regenerator. This two-stage approach to regeneration adds considerable flexibility to
the process. Potential heat is rejected in the first stage regenerator from incomplete combustion of
carbon to carbon monoxide. When processing heavy feed and the need for heat rejection is high,
the amount of coke burned in the first stage regenerator is increased, thereby lowering the final
temperature of the regenerated catalyst. When running lighter feeds, the amount coke burned in the
first stage regenerated catalyst temperature. The amount of coke burned in the first stage can be
varied by adjusting the air flow rate. This feature allows operating flexibility for processing
different feed stocks. Regenerator temperature is not directly controlled. As the coke burn increase
with higher combustion air rates, the regenerator temperature will rise.
The heat of combustion released by the burning coke heats the catalyst and will later supply the
heat required by the reactor. The heat balance of a two-stage regeneration unit is more flexible than
a single stage regeneration system potential energy in the form of carbon monoxide from the first
stage regenerator can be adjusted while complete regeneration of the catalyst is accomplished in the
second stage.

By controlling the combustion air to the first stage regenerator, the temperature in the first stage is
limited to approximately 705 degreeCelsius.
The partially regenerated catalyst flows down through the first stage regenerator bed to the entrance
of the lift line. Aeration is supplied in this area to ensure smooth flow of catalyst to the line. A
hollow-stemmed plug valve (PV) regulates the catalyst flow to the lift line. The plug valve controls
the first stage regenerator’s bed level. Air injected through the hollow stem plug valve into the lift
line is flow controlled to lift line should be maintained above 6500 Nm3/hr. Minimum allowable
catalyst/air mixture velocity is 4.5 m/s for smooth catalyst lift line operations. In the event that lift
air is lost, catalyst will fill the lift line and air blower discharge pressure may not be sufficient to lift
the dense catalyst. Five emergency blast steam taps are provided on the lift line to fluidized and
reduce the catalyst head in the lift line.
Four sets of two-stage cyclones separate entrained catalyst from the flue gas exiting the first stage
regenerator. The flue gas passes through a slide valve and an orifice chamber where the pressure is
reduced to approximately 0.09 kg/cm2G. Incineration of the CO in the flue gas is then
accomplished at the CO incinerator. Pressure on the first stage regenerator is modulated by
controlling the flue gas valve upstream of the orifice chamber. By controlling the flue gas valve, the
differential pressure between the first stage and second stage regenerators is adjusted.
C. REGENERATION SYSTEM- SECOND STAGE REGENERATOR
The partially regenerated catalyst flows up the lift line and enters the second stage regenerator
below the air ring. A distributor on the end of the lift line provides efficient distribution of catalyst
and air from the lift line. Catalyst is then completely regenerated to less than 0.05% carbon at more
severe conditions than in the first stage. Very little carbon monoxide is produced in the second
stage and excess oxygen is controlled by flow control of the second stage regenerator combustion
air for efficient and complete combustion because most of the hydrogen in coke was removed in the
first stage, very little water vapour is produced in the second stage. This low water vapour
minimizes hydrothermal deactivation of the catalyst as higher regeneration temperatures are
experienced.
Three two stage external refractory lined cyclones are used on the second stage flue gas to remove
entrained catalyst. This design expands the operating envelope for regenerator temperatures, which
tend to be higher for residue-type feeds. The first stage cyclone dip legs are external to the
regenerator. Catalyst recovered in the cyclone is returned to the regenerator bed below the normal
operating level by way of the dip legs. Aeration is supplied to the dip legs to provide for smooth
fluidized catalyst flow and is necessary to prevent catalyst from backing up into the cyclones.
D. REGENERATION SYSTEM- REGENERATED CATALYST TRANSFER
The hot regenerated catalyst flows from the second stage regenerator through a lateral to the
withdrawal well (WDW). In the withdrawal well, a quiescent bed is established at proper standpipe
density (545 kg/m3) by controlling the fluidizing air rate to the WDW ring. Injecting aeration air at
several elevations on the regenerated catalyst standpipe provides a smooth stable flow of catalyst
down the standpipe. As the head pressure increases down the standpipe and the catalyst mass is
compressed, these aeration points are used to replace the “lost” volume, thereby ensuring proper
catalyst flow properties. Each aeration tap has adjustable flow rates to maintain desirable standpipe
density as catalyst circulation rates and/or catalyst types vary.

At the bottom of the regenerated catalyst standpipe the RCSV controls the flow of hot catalyst. The
reactor-riser outlet temperature sets the position of the RCSV, which regulates the catalyst flow.
Catalyst continues moving down the 45 degree slanted wye section to the riser base where the
catalyst beings the upward flow toward the fresh feed injections. Fluidization gas used in the wye
section ensures stable catalyst flow in the 45 degree lateral transfer.
Prior to the fresh feed injectors, a high-density zone must be provided to absorb shocks and
stabilize the catalyst flow. The stabilization steam promotes smooth and homogeneous catalyst
flow as the catalyst moves upward toward the fresh feed injectors. The stabilization steam ring is
located at the base of the wye.
❖ Flow Diagram of RFCCU
b. DIESEL HYDRO DESULPHURISATION TREATER UNIT
• INTRODUCTION:
Earlier diesel produced from several primary units was sent to the market without sulphur removal.
But due to increased pollution control norms diesel was needed to be desulfurized. Also the imported
crude which is cheaper contains higher sulphur than the native crude. So seeing the cost as well as
pollution consideration a new diesel hydro desulphurisation unit was set up in the refinery.

• BASIS OF DESIGN:
A. PLANT DEFINITION
IOCL intends to install a diesel hydrotreater in its refinery at Barauni in the state of Bihar to improve
the diesel quality with respect to cetane number (48.5 minimum) while meeting the diesel stability.
B. UNIT CAPACITY
➢ Design capacity: 2.2 MMTPA
➢ 2. Steam factor : 8000 hr. per year
➢ 3. Turndown : 40 % of design capacity.
C. FEEDSTOCK DEFINITION
The design feed will process blended feed containing straight run gas oil from low sulphur imported
crude (SRGO-LS), Straight Run Gas oil from High Sulphur imported from Middle East (SRGO-HS),
Total crude oil from FCCC (TCO), Light Coker gas oil from Coker unit (LCGO).
D. MAKE UP HYDROGEN
The makeup hydrogen for the hydro-treater unit will be supplied from the Hydrogen unit having the
following characteristics:
➢ Hydrogen purity - 99.5 vol. % minimum
➢ Chloride – 1 ppm max.
The feed is pumped to a coalescer where water present is drained out through the boot after it is
routed through heat exchanger where it exchanges heat with the rundown product, the final
temperature being 100° C. Further it is passed through the filter to remove fine particles. The filtered
feed is taken into a Feed Surge Drum from where it is taken through pump to a heat exchanger train
where it gains heat from the reactor bottom product, the final temperature being 327° C. The pump is
driven by a PRT (pressure recovery turbine). After this, it is mixed with recycle hydrogen gas and
passed through a furnace where it reaches a temperature of around 340° C. This feed is then fed in to 2
reactors in series. The reactors have fixed bed catalyst (2 in each reactor). The first bed consists of a
catalyst that traps the metal coming in the feed and second as well as the other two beds consists of
catalysts that improves the cetin no. and causes hydrodesulphurisation.
The reactions are exothermic and recycle hydrogen is added in the bottom product of the first reactor
that becomes the feed to the second reactor. The reactor bottom exit temperature is 368°C. It is routed
to a heat exchanger train where it loses heat (140° C), then through air coolers (54° C) and is taken to
a HPS drum having a boot in the bottom. In between wash water and makeup hydrogen is also added.
In the HPS drum the gas goes into a knock out drum from the top. In the KOD, the top gas containing
unused hydrogen and some other gases sent to a compressor which sends it to the feed line before the
furnace .the bottom of the HPS as well as the KOD goes into a flash drum. One line from the bottom
of the HPS goes to PRT also.

