This reports gives an overview of different plants of production department, Indian Oil Corporation Ltd,Barauni Refinery

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Indian Oil
INDIAN OIL CORPORATION LIMITED
(An ISO 9002:14001 Certified Company)
BARAUNI REFINERYBARAUNI REFINERYBARAUNI REFINERYBARAUNI REFINERY
Inharmony with natureIn harmony with natureIn harmony with natureIn harmony with nature
INDUSTRIAL TRAINING REPORT
(From May 05, 2014 to June 30, 2014)
Submitted By:
Mukul Kumar
Roll- 11CH10026
Department Of Chemical Engineering
IIT Kharagpur

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ACKNOWLEDGEMENTACKNOWLEDGEMENTACKNOWLEDGEMENTACKNOWLEDGEMENT
It’s a great pleasure for being part of INDIAN OIL CORPORATION LIMITED which
is the world’s 83rd largest public corporation according to the fortune global 500 list in
the year 2012, and largest public corporation in India when ranked by revenue.
This acknowledgement is a way by which I’m getting the opportunity to show the
deep sense of gratitude and obligation to all the people who have provided me with
inspiration and guidance during the preparation of the training report.
The special thanks to Mr. K.K Majumdar CM (MS, T&D), Mr. Kalyan Bagchi DM
(T&D), Mr. A.B Minz DM (T&D) and Ms. Nilu Rani (O.A., T&D) for the supervision
and support they have given truly helped in the progression and smoothness of the
vocational training.
My grateful thanks also go to Mr. S.S. Tiwary(Fire & Safety), Mr. R.P. Paswan
(DPNM,MSQ), Mr. A.K. Mishra (AVU-2),Mr. Arjun Singh(AVU-3),Mr. S.M.
Gautam(CRU), Mr. Mithilesh Prasad(RFCCU), Mr. S.P. Singh (DHDT) and Mr. P.
Singh (SRU) for big contribution and hard work from them during my eight week
training.
I would like to thank the technicians for helping me during the training and for
shedding light on the practical aspects of engineering in Barauni Refinery.
Last but not the least I would like to thanks my friends and staff of Barauni Refinery
for their cooperation throughout the training.

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ABOUT THE COMPANY
INDIAN OIL CORPORATION LIMITEDINDIAN OIL CORPORATION LIMITEDINDIAN OIL CORPORATION LIMITEDINDIAN OIL CORPORATION LIMITED
Indian Oil Corporation Limited, or IndianOil, is an Indian state-owned oil and gas
corporation with its headquarters in New Delhi. It is the world's 83rd largest corporation,
according to the global fortune 500 list of year 2012, and the largest public corporation in
India when ranked by revenue.
Indian Oil and its subsidiaries account for a 49% share in the petroleum products market,
31% share in refining capacity and 67% downstream sector pipelines capacity in India.
The Indian Oil Group of companies owns and operates 10 of India's 22 refineries with a
combined refining capacity of 65.7 million metric tonnes per year. It is one of the seven
Maharatna status companies of India.
Indian Oil is Public Sector undertaken (PSU) company registered under the companies
act 1956 and is managed by the Board of Directors who are appointed by the President of
India. Indian Oil owns and operates seven of the countries’ fourteen refineries which are
as follows:
UNIT CAPACITY
1. Barauni Refinery 06 .00 MMTPA.
2. Panipat Refinery 12.00 MMTPA.
3. Mathura Refinery 08.00 MMTPA.
4. Koyali Refinery 13.70 MMTPA
5. Guwahati Refinery 01.00 MMTPA.
6. Haldia Refinery 09.60 MMTPA.
7. Digboi Refinery 00.65 MMTPA
*MMTPA = Million Metric Tons per Annum

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CONTENTS
CHAPTERCHAPTERCHAPTERCHAPTER PAGEPAGEPAGEPAGE
INTRODUCTION 5
FIRE AND SAFETY TRAINING 10
ATMOSPHERIC AND VACCUM UNIT -I/II/III 12
CATALYTIC REFORMING UNIT (CRU) 18
MOTOR SPIRIT QUALITY UNIT (MSQ) 23
RESID FLUIDIZED CATALYTIC CRACKING UNIT
(RFCCU)
31
DIESEL HYDROTREATING UNIT (DHDT) 39
SULPHUR RECOVERING UNIT (SRU) 42
HYDROGEN GENERATION UNIT (HGU) 46
OFFSITE FACILITIES AND ITS MANAGEMENT 50

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IOCL BARAUNI REFINERYIOCL BARAUNI REFINERYIOCL BARAUNI REFINERYIOCL BARAUNI REFINERY –––– THE JEWEL OF BIHARTHE JEWEL OF BIHARTHE JEWEL OF BIHARTHE JEWEL OF BIHAR
Barauni Refinery is the second public sector refinery of Indian Oil Corporation Ltd.
which was setup under the collaboration of erstwhile USSR and limited
participation of Romania. It is located near the northern bank of the river Ganga at
Begusarai District town of Bihar state. It is among the few refineries in the world to
have scored the coveted ISO 9002 certification.
The construction activity of the refinery commenced in 1962 and formally
inaugurated by Prof. Humayun Kabir, the then union minister of petroleum &
chemicals, govt. of India on January 15, 1965.
The Barauni refinery currently takes its crude oil from foreign countries through
Barauni-Haldia crude pipeline (BHCPL) from Paradip on the east coast. The
capacity was subsequently enhanced to 6 Million Metric Tonnes Per Annum since
Jan 2003 after commissioning of process units like RFFCU, DHDT, HGU, SRU, ARU
and SWS.
With various revamps and expansion projects at Barauni Refinery, capability for
processing high-sulphur crude has been added — high-sulphur crude oil (sour
crude) is cheaper than low-sulphur crudes — thereby increasing not only the
capacity but also the profitability of the refinery.
The oil movement and storage section of refinery does the storage and dispatch of
all the products. An LPG bottling plant has also been provided which is able to fill
3500 to 4000 cylinders per day. A captive Power plant has been provided to meet
the steam and power requirements of the refinery.