In the flash drum water drains out from the water boot and the bottom product goes to a column after
passing through a set of heat exchangers (260° C). MP steam is added to the column through the
bottom. The bottom product (257° C) is our run down product. It is cooled in two heat exchangers and
then in air coolers (400° C) and fed into a coalescer to remove any water present. The top of the
coalescer vessel is our final diesel which is sent to the storage tanks.
The top vapours of the column are taken through air coolers and condensers where it loses heat (41°
C) and then into a stripper receiver. The top of this vessel contains gasses mainly hydrogen sulphide.
This is sent to a KOD and then to amine absorber where lean amine is added and the bottom product is
rich amine which is sent to the amine recovery unit (ARU). The top product goes to stripper where
sweet gas is generated. The bottom of the stripper receiver drum is un-stabilized naphtha, part of
which is sent to RFCCU and rest as reflux to the main column.
DIESEL HYDROTREATMENT UNIT (DHDT)
• INTRODUCTION:
Petroleum fractions contain various amounts of naturally occurring contaminants including organic
sulphur, nitrogen, and metal compounds. These contaminants may contribute to increase levels of air
pollution, equipment corrosion, and cause difficulties in further processing the materials. The union
fining process is the proprietary fixed bed, catalytic process developed by UOP for hydro treating a
wide range of feedstocks. The process uses a wide range of catalytic hydrogenation method in order to
produce the upgraded quality of petroleum distillate fractions by decomposing the contaminant with
negligible effect on the boiling range of the feed. Union fining is mainly designed to remove nitrogen
and sulphur. In addition the process does an excellent job of saturating the ole-finic and aromatic
compounds while reducing Conrad Son carbon and removing other contaminants such as oxygenates
and organometallic compounds. The desired degree of hydro treating is obtained by processing the
feedstock over a fixed bed of catalyst in the presence of large amount of hydrogen at temperature and
pressure dependent on the nature of feed and the amount of contaminant removal required. The
hydrotreater unit is designed to improve the diesel cetane number to 48.5 (min) while meeting the
diesel specifications of 1.6 mg/100ml (max) and reducing sulphur content to 0.2 % by wt. Future
provisions are considered in this unit to produce HSD of cetane no. 51 and further reduction of sulphur
content to 0.05 wt. %, the two features of hydro treating process and refining reactions. The
mercaptides, sulphides and disulphides react in an atmosphere of hydrogen to produce corresponding
saturated and aromatics compounds, hydrogen sulphides and ammonia. The hydrotreater feed consists
of straight run kerosene II (SRK II) and Coker kerosene-I and diesel mode consisting of straight run
gas oil from low sulphur imported crude (SRGO-LS), straight run gas oil from high sulphur imported
crude (SRGO-HS), total cycle oil from fccu (TCO) and light Coker gas oil (LCGO). Union fining
units are designed for dependable stable operation. UOP’s selective, high active catalysts operate for
long periods of time between regenerations. Specific process objectives determine which UOP catalyst
is influenced to only slight extent by the type of feed processed. The same catalysts in varying
quantities can be used to hydro treat straight run naphtha, vacuum gas oil, and catalytically and
thermally cracked distillates. The widespread use of catalytic reforming units has made available large
amounts of hydrogen making it feasible to hydro treat many or all of the distillate produced by the
refinery.
• GENERAL PROCESS DESCRIPTION:

The function of DHDTU is to improve diesel quality by removing the impurities like sulphur,
suspended particles and by increasing the cetane number of diesel. Increased cetane no. helps to
improve the ignition property of fuel.
The diesel is fed to the unit through pump, removes water particles, suspended particles by feed
coalesce and feed filter. The pump sends the feed to reactors from surge drum through feed
exchangers and heater. In reactor the product react with hydrogen in presence of catalyst and increase
the cetane number of diesel. The products then enter the high pressure receiver after releasing
temperature through exchangers. The hydrogen from HGU through compressors enters to the receiver.
The liquid product from the bottom enters to stripper column via low pressure flash drum and
exchanger train. The gaseous product (hydrogen) from vessel enters to recycle gas compressor and
enters to reactor after gaining temperature from exchanger train. The gaseous product from top of low
pressure flash drum is taken to amine absorber where hydrogen sulphide is absorbed in amine. The
rich amine is taken from the bottom of the absorber. Sweet gas from the top of the absorber is taken to
fuel gas header of refinery.
❖ Flow Diagram Of DHDT

c. HYODROGEN GENERATION UNIT
DHDT and other units need hydrogen and this unit provides them. This plant deals with the
following process steps:
1. Desulfurization and de-chlorination
2. Steam reforming
3. CO conversion
4. Purification
Since it is catalyst based unit hence Cl and S act as poison to the catalyst. Hence, is needed to
remove.
• DESULFURISATION SECTION:
The catalyst in the reforming and shift section is extremely sensitive to sulphur compounds since
those will cause deactivation or poisoning.
The MT shift catalyst in CO conversion section is sensitive to sulphur and chlorine compounds.
Hydrogen is added to mix to FCCU and naphtha and then total mixture is preheated to 260°C. The
vaporized mixture is then passed through Hydrogenetor chlorine guard, sulphur absorber in the
series where sulphur and chlorine compounds are being hydrogenated to H2S and HCl and then
being absorbed.
• HYDROGENATION:
The first catalyst in the desulfurization section is a cobalt-molybdenum based hydrogenation
catalyst 10.0 m³ in a single bed placed in the reactor. The Topsoe catalyst TK-250 has a bulk
density of about 0.5Kg/l.
Besides the hydrogenation of chloride and sulphur compounds the catalyst hydrogenates olefins
into saturated hydrocarbons.
Reactions are:
RCl + H2 RH + HCl
RSH + H2 RH + H2S
• ADSORPTION OF CHLORINE:
Having passed the hydrogenation catalyst in the first reactor, the HCl is absorbed in the second
reactor, 703-R-02. It is essential for the absorption of the chlorine that the organic chlorides are
hydrogenated by the hydrogenation catalystTK-250 before entering this bed because HTG-1 is not
active towards organic chloride compounds. The absorption curve is very sleep ensuring an
extremely low content of HCl in the exit stream.
The catalyst will react in following manner
K2CO3 + HClKCl + KHCO3
KHCO3 + HClKCl + H2O + CO2
• ADSORPTION OF SULPHIDES:
The hydrogen sulphide is absorbed in 3rd
and 4th
reactors in sections 703-R-03A and 703-R-03B.

The two reactors are located in series and are identified. 703-R-03B is acting as guard vessel in
case of breakthrough when 703-R-03A is taken out of service for replacing the catalyst. Both
reactors have two identical beds, each located with 12.95 m³ of Topsoe HTG-3 catalyst which
consist of activated zinc oxide.
The ZnO reacts with H2S in following manner
H2S + ZnOZnS + H2O
By installing two sulphur absorbers in the series, it is possible to change the catalyst in the first
absorber while the second absorber is on stream. Normally, both absorbers will be on streams and
second one will act as guard.
• REFORMING SECTION:
The gas from the desulfurization section is mixed with stream and sent to the reforming section of
an adiabatic pre-reformer and a tubular reformer where hydrocarbons are reacted over nickel
catalyst with streams. A tubular reformer is used consisting of 110 tubes and 180 burners where we
obtain CO2, CO, H2 and certain ppm of CH4.
The stream reforming of hydrocarbons can be described in following ways
CH4 +H2O  CO +3H2O + HEAT
• SHIFT SECTION:
CO +H2O  CO2 + H2 + HEAT
In this section CO is converted into CO2. After this product is passed through fan cooler and water
cooler and then fed to purification section.
• PURIFICATION SECTION:
It is also known as PSA (Pressure Swing Absorber) which works at apressure of 20 kg/cm2
in the
presence of catalyst. 10 bed PSA is used and due to pressurization at 20 kg/cm2
, lighter and heavier
ends get separated out and layers are formed.

d. SULPHUR RECOVERY UNIT
• PROCESS SUMMARY:
The sulphur recovery process applied in the design, which is known as the Super Claus Process is
based on the partial combustion of H2S with a ratio controlled flow of air, which is maintained
automatically in a correct quantity to accomplish the complete oxidation of all hydrocarbons and
ammonia present in acid gas feed, and to obtain 0.5-0.7% H2S at the inlet of the Super Claus
Reactor. In the conventional Claus process the air to acid gas ratio is maintained to provide an H2S
/SO2 ratio of exactly 2 in the burner effluent gas. This is known to be the optimum ratio of H2S
/SO2 for the Claus section. The Super Claus process operates according to a different philosophy.
In this process air to acid gas ratio is adjusted to achieve an H2S /SO2 ratio of greater than 2 in the
burner effluent. The combustion air is controlled in such a manner that the concentration of the H2S
gas entering the Super Claus stage is in the range of 0.5-0.7 vol. % H2S. In order to accommodate
this requirement the front end combustion step is operated off ratio. In other words the front end
combustion step is operated on H2S control rather than the customary H2S /SO2 ratio control.
If the H2S concentration entering the Super Claus section is too high, more air is added to the main
burner to create more SO2, or if it is low, less air is added to the burner.
• UNIT DEFINITION:
Capacity 2*40 TPD of element sulphur
Turn down 30%
• INTRODUCTION:
SRU is designed to recover sulphur from the vapours originating from following sources
➢ The amine regeneration unit
➢ The sour water stripping section
The process is the combination of the conventional Claus process and the recently developed
process for selective oxidation of hydrogen sulphide.
The unit consists of two parallel SRU trains. Each train consist of the following sections
➢ A Claus section, consisting of a thermal stage and 3 reactor stage
➢ A super Claus section
Sulphur Recovery Unit consists of three main basic units
➢ Amine recovery unit (ARU)
➢ Sour water stripper unit (SWSU)
➢ Sulphur recovery unit (SRU)

AMINE RECOVERY UNIT (ARU)
• CAPACITY: 175 MT/hr.
• CHEMICAL REACTION:
1. R2 NH3 S --------------------- R2NH + H2S
2. (R2 NH3)CO3 --------------- R2NH + CO2 + H2O
Where R is CH3CH2 OH group
• PURPOSE:
In order to remove absorbed H2S & CO2 from amine.
• PROCESS:
In this unit the rich amine from different units are send to flash drum from where it is send to pump
and through heat exchanger to stripping section where steam from top and feed from bottom
passed. When feed and steam comes in contact, steam absorbs amine and H2S is passed from top
and collected. The line amine so formed is send to different unit for use and H2S is send to SRU
section.
• PRESSURE: 4.5 kg/cm2 g
• TEMPERATURE: 50 Degree Celsius.
• PRODUCT: Lean amine at temperature of 127 Degree Celsius.
SOUR WATER STRIPPING UNIT (SWSU)
• CAPACITY: 92.8 MT/ hr.
• PURPOSE: In order to remove H2S & NH3
• CHEMISTRY OF THE PROCESS AND PROCESS DESCRIPTION:
Sour water contains H2S, NH3 as major contaminants & phenols, cyanides, chlorides, carbon
dioxide and hydrocarbons as minor one
NH3 + H2S ------------- (NH4
+
) + (HS-
)
The principal of sour water stripping is based on the application of heat to reduce the
solubility’s of (NH4
+
) & (HS-
) in the water phase pulls the dilution and depletion of gaseous
NH3& H2S by rising steam vapour. So equilibrium shifts left. That is, on adding sufficient heat
to sour water the NH3 and H2S will come out of the solution and be easily stripped away as
gases.
But NH3 is extremely soluble in water, some ammonium salts will persist in sour water. Also
some ammonium salts such as NH4Cl are not easily decomposed. This residual ammonia can be
released from solution by the injection of strong base such as NaOH to establish the following
reactions:
(NH4
+
) + (OH-
) ---------- NH3 + H2O

This freed ammonia can then be stripped away. Acid gas flare system is providing to rout
acid/sour gases from all vents/relief valves to acid gas relief header.
7. MSQ(MOTOR SPIRIT QUALITY)
a. ISOM
• PURPOSE OF THE ISOM UNIT:
The purpose of this process is to saturate benzene and to improve the research and motor octane
number of the light naphtha feed (predominantly C5/C6) before blending into the gasoline pool. The
light naphtha fraction is typically high in normal isomer content resulting in a low octane number
(typically < 68). The isomerization process converts an equilibrium proportion of these low octane
normal isomers into their higher octane branched isomers.
• FEED:
The unit feed is mainly Light Hydro treated Naphtha from NHDT containing predominantly mono
branched C5 and n-C5 and n-C6 paraffin.
Light reformate from Reformate splitter which contains, in addition to above mentioned paraffin,
benzene also in high concentration can be processed in ISOM.
• PRODUCT:
The unit produces mainly Light isomerate rich in mono branched C5 paraffin and multi branched
C6 paraffin and no benzene having more octane number than feed. Unit also produces some Heavy
reformate rich in cyclo-hexane and C7+naphthene. Both reformates are sent to MS pool.
The ISOM process developed and licensed by Axens consists of three fixed bed adiabatic reactors,
with benzene saturation carried out in the first reactor, and C5/C6 isomerization reactions completed
in the following two reactors. The isomerization reactions are carried over a fixed chlorinated
catalyst bed in a hydrogen environment. Operating conditions are not severe as reflected by
moderate operating pressure, low temperature, low hydrogen partial pressure and high catalyst
space velocity. These operating conditions promote the isomerization reaction, minimize
hydrocracking and minimize equipment capital costs
• DESIGN BASIS:
o Unit capacity: 15750 kg/hr. (378 MTPD), (126000 MTPA)
o Turn down capacity: (Min. T’put): 50 %
o On stream hour per annum: 8000
• GENERAL INTRODUCTION:
The ISOM unit includes the following sections:
➢ FEED AND MAKE-UP H2 SECTION
➢ REACTION SECTION

➢ STABILIZER SECTION
➢ DE-ISOHEXANIZER SECTION
➢ SCRUBBER SECTION
❖ Process Flow Diagram:
• BRIEF PROCESS FLOW DESCRIPTION (NORMAL OPERATION):
O FEED AND MAKE-UP HYDROGEN SECTION
Light hydro treated naphtha from NHDT unit (Unit 801), light reformates from Reformate Splitter
unit (Unit 103) and Deisohexanizer recycle products are combined in feed surge drum 802-V-01.
Unit feed is further pumped by feed pumps 802-P-01 A/B to the two feed dryers 802-DR-01 A/B
that operate in series and in downflow direction. These two dryers protect the isomerization catalyst
from irreversible damage with water, which is extremely poisonous to the reactor catalyst.
The make-up hydrogen from CRU unit (Unit 03) or from HGU (Hydrogen plant) is compressed to
the desired pressure level by compressor. The same make-up hydrogen compressor serves Naphtha
Hydro treating unit (Unit 801) and Prime G+ unit (Unit 803) also. The remaining hydrogen
flowrate is compressed to the desired pressure in the compressor second stage and cooled down in a
second stage cooler. Then, hydrogen make-up is sent to Isomerization unit under flow control.
Hydrogen make-up also needs to be dried to remove water and CO/CO2 which are extremely
poisonous to the reactor catalyst. For this reason, hydrogen make-up gas is dried in the two dryers
that operate in series and in up flow direction. Then the dried hydrogen is mixed with the dried
naphtha. Both hydrocarbon feed and hydrogen make-up are under flow control linked to a ratio
controller.
Off Gas
Full vacuum with steam ejector followed by vacuum breaking with dry nitrogen
With nitrogen
With nitrogen or steam
H2 make-
up KO
Drum
H2
Dryers
Reaction
Section
Feed
Surge Drum
Feed
Dryers
Stab.
DIH
Scrubber
Chloride
Guard
Bed
Regen.
section