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MAIN PRODUCTS
1. LPG : LIQUIFIED PETROLEUM GAS
2. MS : MOTOR SPIRIT
3. NAPTHA : NAPTHA
4. HSD : HIGH SPEED DIESEL
5. SKO : SUPERIOR KEROSENE OIL
6. MTO : MINERAL TURPENTINE OIL
7. LDO : LIGHT DIESEL OIL
8. LSHS : LOW SULPHUR HEAVY STOCK
9. RPC : RAW PETOLEUM COKE
10. CPC : CALCINED PETROLEUM COKE
11. P. EXT. : PHENOL EXTRACT
12. SL. WAX : SLACK WAX

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NAME OF PROCESSING UNITS
1. AVU-I : ATMOSPHERIC & VACCUM UNIT – I
2. AVU-II : ATMOSPHERIC & VACCUM UNIT – II
3. AVU-III : ATMOSPHERIC & VACCUM UNIT – III
4. PEU : PHENOL EXTRACTION UNIT
5. SDU : SOLVENT DE-WAXING UNIT
6. CCU : COKE CALCINATION UNIT
7. NSU : NAPTHA SPLITTER UNIT
8. CRU : CATALYTIC REFORMING UNIT
9. RFCCU : RESIDUE FLUIDISED CATALYTIC CRACKING UNIT
10.DHDT : DIESEL HYDRO-TREATMENT UNIT
11.HGU : HYDROGEN GENERATION UNIT
12.SRU : SULPHUR RECOVERY UNIT
13. ARU : AMINE GENERATION UNIT

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BLOCK FLOW DIAGRAM

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STRUCTURE OF THE REFINERYSTRUCTURE OF THE REFINERYSTRUCTURE OF THE REFINERYSTRUCTURE OF THE REFINERY
DEPARTMENTS JOB
1. PRODUCTION
DEPARTMENT
All the production related issues in the refinery
2. ENGINEERING
SERVICE
DEPARTMENT
Encompasses Mechanical, Civil, Electrical and
Instrumentation disciplines. Engineering & material
procurement related activities for modification/process
schemes/projects.
3. INTERNAL AUDIT Independent appraisal activity within the organization
for the review of operations as a service to management.
4. INSPECTION
DEPARTMENT
Provide technical backup to Production & Maintenance
department in terms of unit operation, monitoring &
inspection of static equipment’s such as furnace, vessels,
lines, column to prevent failures and recommends
necessary repairs.
5. MEDICAL
DEPARTMENT
Provide the highest quality health care and service to
Refinery employees and their families through unique
assessment and counseling expertise, organizational skills
and knowledge of systems and resources.
6. FIRE & SAFETY
DEPARTMENT
Reduce losses in terms of Machine, Men, Material and
Environment because of fire, accident, near miss incident,
dangerous occurrence and disaster by assisting in
development of safe/ suitable working environment.
7. TECHNICAL
SERVICE
Provide technical backup to production department for
monitoring unit operations, fuel & loss, utilities and
chemical. Monitors refinery emissions/effluent to meet
environmental regulation.
8. QUALITY CONTROL
DEPARTMENT
Monitors the quality of initial to final product i.e. from
crude to each extracted product (MS, Diesel etc.)

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Fire and Safety trainingFire and Safety trainingFire and Safety trainingFire and Safety training
The products obtained from the refinery are highly inflammable and associated
processing’s are extremely dangerous and fire hazardous. So, fire and safety provides
training teaches people to how to be safe while doing the refinery work and how to
avoid serious accidents or mishaps.
Triangle of fire- For a fire to catch, air heat and fumes are needed. If we cut the supply of
anyone of these then the fire can be avoided.
Types of HazardsTypes of HazardsTypes of HazardsTypes of Hazards----
1.) Fire hazards- In any case of fire explosion, fire alarms should be raised as soon as
possible and people should meet the nearest assembly point. In case of oil based
fire, cold water should be supplied to the burning system so that the temperature
does not exceed a maximum permissible value. In Barauni Refinery, Auto foam
system has been installed to extinguish fire.
Classification of fire –
Class of fire Involving materials Extinguishing agent
A Solid( normally organic)
materials
water
B Flammable liquid (or liquefiable
solid)
Water spray
C Gas or liquefiable gas DCP,CO2
D Metals like Mg, Na, Sn Ternary Eutectic chloride
E Electrical fire DCP, CO2
2.) Chemical and explosion hazards- For example, toxic gas emission, acid spillage,
corrosive chemical spillage etc. So, different kind of detectors are used like DSI
(ionized smoke detector), DSO (Optical smoke detector), DGT (toxic gas detector),
DGH (hydrogen gas detector) etc.

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Safety measure that must be taken:Safety measure that must be taken:Safety measure that must be taken:Safety measure that must be taken:
A worker must use personal protecting equipments (PPE) inside the refinery. PPE
includes safety helmet, safety shoes (to protect from electrical hazard), safety
goggles, ear plugs, hand gloves hand gloves, nose mask, safety belt and Nomex
(full body covering clothing for special cases).
Mobile phones or any electronic devices should not be carried inside refinery.
Without having proper knowledge, nothing should be touched to bring about any
change.
Self-controlled breathing apparatus (SCBA) should be used in any case of toxic gas
(like SO2, NH3, CO2 and H2S) emission.
Safety belt and rail guards, along with proper ladder (at 75o
) and staircase, must be
used when climbing above 2 meters.
Full proof guarding of the motors and pumps and other electrical or mechanical
devices musty be done to avoid injuries.
Miniature circuit board, molded case circuit board, Earth leakage circuit board
must be present so that it trips the electrical supply if there is some fault in the
electrical circuit.
Fire extinguishers must be present at suitable positions. For universal fire
extinguisher, range is 2-3 m, duration 15-20 seconds and weight is 5-6 kg.
.In case of fire or emergency, one should use emergency phone to dial 333 or
7777, IOCL fire and safety department numbers and 301 for first aid.