During the dryer regeneration period, only a single bed is used for drying. Piping flexibility is
provided to operate either bed in the lead or tail position, or as a single bed.
O REACTION SECTION
This combined two phase feed is first preheated in De-isohexanizer recycle/ Reactors feed
exchanger, then in first stage reactor feed/effluent exchanger, and then in hydrogenation reactor
feed/effluent exchanger.
Finally, it is heated to the required inlet temperature of the first isomerization reactor by MP steam
heater.
The feed enters in benzene hydrogenation reactor where the benzene is hydrogenated. The
hydrogenation reaction is highly exothermic. Reactor effluent leaves the benzene hydrogenation
reactor to be cooled down in exchanger before entering the first stage isomerization reactor.
C2Cl4 from chloriding agent injection drum is injected into 802-R-02 first stage isomerization
reactor effluent with pumps in order to maintain the chloride balance on the isomerization catalyst.
Inlet temperature of the first isomerization reactor is controlled by hydrogenation reactor feed /
effluent exchanger 802-E-04 bypass. The feed enters first stage isomerization reactor 802-R-02
where the isomerization reaction occurs. Isomerization reactions are slightly exothermic and reactor
effluent leaves the first isomerization reactor to be cooled down in exchanger 802-E-03 before
entering the second stage isomerization reactor 802-R-03. Inlet temperature of the second
isomerization reactor is controlled by first stage isomerization reactor feed / effluent exchanger
802-E-03 bypass. In this second reactor, the remaining isomerization reactions occur.
The reactors containing platinum catalyst, a small amount of chloride agent is injected continuously
to the 1st
stage isomerization reactor feed as a make-up for the catalyst chloride, which is lost to the
reactor effluent.
The three isomerization reactors (benzene hydrogenation, 1st
and 2nd
stage) are mixed phase, down-
flow reactors, with a single catalyst bed. The isomerization reactors are designed to operate in the
lead/tail position or in a single reactor configuration.
The reaction section pressure profile is fixed with pressure controller located on the reactor effluent
stream. The temperature profile in each reactor is monitored with multiple TI’s located across the
catalyst bed. The differential temperature between adjacent thermocouples is a measure of the
extent of reaction, while also indicating the reactive zone of the catalyst bed.
O DEISOHEXANIZER
Deisohexanizer (DIH), which has 82 trays, is fed on tray #30 with stabilizer bottom, which preheats
the DIH pumparound through DIH feed / pump around exchanger. Deisohexanizer recovers
isomerate product and recycles low octane methyl-pentanes and n-hexane to the reactors. This low
octane cut is drawn off the column to DIH recycle drum, on level control. Liquid from 802-V-06 is
pumped through recycle pumps. A part of this liquid, called DIH recycle, is recycled to the reactor
section after being cooled successively in deisohexanizer recycle/reactors feed exchangerand
recycle trim cooler.

Remaining liquid stream after being pumped through pump is preheated by the DIH feed in
exchanger, and is recycled to the DIH column, in order to reduce the heat load required for
reboiling the column.
Overhead vapor of the column is totally condensed through deisohexanizer air condenser and is
routed to deisohexanizer reflux drum. The De-iso-hexanizer reflux drum pressure is controlled with
the column overhead pressure controller, allowing pressurization of DIH reflux drum with a hot
bypass in case of pressure decrease. The liquid in the reflux drum is pumped through
deisohexanizer reflux pumps. Reflux is pumped back to the column whereas the distillate is cooled
down to 40°C by light isomerate cooler 802-E-11, before being sent to the light isomerate storage.
A small amount of the light isomerate is also used as regenerant for dryers (batch operation).
Deisohexanizer is re-boiled with MP steam re-boiler. Reboiler duty is under temperature control at
the sensitive tray of the column.
The bottom stream, being concentrated in C7+ and C6 Naphthenes, is pumped by deisohexanizer
bottom pumps, and cooled down by heavy isomerate cooler 802-E-13 and routed to heavy
isomerate storage. Piping is foreseen to enable blending light and heavy isomerates before sending
to storage.
O SCRUBBER SECTION
As the gas from the stabilizer reflux drum overheads contains HCl, it must be caustic treated and
water washed before being released to fuel gas system. This off-gas enters in the bottom of the
column through the caustic hold-up and is caustic washed in the bottom packed bed.
Then off-gas, saturated with caustic, is washed in a second packed bed with steam condensate,
before being routed to fuel gas system under pressure control. In the caustic solution, the NaOH
composition varies from 10% wt. to 2% wt. as it reacts with HCl to produce NaCl. The caustic is
re-circulated by pump. It is maintained at 50°C through the caustic recycle heater in order to keep
the caustic a few degrees warmer than the feed gas to avoid potential foaming problems due to any
hydrocarbon condensation.
Both scrubber sections are packed with carbon raschig rings. The caustic inventory requirement is
stored in the column bottom section, and the feed gas is bubbled through this caustic inventory. A
portion of the circulating caustic is sprayed onto the column walls below the caustic wash packed
section to avoid any wet hydrogen chloride corrosion in this part of the scrubber. All vapor lines in
this section are electrically traced in order to avoid water condensation and therefore HCl corrosion.
The caustic inventory is drained through caustic circulation pump discharge, once the concentration
of circulating caustic decreases to approximately 2% wt, and then the column bottom is filled up
using fresh 10% wt caustic stored in fresh caustic drum and sent to the tower via fresh caustic
pumps. The spent caustic is routed to the spent caustic system.
The gas leaving the caustic wash section is again washed with water in the top packed section, to
remove any entrained caustic. Water is collected in the chimney tray below the water wash packed
section, and is circulated using pumps. Water losses to the vent gas leaving the scrubber are made-
up periodically by fresh demineralized water addition (via water condensate injection package).
Once every several days the water inventory is drained and replaced.

b. NHDT
• PURPOSE OF THE NHDT UNIT:
The purpose of the Naphtha Hydrodesulphurization unit is to produce clean hydro treated feed
stocks to feed the Isomerization unit. These feed stocks must be sufficiently low in contaminants
such as sulphur, nitrogen, water, halogens, di-olefins, olefins, arsenic, mercury and other metals so
as not to affect the downstream unit. A sulphur guard bed is installed on the stripper bottom stream
to protect downstream units from dissolved H2S being carried through in case of stripper upsets.
• FEED:
The unit feed is: CRU’s light naphtha, Light Straight Run Naphtha, Coker Naphtha and Heart cut
Naphtha from Prime G+ Unit.
• PRODUCT:
The unit is designed to produce “Sulphur-free” stabilized naphtha containing less than 0.5 wt. ppm
sulphur and 0.5 wt. ppm nitrogen.
These naphtha contains level of contaminants which would be detrimental to the Isomerization
catalysts and therefore pre-treatment is necessary.
This process developed and licensed by Axens involves two subsequent operations:
A. Treatment of the naphtha:
first, in an adiabatic reactor over a fixed bimetallic catalyst bed within a hydrogen environment at
low temperature (160°C-190°C) to hydrogenate the di-olefins followed by the treatment in second
reactor at moderately high temperature in the range of 260-290°C to promote the chemical
reactions (Reaction Section) to finalize the olefin hydrogenation and to remove sulphur and
nitrogen.
B. Stripping of the raw de-sulphurized product:
Stripping of the raw de-sulphurized product to remove light ends, gaseous products including H2S
and water (Stripper Section). Splitting of the treated Naphtha into light, the feed for ISOM unit and
heavy naphtha for naphtha pool. The high performances of the ISOM unit depend widely on the
efficiency of the NHDT operation.
• DESIGN BASIS:
o NHDT CAPACITY: 22875 kg/hr. (378 MTPD), (183000 MTPA)
o TURN DOWN CAPACITY (Min. T’put): 50 %
o CAPACITY BASIS: 8000 hr.