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ATMOSPHERIC AND VACUUM UNIT (AVU)
INTRODUCTION
In IOCl, Barauni Refinery, there are three Atmospheric and Vacuum Unit (AVU) units. AVU-1
and AVU-2 are for low sulfur crude oil and AVU-3 can process both low and high sulfur crude
oil. AVU is the mother unit of any refinery. Crude is first of all processed in this unit. It operates
at atmospheric pressure for fractionation into Gas, LPG, Naphtha, ATF, Kerosene, Diesel, and
Reduced Crude Oil (RCO). RCO is fractionated in Vacuum Distillation Unit (VDU) to get VGO
and raw lube cuts.
The raw streams from AVU are treated in Hydro treatment, Reforming, Isomerization and
Fluid Catalytic Cracking plants to obtain components of finished saleable products. VGO is
treated in RFCCU to get LPG, Propylene, Petrochemical feedstocks and components for motor
spirit and diesel. Raw lube cuts are treated for removal of aromatics and wax and are hydro
treated to get lube oil base stock. The short residue obtained from AVU fractionator bottom is
partly treated in Coker unit to get lighter value added products along with raw petroleum
coke. Vacuum residue can also be treated to extract out De-asphalted Oil (DAO) and the
residue left is asphalt. DAO is treated in aromatic extraction unit, dewaxing unit and
hydrofinishing unit to obtain bright stock which is used for Lube oils and grease manufacture.
Asphalt and vacuum residue can also be utilized for production of bitumen or as fuel for
furnaces and boilers. From RFCCU, olefins, propylene, various aromatics and naphtha are
obtained which are used as raw materials for polypropylene and aromatic petrochemical
plant. The Raw Petroleum Coke (RPC) is used for generation of power and calcined petroleum
coke. Sulphur present in crude and various streams is converted to H2S during processing. In
Sulphur plant, it is converted to elemental sulphur which is sold as by-product. This also helps
in environmental protection. Hydrogen plant is installed to produce hydrogen for meeting the
requirement of various hydro treatment processes.
Distillation
Distillation is a method of separating the components of a solution which depends on
distribution of the substance between gas and liquid phases. Its basic principle is that when a
solution of two or more components is boiled, then lighter the component more easily it
vaporizes. This results in the vapor above the liquid being relatively rich in the lighter, more

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volatile material. The liquid is left with proportionally more of the less volatile or heavier
liquid.
Fractional distillation
Fractional distillation is the separation of a mixture into its component parts, or fractions, such
as in separating chemical compounds by their boiling point by heating them to a temperature
at which one or more fractions of the compound will vaporize. It is a special type of
distillation. Generally the component parts boil at less than 25 °C from each other under a
pressure of one atmosphere (atm). If the difference in boiling points is greater than 25 °C, a
simple distillation is used.
In most cases, the distillation is operated at a continuous steady state. New feed is always
being added to the distillation column and products are always being removed. Unless the
process is disturbed due to changes in feed, heat, ambient temperature, or condensing, the
amount of feed being added and the amount of product being removed are normally equal.
This is known as continuous, steady-state fractional distillation.
Industrial distillation is typically performed in large, vertical cylindrical columns known as
"distillation or fractionation towers" or "distillation columns" with diameters ranging from
about 65 centimeters to 6 meters and heights ranging from about 6 meters to 60 meters or
more. The distillation towers have liquid outlets at intervals up the column which allow for the
withdrawal of different fractions or products having different boiling points or boiling ranges.
By increasing the temperature of the product inside the columns, the different hydrocarbons
are separated. The "lightest" products (those with the lowest boiling point) exit from the top
of the columns and the "heaviest" products (those with the highest boiling point) exit from the
bottom of the column.

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Process flow diagram of AVU
PROCESS DESCRIPTION
CRUDE OIL PRETREATMENT (DESALTING)
The crude oil is contaminated with various impurities– mainly salts of Ca, Mg, Na, CI, SO4, etc.
These salts, however, in small proportions in crude, can cause severe corrosion in crude units,
particularly in the overhead section. So, it is important to remove the salts from crude prior to
distillation. The desalters are designed for 99% salt removal and reach less than 1 part per
thousand barrels in desalted crude.
Crude oil received from refinery tank farm (RTF),each tank having 40000 m3
, is heated from
30O
C to 140-150o
C in cold preheat trains thus reducing viscosity and surface tension for easier
mixing and separation of water.. This is done by recovering heat from outgoing
products streams from the unit. Then it is passed through a desalter after being mixed with de-
emulsifier (chemical surfactant) and water through a mixer valve at pressure of 10kg/cm2
.
Water dissolves inorganic salts and de-emulsifier facilitates coalescence of fine water droplets

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in the desalter wherefrom water is separated from mixture. In the desalter, crude passes
through high electric field under very high voltage of 12kV. The salt dissolved in water settles
at the bottom as brine and desalted crude with less than one part per thousand barrels comes
out from the top of the vessel. Often ammonia is added to reduce corrosion and caustic or
acid may be added to adjust the pH of the water wash. Desalters remove salts, sludge and
mud from crude to avoid corrosion and fouling in exchangers’ columns and downstream
equipment.
PRE-TOPPING COLUMN (K1)
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 230O
C enters the column and flashes into liquid and vapor.
Inside the tower the liquids and vapors are always at their bubble points or dew points
respectively. So highest temperature is at the bottom and there by strips out the light portion
of the feed, it is also an alternative source of heat. The overhead vapor from the main
fractionator is condensed and cooled in the trim cooler; the condensed gasoline at a
temperature of 45O
C 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 top column. 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 goer to the kero
stripper where the light ends are stripped by steam. The vapor goes back to the main
fractionating column. The stripped bottom is sent to rundown via heat exchangers. The
balance kerosene is pumped as circulating reflux-exchanging heat with incoming crude in
various heat exchangers for maintaining the temperature of the column.
The next stream is of LPG and LGO cr. LGO is product is condensed while the LGO cr is sent
back to the column as circulating reflux.

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MAIN FRACTIONATOR (K2)
Inside the tower, the liquids and vapors are always at their bubble points or dew points
respectively. So highest temperature is at the bottom and lower temperature is at the top of
the column.
Stripping steam is given in the bottom of the column which decreases the partial pressure and
thus the boiling point of the hydrocarbon inside the column and thereby strips out the lighter
portion of the feed. It is also an alternative source of the heat.
The overload vapors from the main fractionating column is condensed and cooled in the air
condenser to 65O
C and further cooled in the trim cooler. The condensed gasoline at a
temperature of 45O
C 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 naphtha caustic wash. Sour water collected in the boot is drained
under level control of the vessel. Gas from the top of the reflux vessel is sent to the flare
under control of the hydrocarbon level.
The next 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 vapor from the stripper goes back
to main fractioning column. The stripped bottom is sent back to rundown via heat
exchangers. The balance kerosene is pumped as circulating reflux –exchanging heat with
incoming crude in various heat exchangers for maintaining the temperature of the column.
The side stream is of LGO & LGO cr. The LGO product is condensed while the LGO cr is sent
back to the column as circulating reflux.HGO & HGO cr come from the next side stream. HGO
product is condensed while HGO cr is sent back to the column as circulating reflux.
The bottom product of the column is RCO which is pumped into the furnace for heating it to a
temperature of 46O
C and is then flashed in the vacuum column.
NAPHTHA STABILIZER COLUMN (K4)
From k1, the top product which is mixture of naphtha and LPG enters into naphtha stabilizer
column to separate naphtha from tits lighter fractions. Lighter ends (propane and butane)
are removed to reduce the vapor pressure of naphtha so that it can be used in

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automobile engine without the fear of any vapor locking, while LPG which is removed is
cooled, condensed and taken into reflux drum wherefrom a part of it again fed back and
remaining part is sent to LRU.
VACUUM COLUMN
The RCO which can’t be further process in AVU is fed to the vacuum column. The overhead
vapors from the column are sent to the pre-condenser where Stream and other condensable
are sucked by ejectors and sent to the series of ejectors condensers from where the
condensed liquid goes to the hot well. The non-condensable inert gases are bubbled through
the hot well for purpose of maintaining liquids.
First side stream from the column is LVGO & LVGO cr acts as circulating reflux for maintain
the temperature of the column. Product VGO joins as HSD Streams, the 2nd side stream from
the column is HVGO & HVGO cr. part of the hot stream is sent as internal reflux to the
column. The HVGO and HVGO cr are sent through heat exchangers for heating the crude.
From the outlet of heat exchangers HVGO is returned to the column.
The 3rd
side stream is SLOP and over flash. A part of which is sent to stripping section as over
flash while balance is sent to suction or SR pumps.
The bottom product of the column is short residue, which is pumped to rundown via heat
exchangers. SR acts as a feed to various units like Coker and RFCCU.
RCO from the main fractionating column is feed to the vacuum column because further
heating in main fractionator 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 yields.
Top of the vacuum column is provided with a demister to minimize the entrainment of
liquids droplets in the vapor going to the overhead condenser. The overhead condenser is
taken to the pre-condensers where the steam and condensable are condensed. The sour
water is pumped back to desalter water tank.

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CATALYTIC REFORMING UNIT(CRU)
The purpose of CRU 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. So splitter was required to get suitable catalyst, but impurities act as
catalyst-poison, so we need hydro-treater to remove impurities and water.
General process description
CRU improves the quality of MS (petrol) by increasing it octane number or antiknock
property. The raw material is gasoline, received from AVUs column to tank in CRU. From tanks
through pumps it is fed into naphtha splitter column, where it is divided into 2 parts. Top
portion i.e. light naphtha is routed to HGU as feed of the unit after caustic wash. The bottom
product i.e. heavy naphtha is sent to the hydro-treater unit where its organic impurities like
sulfur, N2, O2 are removed and stripped off from top. The bottom product of the stripper i.e.
DSN (de sulfurized naphtha) is feed to CRU. In CRU, this DSN is aromatized or dehydrogenated
by catalyst in reactors along with hydrogen. His hydrogen is recycled with compressor; the
excess h produced is compressed by h rich gas compressor.
The hydrocarbon from reactor goes to L.P. separator, the bottom of the separator is naphtha
and it is pumped H.P. separator through pump and the top of the L.P. separator goes to
compressor. The bottom of the H.P. separator is sent to the LPG separator. After removing
the LPG, naphtha is pumped to stabilizer column for residual LPG removal. The LPG from the
top of the column are removed and the bottom stabilized product is called reformate and
sent as M.S. constituent.
The commonly used catalytic reforming catalysts are Pt and Rh which are very susceptible to S
and N compounds, so they are removed in pretreatment process.
The four major catalytic reforming reactions are:
1: The dehydrogenation of naphthenes to convert them into aromatics as
exemplified in the conversion methylcyclohexane (a naphthene) to toluene (an
aromatic), as shown below:

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2: The isomerization of normal paraffins to isoparaffins as exemplified in the
conversion of normal octane to 2, 5-Dimethylhexane (an isoparaffin), as shown
below:
3: The dehydrogenation and aromatization of paraffins to aromatics (commonly
called dehydrocyclization) as exemplified in the conversion of normal heptane to
toluene, as shown
4 The hydrocracking of paraffins into smaller molecules as exemplified by the
cracking of normal heptane into isopentane and ethane, as shown below:
Process flow diagram of CRU

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Process and plant description
Naphtha splitter unit (NSU)
IBP-140o
C cut naphtha from storage is fed to splitter column under flow control by offsite
pump. The feed is heated up to 95o
C in splitter feed/bottom exchanger against splitter
bottom stream before it enters the column.
The overhead vapors are totally condensed. The liquid collected is pumped by splitter reflex
pump and one part sent as top reflux back to column under flow to maintain the top
temperature, the balance, which constitute the IBP 70o
C cut naphtha is sent to the HGU as
their feed and rest light naphtha is sent to the storage under reflux drum level control after
cooling in a water cooler. Reflux drum boot water is drained in OWS manually.
The pressure of splitter is controlled at reflux drum by passing a part of hot column
overhead vapors around the condenser or releasing the reflux vapors to flares through a
split range controller. The splitter bottom product which constitutes the 70-40o
C cut
naphtha is pumped to splitter feed/bottom exchanger by hydro treater fed pumps/. The
bottom product after exchange ng the heat with feed is split into 2 streams. One is fed to
the hydro treater unit at a tempo of 65o
C and the other is sent to storage under column
level control after being cooled in splitter bottom column.
The heat necessary for splitter reboiling is supplied by splitter reboiler furnace and desired
temperature maintained by controlling the fuel firing. Splitter reboiler pumps provide the
circulation through reboiler is double pass vertical cylindrical furnace having 4 burners fired
from the bottom. It has soot-blowing facility for convection section.
Hydrotreater unit (HTU)
• Reaction and separation section
The naphtha from NSU Is fed to HTU by a pump. The feed flow is controlled by a valve. The
feed is then mixed with rich H2 gas from HP separator of reformer. Both liquid naphtha and
rich H2 gas are preheated in a series of feed effluent heat exchangers. Then mixture is
heated up to reaction temperature in a furnace and fed to a reactor. The furnace is 4 pass
having 3 burners fired from the bottom. The furnace is having a facility of soot blowing. The
reaction is maintained. The furnace is providing with all safety. It has also provision of