• GENERAL INTRODUCTION:
The NHDT section includes the following sections
➢ Feed section
➢ Reaction section
➢ Recycle gas compression system
➢ Stripper
➢ Splitter
NHDT BLOCK FLOW DIAGRAM
FEED
SECTION
R-01 R-02
SEPERATORC-01
Stripped
gas
C-02
H2
COKER NAPHTHA
LS/HS SRN
HEART CUT
CRU LIGHT
NAPHTHA
LIGHT
NAPHTHA TO
ISOM
HEAVY
NAPHTHA TO
POOL
RGC
STRIPPER
SPLITTER
ΔP=2.5
ΔT=7
ΔP=5.0
ΔT=42
V06
SULPHUR GUARD
Di-olefin to olefin conversion
Olefin hydrogenation,
desulphurization
35
➢ BRIEF PROCESS FLOW DESCRIPTION (NORMAL OPERATION):
The Coker naphtha cut enters the unit at battery limit. It is routed to Coker naphtha feed drum V-07
through Coker feed filter package G01.Light naphtha from CRU is mixed with heart cut naphtha
and heavy LCN from Prime G+ unit.
The mixture is directed to the NHDT feed surge drum V-01.The mixture of Coker naphtha feed,
which is pumped by Coker naphtha feed pumps P-05A/B, and naphtha feed, which is pumped by
NHDT feed pumps P-01A/B is routed under cascade flow control with V-01 level through feed
mixer M-03 to the reaction circuit. It is mixed with a part of make- up hydrogen coming from the
ISOM unit before entering to reaction section. The other part of H2 coming from ISOM is injected
at the outlet of first reactor to limit the rate of vaporization at the inlet of first reactor. The feed is
also diluted with a part of liquid (dilution flow) coming from NHDT separator drum V-02 to limit
T in the second reactor.
o REACTION SECTION (R-01 & R-02):
Hydro treating is performed in two steps: the first step consists in transformation of di-olefins in
olefins in rector R-01 and the second one corresponds to olefins hydrogenation, de-sulfuration and
de-nitrification of the whole feedstock in reactor R-02.

Naphtha feed and make up H2 are preheated in heat exchangers against reactor R-02 effluent, and
in MHP steam heater E-12. Then they are injected into 1st
Hydro treating reactor R-01. The reactor
inlet temperature is controlled with a TC-FC cascade on the steam condensate of MHP steam
heater. The feed inlet temperature at E-12 is controlled with a bypass. The reactor R-01 is filled
with HR-845. The di-olefins and a part of the olefins present in the feed are hydrogenated at low
temperature in the liquid phase and with a moderate temperature increase.
The effluent is then mixed with the recycle gas from K-01 A/B and the other part of make- up
hydrogen, heated in heat exchangers and against reactor R-02 effluent and in the furnace. Then it is
injected into 2nd
hydro-treater reactor R-02. This reactor feed temperature is controlled by
regulating fuel flow rate to the furnace burners, this temperature varies from 260 to 290 degree
Celsius depending on the cycle position.
The temperature increase in R-02 is mainly due to olefin hydrogenation. A liquid quench is
required at the outlet of first bed to maintain the temperature at 300o
C or 340o
C at the quench point,
depending on the position in the cycle. R-02 effluent is cooled down in exchangers, and in air
cooler / trim cooler, before being fed to the separator drum.
The major part of the vapour phase is used as recycle and sent to recycle compressor K-01A/B. A
small part is purged to the FG system. This purge gas is used to control the reaction section
pressure during start up and to increase the recycle gas purity during normal operation. During
normal operation, the reaction section pressure is controlled by hydrogen make up flow and the
purge gas of separator drum under being under flow control.
Prior to the air condenser, water is injected to dissolve any chloride, sulphide and ammonium salts,
which precipitate at low temperature. Water is recovered in the boot of separator drum. The main
part is recycled by water circulation pumps and mixed with steam condensate water make up, and
the other part is routed under level control to SRU.
The main part of separated hydrocarbon liquid is pumped through NHDT reactor quench pumps
under flow control and used as dilution (normal operation) and as liquid quench in case of
turndown or olefins content upset. The other part is routed under flow control with level reset to the
stripping section.
O STRIPPER SECTION (C-1):
In the, stripping section, the hydro treated naphtha is preheated in splitter fee/bottom exchanger and
then in stripper feed bottom exchanger to enter the stripper on tray #11 and this column has 36
trays. This column is re-boiled by MHP steam heater re-boiler.
Overheads from the column are partially condensed in stripper air condenser and then in stripper
trim condenser. The stream coming from the trim condenser is sent into the stripper reflux drum.
The fuel gas from is sent to the FG system under pressure control. The liquid is pumped by stripper
reflux pumps under flow control with level reset to as reflux.
Bottom from the stripper undergo heat exchange in stripper feed/bottom exchanger. Stripper
bottoms feed under flow control with stripper level reset, the NHDT splitter on tray#15 and this
column has 42 trays. The stripper bottom goes to splitter with stripper pressure.
O SPLITTER SECTION: C-2

The function of the NHDT splitter is to split the full range naphtha into light naphtha feed to ISOM
unit and a heavy naphtha to naphtha pool. This column is re-boiled by MP steam heater re-boiler.
Overheads from the column are totally condensed in the splitter air condenser to enter the splitter
reflux drum. The splitter reflux drum pressure is controlled with the column overhead pressure
controller, allowing pressurization of splitter reflux drum with a hot bypass in case of pressure
decrease. The condensed liquid collected in is pumped back by splitter reflux pump and a part is
sent to the column as reflux under flow control, other part of this cooled down to 40 degree Celsius
in light naphtha cooler and sent under flow control with level reset to ISOM unit. The splitter
bottoms i.e. heavy naphtha fraction is pumped using the splitter bottom pump, and is cooled down
in splitter feed/bottom exchanger and in heavy naphtha trim cooler.
c. G+ UNIT
• PURPOSE OF THE PRIME G+ UNIT:
The purpose of the Prime G+ unit is to achieve a deep hydrodesulphurization of Light Cracked
Naphtha (LCN) and Heavy Cracked Naphtha (HCN) coming from an RFCC. The majority of sulfur
in the typical refinery gasoline pool is coming from the RFCC gasoline. This product is also
characterized by high olefin content.
Conventional desulfurization technology results in significant loss in octane number due to
saturation of high-octane olefins to low octane paraffin. At high levels of desulfurization, the
octane number (RON+MON)/2 can be reduced by 5 to 10 points, which is unacceptable. The
objective of the Prime-G+ process is to remove sulfur while avoiding substantial loss in octane
number.
• FEED:
The LCN gasoline feed coming from the RFCC Unit is supplied at battery limit of the SHU section.
The HCN gasoline feed from RFCC Unit is sent to the HDS section and co-processed with the
SHU Splitter bottoms.
• PRODUCT:
The main products of Prime G+ unit are LCN , HCN and Desulfurized HCN.
In the SHU reactor, diolefins are hydrotreated and light sulfur compounds are converted into
heavier sulfur species. The reactors effluent is sent to a splitter column where it is split into three
fractions: light cracked naphtha (LCN), Heart cut and heavy cracked naphtha (HCN).
In the HDS reactor, the desulphurization of the gasoline takes place. Despite the high degree of
desulphurization, olefin saturation is very limited and no aromatic hydrogenation occurs. It is
followed by a stabilization column to remove the light ends, H2S and water resulting from the
reaction and from dissolved components in hydrogen make-up gas.
• DESIGN BASIS:
o UNIT CAPACITY:322,000 MTPA (Metric Tons Per Annum) of Light Cracked
Naphta (LCN) and 81,000 MTPA of Heavy Cracked Naphta (HCN)