21. 21
decoking. The desulfurization and hydro treating reaction takes place at almost constant
temperature since heat of reaction negligible. The reactor is provided with the facility of
steam and air for regeneration of Catalyst (HR-306).
The reactor effluent after having heat exchanged with feed goes to the air cooler. The air
cooler fans pitch is variable i.e., cooling load can be carried. Then effluent is cooled in a trim
cooler. The product is collected in a separator manually. The separator drum pressure is
maintained by routing the gas to HGU compressor fully through and any excess gas can be
routed to FG system. In event of emergency the separator excess pressure can be released
to flare.
• Stripper Section
The separator liquid id pumped under flow control cascaded to stripper feed/bottom
exchanger. The stripper column consists of 28 valve trays. Feed coming enters at 9th
tray
From the two sides. The overhead vapors are 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 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.
Catalytic Reformer Unit (CRU)
Hydro treated naphtha is pumped to required pressure and mixed with recycle gas. The
mixed feed is preheated in the two feed effluent exchangers. Then the mixture is brought
up to the reaction temp (480C) by heating in the preheater and fed to 1st
reactor.
As the reaction is endothermic, the temperature drops, so the first reactor effluent is
heated in the first inter heater prior to be sent to 2nd
reactor. In the same way effluents are
heated in 2nd
inter healer prior to be sent to 3rd reactor.
The effluent from the last reactor is split in to 2 streams and sends for heat recovery
parallel to feed exchanger and stabilizer reboiler. The outlet from the 2 exchangers is
combined by these way valves and then cooled down, reformer effluent cooler and effluent
trim cooler. The cooler reactor effluent is flashed in the reformer separators.

22. 22
Vapor and liquid phase are separated. Part of the gas phase constitutes the H2 recycle gas
to the reactor a circulated by recycle gas compressor. The H2 rich gas compressor
compresses reaming amount, corresponding to the amount of gas produced, the pressure
control in separated is achieved by a kick back gas follow from HP absorber to separator.
The separator liquid is sent by reformer separator bottom pumps under level control for
contacting with the gas compressed. The hot flues gas from all 3 reformer furnaces are
combined and sent to stream generation system for waste heat recovery to produce MP
steam. Provision is there to dry the recycle gas into a dryer.
The unit has also been provided with facilities for continuous chloriding, water injection,
DMDS injection and caustic soda circulation. The separator vapor after passing through KO
drum is compressed in H2 gas compressor and recontacted with separator liquids. The
contracted vapor and liquids is cooled in a cooler and the fed to HP absorber. The aim is
allow for high quality of produced gas. A part of H2 rich vapor goes to HTU as make-up H2
and balances goes to the suction KO drum of HGU compressor that is run to provide H2 to
DHDT after purification in a PSA unit.
The liquid from HP absorber is drawn off under level control and mixed with stabilizer
vapor distillate. The combined stream is cooled in LPG absorber feed cooler and flashed in
LPG absorber. Of Gas is sent u8nder pressure control to fuel gas system. Stabilizer feed
pumps the liquid and preheating in stabilizer feed exchanger the mixture is sent to
stabilizer at tray 13th
where vapor condenses partially and flashed into stabilizer reflux
drum. N the vapor phase is sent to LPG absorber for C3, C4 recovery.

23. 23
MOTOR SPIRIT QUALITY UPGRADATION UNIT (MSQU)
This unit is for motor spirit quality improvement, that is, octane number increase. It has 3
sub-units, namely-
1) Naphtha Hydro treating Unit (NHDT)
2) Isomerization unit (ISOM)
3) Prime gasoline plus (Prime G+)

24. 24
NAPHTHA HYDROTREATING UNIT
The purpose of NHDT unit is to produce clean desulfurized naphtha cut suitable to be
process in the NHDT splitter unit after removal of all impurities which are currently
poison for catalyst (sulphur nitrogen, water, di-olefins, olefins, arsenic, mercury and
other metals.)
FEED: -
Coker Naphtha
Straight Run Naphtha (SRN)
Heart Cut Naphtha
CRU Naphtha
IMPURITIES CONTENTS IN FEED: -
Sulphur
Nitrogen
Silicon
NHDT includes following sections: -
Feed Section
Reaction Section
Recycle Gas Compression System
Stripper
NHDT Splitter
Product specification:-
There are only two primary products
Light Naphtha to Isomerization Unit
Heavy Naphtha to Naphtha Pool
in addition to this secondary purge gas stream routed to fuel gas treatment.

25. 25
Process flow diagramProcess flow diagramProcess flow diagramProcess flow diagram
Process Flow Description
The Coker Cut Naphtha enters the Unit at battery limit. It is routed to Coker Naphtha
feed drum 801-V-07 through Coker feed filter package 801-G-01. Light naphtha from
Naphtha splitter unit is mixed with Heart Cut Naphtha and heavy LCN from Prime G Unit.
The mixture is directed to the NHDT feed surge drum.
As a constant composition and flow to NHDT is needed, there is connection to RFCCU
on the Coker Naphtha feeding line in order to regulate the Coker Naphtha flow rate to
the reaction section properly for controlling Coker feed surge drum level.
The mixture of Coker Naphtha feed and Naphtha feed which is pumped to NHDT feed
pump 801-P-01 A/B, is routed to the reaction circuit under flow control with level reset
of 801-V-07. It is mixed with a part of make-up hydrogen coming from C5-C6
Isomerisation unit before entering the reaction circuit. The other part of make-up
hydrogen coming from C5-C6 Isomerisation unit is injected at the outlet of the first
reactor to limit the rate of vaporisation at the inlet of the 1st
reactor. The feed is also
diluted with a part of liquid coming from NHDT separator drum to limit ∆T in the second
reactor.

26. 26
ISOMERIZATION UNIT
Isomerization is conversion of low octane straight chain compounds to their higher
octane branched isomers. Light hydro treated naphtha and light reformate is dried and
passed over an activated chloride Platinum based catalyst in presence of once through
hydrogen (also dried). Prior to isomerization reaction, a fixed bed reactor for catalytic
saturation of benzene in presence of H2 is used.
SAMPLE FEED SPECIFICATIONS
Feed material MAJOR CONSTITUTES
Light naphtha from
NHDT
NC6 NC5 IC5 MCP BENZEN
E
TOTAL FLOW
RATE in kg/hr
15.13
%
19.16
%
16.53
%
3.88
%
2.87% 11875 kg/hr
Light reformate
from RSU
NC6 NC5 IC5 MCP BENZEN
E
14.2
%
10.69
%
15.3% 1.34
%
25.33% 3117 kg/hr
H2 MAKE-UP
FROM CRU
H2 C1 C2 1689 kg/hr
86.03
%
15.9
%
3.33%
FRESH CAUSTIC 10 % NaOH 8755 kg/hr
LOW PRESSURE
STEAM
CONDENSATE
100% water 06 kg/hr

27. 27
UTILITIES
(a) No. of Pumps used- 9
(b) No. of compressors used- 2
(c) No. of coolers used- 5
(d)
PROCESS FLOW DESCRIPTION
• There are two fixed bed reactors, which convert normal C5 and C6 paraffin to
isomers for increasing the octane number.
• Catalyst: Platinum catalyst in presence of Hydrogen.
• Low octane methyl pentanes and unconverted n-hexane are recycled back.
• Deisohexaniser Tower: For recovering and recycling the low octane numbers
methyl pentanes and the unconverted n-hexane from the reactor effluent.
• A stabilizer is used for removing light ends from the reactor effluent, before
sending it to the deisohexaniser.
•
• The stabilizer reflux drum vent gas contains H2 and chloride which are removed by
neutralization with caustic soda in caustic scrubber.
• There require make-up H2 so it is sent to Isomerisation unit under flow control,
spill back control valve is there to maintain discharge pressure.
• Dryers are used to dry the H2O so that water is not present there as it is the
deactivator of catalyst.
• Feed exchanges heat with Deisohexaniser cycle then in 1st
stage reactor then in
Hydrogen Generation Reactor finally heated by MP steam heater for required inlet
temperature then go to benzene hydrogenation.
• C2Cl4 is the activator of isomerisation catalyst.
• The effluent are routed to stabilizer, its purpose is to reduce C4 rate in ISOM
reactor effluent.
• LPG, H2, HCl are stripped and sent to scrubber mainly to reduce C4 content so C5
concentration increases.
• Stabilizer trim cooler, stabilizer is reboiled with MHP steam heater.
• Then Stabilizer bottom is routed to deisohexaniser via chloride guard to avoid
chloride upset in downstream section.
• Light isomerate is used as regenerate for dryers.
• The two isomerate products from the deisohexaniser the light isomerate and
heavy isomerate. The heavy isomerate is required to be cooled before storage.
• The stabilizer effluent gas contains HCl so it is caustically washed then reached to
fuel gas system.

28. 28
• The stabilizer section contains carbon raschig rings and H2.
• Dryer regeneration: Light naphtha feed, H2 make-up, flow through their
respective dryers in series.
• Molecular sieves becomes saturated they need re-generation; one multilayer
online moisture analyser is used to monitor the moisture content of the stream
leaving each dryer.
• Regenerant Degasser is a liquid flooded drum.
• Light components which accumulate in Regenerant Degasser are purged to flare.
Regenerant Degasser free water is periodically drained as oily water sewer
• C2Cl4 for HCl, Cl2 lost and the HCl coming from ISOM unit is finally converted to
NaCl in the caustic scrubber.

29. 29
PRIME GPRIME GPRIME GPRIME GASOLINEASOLINEASOLINEASOLINE + UNIT+ UNIT+ UNIT+ UNIT
The purpose of Prime G+ unit is to achieve a deep hydro-desulfurization of Light Cracked
Naphtha (LCN) and Heavy Cracked Naphtha (HCN) coming from RFCCU. The majority of
the sulphur in the typical gasoline pool is coming from the RFCC gasoline.
Conventional desulfurization technology results in significant loss in octane number due
to saturation of high octane olefins low octane paraffin. At high levels of desulfurization,
the octane number can be reduced by 5 to 10 points, which is unacceptable. The
objective of the Prime G+ process is to remove sulphur while avoiding substantial loss in
octane number.
For storage tanks are to be blanketed with the inert gas as nitrogen. Antioxidant agent
injection and inline dilutions should be taken in consideration. Reactions in reactor have
very high selectivity and minimum loss of octane number is obtained. Amine stream is
used in used in recycle gas to remove hydrogen sulphide.
Selective Hydrogenation Reaction Section:
Feed: Light Cracked Naphtha (LCN) gasoline coming directly from the upstream of
debutanizer of RFCC Unit or mixed with a limited quantity of feed from storage.
To remove scale particles and gummy ingredients feed is first routed to LCN feed filters.
In this reactor light mercaptan and light sulphides are converted to heavier sulphur
compounds which recovered in the splitter bottom. SHU is operated in liquid phase.
Splitter produces LCN and HCN.
HDS Section:
HDS section converts dioleffins to olefins. In reactor residence time is increased and high
pressure is reducing polymerisation and coke deposit. After HDS reactor liquid HC is sent
to stabilizer and effluent is water wash to cool it. Sour water is sent to sour water splitter
unit. Hydrocarbon is sent to stabilizer. Here light ends, hydrogen sulphide and water
vapour is separated formed in the reactor. Desulphurisation of gasoline takes place in
reactor. Olefin saturation is limited and no aromatics are formed.

30. 30
BARAUNI REFINERY EXPANSION PROJECT (BXP)
BXP was envisaged for augmenting crude processing capacity from 4.2 MMTPA to 6
MMTPA. It is to produce the market-oriented pattern of environment friendly high value
products like LPG, diesel and motor spirit.
Unit Feed Product
Residue fluidized catalytic
cracking unit(RFFCU)
Blend of short residue and
HVGO
Fuel gas oil, LPG, gasoline
Diesel hydro treating unit
(DHDTU)
High sulfur low cetane diesel Low sulfur high cetane
diesel
Hydrogen generation
unit(HGU)
Naphtha Hydrogen (99.99% pure)
Amine recovery unit(ARU) Rich amine containing high
amount of H2S from
DHDT/RFFCU
Lean amine
Sour water stripping
unit(SWSU)
Sour water Water
M Sulfur recovery unit(SRU) acid gas feed Sulfur
Catalytic reforming
unit(CRU)
gasoline Reformate as M.S.
constituent and
Hydrogen

31. 31
RESID FLUIDISED CATALYTIC CRACKING UNIT(RFFCU)
REACTION SYSTEM
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.
Fresh feed preheat
Fresh feed is pumped on flow control from the feed surge drum to the feed preheat
exchangers to recover heat from the process. The feed is heated against HN lean oil, 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.
Feed
Oil feed to the riser is preheated before entering the reaction system. Dispersion steam is
supplied to each fresh feed 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.