o TURN DOWN CAPACITY (Min. T’put): 50 %
o ON STREAM HOUR PER ANNUM: 8000
.
❖ Process Flow Diagram
➢ BRIEF PROCESS FLOW DESCRIPTION (NORMAL OPERATION):
O SPLITTER
The SHU reactor effluent is separated into three fractions in the splitter 803-C-01: LCN, Heart cut
(for high Benzene content) and HCN. The LCN stream has very low sulfur content and does not
require an extractive sweetening to further lower the sulfur content.
Stabilization of the LCN (removal of H2 excess through the vent gas) is achieved by taking the
LCN stream as a side draw in the column.
The LCN is a final product and is sent directly to MS pool while the splitter bottoms is fed to the
HDS reactor 803-R-02 for hydrodesulphurization. Heart Cut is also sent directly to NHDT (Unit
801) prior to Isomerisation and/or to MS gasoline pool.
LCN
H2 Makeup
SHU
FCC Gasoline S
T
A
B
I
L
I
Z
E
R
S
P
L
I
T
T
E
R
HDS
LCN
HDN Prod.
Sweet Purge
Sour Purge
Heart
Cut
Recycle
gas
Amine
HCN

In case LCN being routed to an atmospheric storage (outside battery limit), the LCN stream needs
to be blended with a heavier gasoline stream due to the high RVP of the LCN stream.
The gasoline contains mercaptans, thiophene, alkyl thiophenes and benzothiophene from light
species (Mercaptans) to heavy species (Benzothiophene), As mercaptans and light sulfides are
converted into heavier sulfur species in the SHU reactors, thiophene becomes the first significant
sulfur component to be entrained in the LCN product.
In general, olefins tend to concentrate in the lighter portion of the gasoline. Splitter operation is
important to achieve a good balance between the sulfur and olefin concentrations present in the
Heart Cut that are sent to NHDT unit and in the HCN that are sent to the HDS Reaction Section.
The optimum amount of LCN depends on the feed sulfur, feed thiophene, C5/C6 amount and the
product sulfur specification.
The LCN draw rate and the sulfur content are controlled indirectly by a temperature controller
located on the Splitter column a few trays below the LCN draw tray. The on-line LCN sulfur
analyzer helps to control the amount of LCN draw.
A lower LCN withdrawal rate from the Splitter will produce a Heart Cut with higher olefin
concentrations and hence potentially higher octane losses. Alternatively, a higher LCN withdrawal
rate from the Splitter will produce an Heart Cut with lower olefin concentrations but with increased
sulfur levels in the LCN. As the LCN and Heart cut rate in the Splitter is increased, the severity of
the HDS Reaction Section has to be increased to offset the amount of sulfur that has left with the
LCN and Heart Cut.
O HDS REACTOR HYDRODESULFURIZATION
The Prime G+ reaction section features the use of a highly selective Co-Mo catalyst (HR-806) in
the HDS Reactor for the desulfurization reaction with practically no additional olefin saturation.
The catalyst is commercially proven and is regenerable. This results in a modest catalytic
processing cost.
The Prime G+ reaction section employs fixed bed reactor technology. This reactor allows for easy
loading / unloading of the catalyst. Catalyst cycles in excess of three years have been commercially
demonstrated when processing FCC naphtha with the combination of selective hydrogenation /
selective HDS reactor.
The reaction is carried out between the vaporized gasoline and a hydrogen rich gas over a
hydrodesulfurization catalyst bed.
O AMINE ABSORBER AND RECYCLE COMPRESSOR SECTION
In the Amine Absorber, the recycle gas is in contact with a 30% wt. MDEA lean amine solution,
which is pumped by Lean Amine Feed Pumps, and sent under flow control to the Amine Absorber.
The lean amine should be at least, 8-10 deg. C higher in temperature than the vapor entering the
Amine Absorber, to prevent any foaming. Therefore, Lean Amine is heated in Lean Amine
Preheater. Rich Amine is withdrawn under level control from the bottom of the Amine Absorber.
The sweet gas leaving the Amine Absorber is routed to the Recycle Gas Compressor KO Drum.

The recycle gas is compressed via the reciprocating Recycle Gas Compressors, and the HDS
hydrogen make-up is then combined with it. HDS Hydrogen make-up is coming either from HGU
(Hydrogen plant) or CRU (Unit 03), under flow control reset by pressure control of HDS Separator.
o HDS STABILIZER SECTION
The liquid flows from the HDS Separator and potentially from Amine Absorber K.O. Drum, and
feeds the Stabilizer. The feed to the Stabilizer is preheated by heat exchanging heat with the
stabilizer bottoms in the Stabilizer Feed / Bottoms Exchangers. The stabilizer has 27 trays and the
feed enters the column at tray 8.
Corrosion inhibitor is injected in the stabilizer overhead to minimize equipment corrosion. The
stabilizer overhead is partially condensed in the HDS Stabilizer Overhead Air Condenser, 803-AC-
05 and in the HDS Stabilizer Overhead Trim Cooler,. Vapor, hydrocarbons and water are separated
in the HDS Stabilizer Reflux Drum.
The decanted water is sent under level control to the sour water treatment. The liquid hydrocarbon
phase is pumped by the HDS Stabilizer Reflux Pumps,, and sent back to the top of the column as
reflux under flow control in cascade with the Stabilizer reflux drum level control.
The Stabilizer is re-boiled with de-superheated High Pressure steam (HS) in thermo-siphon re-
boiler. Heat input is controlled via flow control of HS steam.
The stabilizer bottoms product is pumped, under flow control reset by stabilizer bottoms level
control, by HDS stabilizer bottom pumps and cooled in the Stabilizer Feed / Bottom Exchangers.
Then it is further cooled down to the battery limits temperature in HCN Product Air Cooler and
HCN Product Trim Cooler.
8. CATALYTIC REFORMING UNIT (CRU)
To get motor spirit of low lead and high octane number, this unit was setup in Barauni Refinery in
1990.
• THE PLANT IS HAVING FOLLOWING FACILITIES
1. Naphtha splitter unit
2. Naphtha Hydro-treater Unit
3. Catalytic reformer unit
4. Feed and hydro-treater Naphtha storage facility
5. Circulating water facility
6. Compressed air and PSA system
7. Hydrogen storage and unloading facility
8. Flare system
The purpose of reformer is to enhance the octane number by changing the hydrocarbon structure in
the presence of catalyst and hydrogen. It is not advantageous to operate reformer with lighter
hydrocarbons. Splitter was required to get suitable catalyst, but impurities/water act as a catalyst-
poison, so we need hydro-treater to remove impurities and water.
• GENERAL PROCESS DESCRIPTION