32. 32
Riser Reactor
The sensible heat, heat of vaporization and heat of reaction by the oil feed supplied by the
hot regenerated catalyst riser outlet temp (ROT) is regulated controlling the regenerated
Catalyst admitted to the riser through the regenerated catalyst side valve (RCSV). The
reaction system 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 fractionator’s press and 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 vapors 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.

33. 33
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.
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 the regenerator catalyst bed. Stone & Webster’s spent catalyst
distributor is a “bathtub” design with weirs for even catalyst flow. To maintain properly
fluidized catalyst, fluidization air is introduced through sparger 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.
Regeneration System – General
The first stage regenerator burns 60 to 70 percent 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 feeds 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 regenerator

34. 34
is reduced, thus increasing the regenerated catalyst temperature. The amount of coke
burned in the first stage can be varied by adjusting the airflow rate. This feature allows
operating flexibility for processing different feedstocks. Regenerator temperature is not
directly controlled. As the coke burn increases 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.
Regeneration System – Air Blower and Air Heaters
An axial air blower, driven by a steam turbine, supplies combustion air for the process. The
steam supply to the turbines is throttled on cascade air flow trim-control/compressor
speed and is exhausted through the turbine to a surface condenser system.

35. 35
Atmospheric air is introduced to the air blower through an intake filter and silencer. The
blower air is distributed to a header system serving combustion air to first stage
regenerator rings, second stage regenerator rings, lift air, withdrawal-well ring air, spent
catalyst distributor sparger, and auxiliary air to the catalyst hopper area. A check valve in
the blower discharge line prevents back-flow of catalyst upon blower shut-down. Blower
surging is prevented by venting air using a sophisticated anti-surge controller.
Combustion air to each regenerator is flow-controlled. Low air flow to either regenerator
will trigger the emergency shutdown circuit during blower failure. Combustion air to the
first stage regenerator is balanced between two air rings with the flow to each ring
adjusted by manual control of butterfly valves. The outer and inner air rings are designed to
handle 72% and 28% of the combustion air to the first stage regenerator, respectively.
Direct fired air heaters are located in the combustion air lines to the first stage regenerator
outer combustion air ring and second stage regenerator combustion air ring. The air
heaters are used only during start-up to heat the catalyst and FCC equipment.
Instrumentation is provided to prevent equipment overheating during air heater operation
and a flame-safety package is included to prevent unsafe conditions during burner
operation. Due to low refinery fuel gas header pressure, fuel gas will be imported from the
Coker unit for use in the air heaters during the FCC start-up.

36. 36
(1) Regeneration System – First Stage Regenerator
Spent catalyst containing coke flows from the spent catalyst distributor and is spread across
the bed in the first stage regenerator. Part of the coke is burned by combustion air from
the air ring. This regenerator operates in a countercurrent (air enters at the bottom while
spent catalyst enters at the top) mode which helps prevent catalyst overheating. The
regeneration conditions are mild to limit hydrothermal deactivation of the catalyst. By
controlling the combustion air to the first stage regenerator, the temperature in the first
stage is limited to approximately 705o
C.
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 lift 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 the catalyst in dilute

37. 37
phase to the second stage regenerator. Blower air to the 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/cm2
. 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.
Torch oil is used to heat the process to its operating temperature during start-up. Oil on
flow-control is directed to two injectors, which spray into the bed of air-preheated catalyst.
(2) Regeneration System – Second Stage Regenerator
The partially regenerated catalyst flows up the lift line and enters the second stage
re-generator 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 vapor is produced in the second stage. This low water vapor 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 resid-type feeds. The first stage cyclone dip

38. 38
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.
The level in the second stage regenerator is not directly controlled but depends on the
catalyst inventory. Periodic catalyst withdrawals (or additions) are necessary to maintain
the level in the normal operating region. Second stage regenerator pressure is controlled
by the flue gas slide valve upstream of the orifice chamber.
(3) 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° slanted wye section
to the riser base where the catalyst beings the upward flow toward the fresh feed
injectors. 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. Fluidization gas in the 45
degree wye section and the stabilization steam in the reverse seal section, ensure even
catalyst flow as the catalyst reaches the feed injection section. This straight vertical
section below the feed injectors also serves as a reverse seal preventing oil flow reversal.

39. 39
Diesel Hydro-Treatment Unit (DHDT)
It uses a catalytic hydrogenation method to upgrade the quality of petroleum distillate
fractions. The purpose of diesel hydro treating unit is to:
• Remove sulphur and nitrogen to produce low sulphur (<0.2 wt %), color stable
diesel.
• Convert olefins/aromatics to saturated compounds.
• Remove contaminants like oxygenates and organometallic compounds.
• Improve Diesel cetane number (> 49).decomposing the contaminant with
negligible effect on then boiling range of the feed.
FEED
From AVUs- LVGO, HVGO
From RFFCU- LCO, HCN
From Coker unit – Light Coker gas
oil(LCGO), Kerosene range
From HGU- H2 gas (>99.5% pure)
UNIT CAPACITY 2.2 MMPTA
Process low diagram of DHDT

40. 40
PROCESS DESCRIPTION –
The feed is pumped to a coalescer where water present is drained out through the
water boot it is routed through heat exchanger where it exchanges heat with the
rundown product, the final temperature being 100o
C. Further it is passed through filters
to remove fine particles.
The filtered feed is taken into s 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 at327o
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 340o
C.
This feed is then fed into 2 reactors in series. The reactors have fixed bed catalysts (2 in
each reactor). The first bed consists of a catalyst that traps metals coming in the feed and
the second as well as the other two beds consists of catalyst that improves the cetane
number and causes hydrosulfurization.
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 temperature of the
reactor bottom exit is 370o
C. It is routed to a heat exchanger train where it loses heat
(140o
C), then through a cooler (54o
C) and is taken to a HPS drum having a boot in the
bottom. In between wash water and make hydrogen is added.
In the HPS drum the gas goes into a knock out drum from the top, In 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 KDO goes into a
Flash drum. One line from n 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 the heat exchangers (260o
C). M.P. steam is
added to the column from the bottom. The bottom product (257o
C) is our rundown
product. It is cooled in 2 heat exchangers and then in air coolers (40o
C) and fed into a

41. 41
coalescer to remove any water present. The top of the coalescer vessel is our final diesel
which h is sent to storage tanks.
The top vapors of the columns are taken to through air coolers and condensers where it
loses heat (41o
C) and then into a stripper receiver. The top of this vessel contains gases,
mainly H2S. This is sent the KOD and then to a amine absorber where lean amine is
added and the bottom product is rich amine which is sent to Amine Recover Unit) ARU).
The top product goes to a stripper where sweet gas is generated.
The bottom product of the sweet drum is unstabilized naphtha, part of which is sent to
RFFCU and rest as reflux to the main column.