The feed is obtained from AVU in the form of E-1 & E-2 gasoline. It is fed to Naphtha splitter unit
where lighter and heavier ends get separated in presence of Pt-Rh impinged on Al bed. H2 gas is
fed to maintain flow and pressure. The bottom product called heavy naphtha is sent to Hydro-
treater unit (HTU) where its organic impurities like sulfur,N2,O2etc are removed and stripped off
from top of column in presence of alumina bed impregnated with molybdenum oxide. After this it
is sent to stripper section where H2S is removed.
Then it is sent to CRU (Catalytic reforming unit) where we obtain unleaded petrol or reformate.
• PLANT DESCRIPTION
a. NAPHTHA SPLITTER UNIT
IBP-140°C cut naphtha from storage is fed to splitter column under flow control by of site pump at
tray no.14. The feed is heated up to 95°C in splitter feed exchanger against splitter bottom stream
before it enters the column.
The overhead vapours are totally condensed in air condensers. On part of liquid collected is sent
with the help of pump as top reflux back to the column to maintain top temperature. The pressure
of splitter is controlled at reflux drum by passing a part of hot column overhead vapours around the
condenser or releasing the reflux vapours to flare through a split range controller. The splitter
bottom product which constitutes 70-140°C cut naphtha is pumped to splitter feed exchanger by
hydro treater feed pump. The bottom product thus obtained is divided into two parts. One part goes
to the hydro treater unit at temperature of 65°C and other part is sent to storage under column level
control after being cooled in splitter bottom column.
The heat necessary for splitter re-boiling is supplied by splitter re-boiler furnace and desired
temperature maintained by controlling fuel firing. Splitter re-boiler pumps provide the circulation
through re-boiler.
b. HYDRO TREATER UNIT
The naphtha from NSU is fed to HTU by a pump. The feed flow is controlled by flow control
valve. The feed then mixed with rich Hydrogen gas from HP separator of reformer. Both the liquid
naphtha and hydrogen gas are pre-heated in a series of exchangers. Then mixture is heated up to
reaction temperature in furnace and fed to reactor. The furnace is four pass having three burners
fired from bottom. The desulfurization and hydro treating reaction takes place in reactor at almost
constant temperature since heat of reaction is quite negligible. The reactor is provided with the
facility of steam and air for regeneration of catalyst.
The effluent of reactor, after heat exchanging with feed goes to air cooler. The air cooler fans pitch
is variable. After air cooler the effluent is cooled in a trim cooler. The product is collected in a
separator vessel. Sour water is drained from the separator drum boot manually. The separator drum
pressure is maintained by routing the gas to HGU compressor fully and any excess gas can be
routed to FG system.
The separator liquid is pumped and cascaded to stripper feed exchanger. The stripper column
consists of 28 nos. of valve trays .feed coming from exchanger enters at 9th
tray from two sides.
The overhead vapours re-cooled down in air condenser and collected in stripper reflux drum. The
fan load can be adjusted. The condensed hydrocarbons are returned to column top by pump as
reflux to maintain the top temperature. The water accumulated in the boot is sent for disposal as

sour water. Stripper bottom product exchanged heat with stripper feed and then sent to reformer as
hot feed. The excess hydro treated naphtha is sent to storage after being cooled in exchanger.
c. CATALYTIC REFORMING UNIT
Hydro treated naphtha from hydro treater unit is pumped to required pressure and mixed with
recycle gas from the recycle gas compressor. The mixed feed is pre heated in the feed effluent
exchanger. Then the mixture is brought up to the reaction temperature by heating in the pre-heater
and then fed to 1st
reactor.
As the reaction is endothermic, the temperature drops, so the 1st
reactor effluent is heated in the
first inter heater prior to be sent to the 2nd
reactor. In the same way 2nd reactor effluents are heated
in the second inter heater prior to be sent to the third reactor. The effluent from the last reactor is
split into two streams and sends for heat recovery is flashed in the reformer separator.
Vapour and liquid phase are separated in separator. Part of the gas phase constitutes hydrogen
recycle gas to the reactor circulated by recycle gas compressor. The hydrogen rich gas compressor
compresses remaining amount, corresponding to the amount of gas produced.
The separator liquid is sent by reformer separator bottom pumps for reciprocating with the gas
compressed. The hot flue gas from all the three reformer furnaces are combined and sent to steam
generation system for waste heat recovery to produce MP steam.
The liquid from the vessel is drawn off and mixed with stabilizer vapour distillate. The combined
stream is cooled in LPG absorber feed cooler and flashed in LPG absorber. Off gas is sent under
pressure control to fuel gas system. Stabilizer feed pump pumps the liquid from vessel. After pre
heating in stabilizer feed exchanger the mixture is fed to the stabilizer at tray no.13. Stabilizer
overhead vapours is partially condensed in stabilizer condenser and flashed in stabilizer reflux
drum. The vapour phase is sent to LPG absorber for C3 and C4 recovery. A part of condensed liquid
is pumped as reflux to the column by stabilizer reflux pump under the flow control and the balance
is sent to LPG recovery unit under level control of reflux drum.
❖ Flow Diagram of CRU

9. COKER - A &B
Delayed Coking is a thermal cracking process used in petroleum refineries to upgrade and convert
petroleum residuum (bottoms from Atmospheric and Vacuum distillation of crude oil) into liquid
and gas product streams leaving behind a solid concentrated carbon material, petroleum coke.
Delayed Cokers can convert even the heaviest residues to lighter distillates and provides much
needed flexibility to the refiners to process a wide variety of crude oil. It, therefore, is the most
widely used process all over the world.
The goal for delayed Coker operation is to maximize the yield of clean distillates and minimize the
yield of coke. Delayed coking technology is preferred for upgrading heavier residues due to its
inherent flexibility to handle even the heaviest residues while producing clean liquid products. The
main products of delayed Coker operation is off-gas (from which LPG is recovered), naphtha, Light
Gas Oil (LGO) and Heavy Gas Oil (HGO). LGO is sent to Hydrotreater for production of Gas Oil
and HGO to refinery FO Pool/ RFCC feedstock. The yield slate for a Delayed Coker can be varied
to meet a refiner’s objective through the selection of operating parameters.
Three operating parameters govern the yield pattern and product quality of Delayed Coker
➢ Temperature
➢ Pressure
➢ Recycle Ratio (RR)
Increasing coking temperature decreases coke production and increases liquid yield and gas oil
endpoint. However, temperature can be adjusted only by a narrow range to control volatilities left
in coke. Increasing pressure and/or Recycle Ratio (RR) increases gas and coke make and decreases
liquid yield and gas oil endpoint. RR can be varied from 0% to 120%. Recycle Ratio is defined as –
(Composite feed to Coker Heater)/ (Primary feed to Fractionator bottom).
• THEORY OF PROCESS:
Delayed coking is a thermal conversion process by which a residual stock or crudes, “bottom of the
barrel” material is upgraded to more valuable distillates. This process also produces a solid
carbonaceous matter called coke. Petroleum coke mainly formed by two different mechanisms–
➢ High molecular weight compounds, such as asphaltenes and resins, tend to dealkylate to
straight chain compounds and CH2 groups when subjected to high temperature. In this
process a residue of carbon (i.e coke) is left behind.
➢ Dehydrogenation of heavy oils followed by polymerization and condensation of free
radicals from high molecular weight compounds (mainly aromatic hydrocarbon) lead to
formation of coke.
There are three types of chemical reaction processes which occur continuously without any distinct
steps in the coking process:
➢ Dehydrogenation – The initial reaction in carbonization involves the loss of hydrogen
atom from an aromatic hydrocarbon and formation of aromatic free radical intermediate.
➢ Rearrangement Reactions – Thermal rearrangement usually leads to formation of
more stabilized aromatic ring system which forms building block of graphite growth.

➢ Polymerization of aromatic radicals – Aromatic free radicals polymerized in the
process of coking reaction. This process is initiated in the liquid phase and continued in
different steps.
• FEEDSTOCK:
Feedstock can have a considerable amount of metal (Ni + V), Sulphur, Resins and Asphaltenes.
Most typical feedstock is Vacuum Residue. It can also process refinery slop oil/sludge.
Atmospheric residue is also occasionally processed.
• DELAYED COKING PROCESS:
The feedstock is pumped by Coker feed pumps from Coker feed tanks located outside the Battery
limit, to the feed surge drum. Provision to receive hot short residue and remaining streams from the
unit, in the feed surge drum is kept.
The feed from the feed surge drum is pumped to Main Fractionator, under its level control, by
feed pumps. The feed is preheated in preheat exchangers using Kerosene product, Light Diesel Oil
(LDO) product and LDO Circulating Reflux (CR) respectively. The temperature at the outlet of the
preheat train is about 240⁰C.
The preheated fresh feed is fed to the Main Fractionator bottom surge section. The mixed stream
of feed and recycle in the weight ratio of 100:70 is fed to the two Coker furnaces by their respective
fractionators bottom pumps.
The fractionators bottom material (fresh feed + recycle) at temperature of 315-320⁰C is fed to the
two passes of each Coker Furnaces. Turbulising water is added to each pass after the flow control
valves. This water vaporizes and the effective volumetric flow inside the tube increases so as to
move the adherent HC liquid film in the tube walls faster. This minimizes coke formation and
increases heater run length.
The outlet of the convection section of the furnace goes to the top section of radiation zone and
finally comes out from the bottom most tube of radiation section. The fuel firing in the heater is
controlled by its outlet temperature. Either fuel gas or fuel oil can be selected for control via
selector switch. Fuel oil is atomized by Moderate Pressure (MP) steam under differential pressure
control.
Each furnace has two coke chambers (a cylindrical, insulated vessel). The feed inlet to the coke
chambers is from the bottom. The heated charge stock enters the bottom of the coke chamber which
is under the normal coking mode through the 4 way switch valves. The vapors from the coke
chambers are led from the top vapor outlet line to the quench column.
Steam and water connections have been provided at the inlet of the coke chamber for steam
heating, pressure testing, steam stripping and water cooling in the coke chamber during routine
operations. Anti-foam injection facilities are provided at the top of the coke chamber. It helps in
preventing/minimizing the boil over inside the coke chamber.
The flow from the furnace is alternated between the two coke chambers, to allow removal of coke
from one drum while the other is on-steam. Coking reaction continues to occur in the coke chamber
and the sensible heat of the incoming transfer fluid from the furnace supplies the required reaction

heat for coking in the coke chambers. Thus the un-vaporized portion of the furnace effluent settles
out in the coke chamber where the combined effect of retention time and temperature causes the
formation of coke.
The vapors pass on from the top of the chamber to the downstream quench column. LDO quench
has been provided immediately at the vapor outlet line of the coke chamber to quench the vapors
and minimize the coking and fouling in the overhead vapor line. The bottom outlet line has two
streams, routed to respective circuits.
Delayed Coker drum cycle length varies from unit to unit. However, typically it is kept within 16 to
24 hours.
• PRODUCTS OF DELAYED COKING:
1. Delayed Coker produces desirable liquid products (naphtha and gas oil) and by-products and by-
products Coker gas and solid coke.
2. Coker off-gas goes to the gas plant where C3 and C4 are recovered as LPG and the lighter end
can be used as fuel gas in the refinery.
3. Naphtha contains high olefin content and this stream is usually sent to hydrotreater for
stabilization.
4. Light Coker Gas Oil (LCGO) is sent to diesel hydrotreater for production of diesel. Typical end
point of this stream is around point of this stream is around 370 °C.

5. Heavy Coker Gas Oil (HCGO) is sent to FCC/ RFCC for production of valuable distillate
products. Typical end point of this stream is around s around 538 °C.
10. LPG RECOVERY UNIT (LRU)
Recovery of heavy hydrocarbons (C3+) or LPG from refinery purge and fuel gas stream is more
profitable than sending these high value components to fuel. So LPG Recovery Unit is introduced
in the refinery. LPG components are produced in many refinery operations. Traditionally
absorption and cryogenic systems are used in LPG Recovery Unit.
• THEORY OF PROCESS:
The off gases from the AVUs and Coker Unit contain C1 - C4 and some amount of sulphur. The
critical pressure of C3 and C4 gases is 10-12 kg/cm2. These gases when liquefied under pressure
are called Liquefied Petroleum Gases. It is a mixture of propane(30-40%) and butane(60-
70%).Propane and Butane can be easily liquefied and stored in cylinders .It is of high calorific
value(45,500 kJ/kg). LPG Recovery Unit recovers the LPG present in the off gases of AVUs and
Coker Unit and this is sent to LPG Treatment Unit (LTU).
• FEEDSTOCK:
Off gases from AVUs and the Coker Unit is the feed of LPG Recovery Unit.
• PROCESS:
The off gas from AVUs and Cokers are sent to LPG Recovery Unit. These gases are stored in a
knock out drum (V1) at a pressure of about 1.7-2.2 kg/cm2. Liquid and gas get separated in this
knock out drum and that liquid free gas is sent to a compressor through a turbine. This is called the
first stage suction. Gases leave the 1st stage compression at a pressure 6 kg/cm2. Then it is sent to
an intercooler (E1) (water cooler). After cooling, the gases are again stored in a knock out drum
(V2) where the liquid is separated. The gases from the knock out drum are sent for 2nd stage
compression through a turbine. The final discharge after the second stage compression is at a
pressure of 13 kg/cm2. During compression, spill back method is used to maintain a constant gas
flow in the compressor. The gases leaving the 2nd stage compression is sent to another knock out
drum (V3) via a water cooler. In V3, it is separated into three parts- the gases at the top, the
condensed liquid at the middle and the phenolic water at the bottom.
From the knock out drum V3, the gases are sent to absorber column (C1) column. Kerosene and
naphtha are also added in C1. The top gases consisting of C1, C2 and sulphur are sent to a vessel
from where it is sent to Amine Treatment Unit (ATU). Sulphur gets separated in ATU and the
gases C1, C2 are sent to Refinery Gas Header (RGH). The bottom product is sent to stripping
column, C2.
The condensed liquid present in the middle of knock out drum V3 is also sent to column C2 along
with the bottom residue of C1. C2 column is a stripping column where MP steam is used as the
stripping medium. The stripped out gases coming out from column C2 consists of C1,C2 and some
amount of C3. The residue of C2 column is sent to column C3.
Column C3 is the Debutanizer column. The operating pressure of this column is 10.2-11 kg/cm2.
The top gas from this column is LPG which is sent to LPG Treatment Unit (LTU). The bottom
product of this column is naphtha which is divided into two parts, one is sent to column C1 and

another is sent to MSQ. The bottom product of knock out drum i.e., phenolic water is sent to
Sulphur Recovery Unit (SRU).
LPG TREATMENT UNIT (LTU)
LPG produced in different units must be treated well to remove all the impurities. In LPG
Treatment Unit LPG is treated with amine and then passed through a sand filter to get the sellable
product.
• FEEDSTOCK:
The LPG from LRU, AVUs and RFCCU is received in LPG Treatment Unit.
• PROCESS:
The LPG gas coming from different units is stored in a vessel. The gases are then sent to a column
through a heat exchanger. Amine is added in this column at the top and middle of the column. This
is sent to a settler where amine is separated. The LPG is sent to a heat exchanger (LPG
cooler).After that LPG is passed through a Sand Filter and then it is sent to storage.
11. BIBLIOGRAPHY
• BOOK:
➢ Control room operating manual of IOCL.
• WEBSITES:
➢ www.iocl.com
➢ www.wikipedia.org
➢ www.google.com/images

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