42. 42
`SULFUR RECOVERY UNIT(SRU)
Property Remarks
SRU Recover Sulfur from vapors containing H2S from ARU & SWSU
Capacity 2 x 40 TPD of element sulfur
Turndown 30%
Unit’s sub-sections Amine Recovery Unit(ARU),
Sour Water Stripper Unit(SWSU),
Sulfur Recovery Unit(SRU)
Process Combination of Claus process and a Super Claus process
Process flow diagram
PROCESS DESCRIPTION
(1) AMINE RECOVERY UNIT(ARU)
Its purpose is to remove absorbed HS and CO2 from rich amine to give lean amine. Rich amine
from RFFCU/DHDT/Coker section at 4.5 kg/cm2
pressure and 50 o
C temperature is first heated
in a boiler to raise its temperature. Then HS and other light gases come out at the top of the

43. 43
vertical amine absorber unit. Lean amine comes out of the bottom and HS gas at top is
supplied to steam recovery unit. Lean amine is again supplied to DHDT/RFFCU where it is
required.
R2NH3S R2NH + HS
(R2NH3)CO3 R 2NH + CO2 +H2O;
Where R is CH3CHOH group.
(2) SOUR WATER STRIPPER UNIT (SWSU)
Sour water contains HS and NH3 as major contaminants and phenols, cyanides, chlorides, CO2
and hydrocarbons as minor one. The principle of sour water stripping is based on the
application of heat to reduce the solubility of NH4
+
and (HS-
) in the water phase plus the
dilution and depletion of gaseous NH3and HS by rising steam vapor. So equilibrium shifts first.
That is, ion adding sufficient heat to sour water, the NH3 and HS will come out of the solution
and be easily stripping away as gases.
But NH3is extremely soluble in water, some ammonium salts will persist in n sour water. Also
some ammonium salts such as NH4Cl are not easily decomposed,, this residual ammonia can
be released from the solution by the injection of a strong base such as NaOH.
NH3 + HS -> NH4
+
+ HS-
NH4+
OH-
NH3 + H2O
This freed ammonia can be then stripped away. Acid gas flare system is to provide to rout
acids/sour gases from the all vents to acid gas relief header.
(3) SULFUR RECOVERY UNIT
The SRU Process applied in the Barauni refinery known as 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

44. 44
hydrocarbons and ammonia present in the acid gas feed and to obtain an H2S (0.5-0.7 vol
%) at the inlet of the super Claus reactor.
• Conventional process is Claus process. H2S /SO2 ration is 2:1 where as
• The super Claus process air to acid ratio is adjusted to ensure an H2S / SO2 ratio greater
than 2:1 in burner effluent.
Claus section
Air from air blower is provided to furnace which is operating at 1100-1400o
C. Partial oxidation
occurs. The main reaction in the main burner occurs in 2 stages:-
a. H2S +3/2 O2 SO2+ H2O +heat(exothermic)
Here 1/3rd
of H2s reacts.
b. 2 H2S + SO2 3/2 S2+ 2 H2O (endothermic)
Remaining 2/3rd
h2s convert as this reaction. This reaction is reversible, so concentration
of Sulfur is maintained.
It should be noted that the exothermic reaction liberates more energy than endothermic, so
overall reaction is exothermic.so waste heat boiler uses excess heat to produce HP steam.
Also, sulfur obtained after this process is in vapor phase as at 290-340o
C, while has boiling
point of sulfur is 206o
C.
Sulfur is formed in vapor phase in the main burner and combustion chamber. The process gas
leaving the Sulfur condenser still contained a considerable amount of H2S and SO2 .Therefore
the essential function of the following equipment is to convert these components to Sulfur.
Super Claus process
The process gas from the 4th
Sulfur condenser is routed to the 4th
steam heater then passed
through super Claus reactor. Following reaction occurs:
2 H2S + SO2 2/8 S8 + 2H2O+heat
The sulfur is condensed in the 5th
Sulfur condenser. It coalesces is installed downstream of the
last sulfur condenser to separate entrained sulfur mist. The sulfur condensed and separated in
the condenser and coalesces is drained via the sulfur locks and goes into Sulfur pit.

45. 45
Sulfur degassing section
The produced liquid sulfur contains H2S and partly polysulfide (H2Sx). So we have to treat it to
remove the H2S content. There is shell sulfur degassing system to enhance the decomposition
of polysulfides and to strip the H2S content from the sulfur to safe level of 10 ppm. This is
achieved by bubbling air through the sulfur. The air decreases the partial pressure of the H2S
and causes ignition and circulation to the sulfur. In this way, the H2S content is reduced from
350 ppm to less than 10 ppm. The released H2S together with the air is routed to the thermal
incinerator in which it is oxidizes to SO2.The degassing sulfur is inherently intermitted pumped
to the liquid sulfur tanks to sulfur yards. From the liquid sulfur tanks, sulfur is pumped into the
truck via sulfur loading pump stand and supplied to various industries.
Thermal incinerator
The tail gas leaving the coalescer still contains an amount of H2S, which is dangerous if directly
released to the atmosphere. So the gas is thermally incinerated converting residual H2S and
sulfur vapors in SO2. It also removes SOx, NOx and COx from the system.
CO CO2
NO NO2
H S SO2
In the thermal incinerator the combustible components in the tail gas from the sulfur
coalesces and vent gas from the sulfur pit are thermally oxidized at the temperature 765o
C
with an excess air. The off gas from the merichem unit is also sent to incinerator.
The gas to be incinerated is headed to required temperature by mixing it with hot flue gas in
the thermal incinerator burner, these hot flue gas are greeted by burning flue gas. The
combustion air is supplied by the incinerator air blower. To remove the heat generated in the
thermal incinerator, the flue gas is passed through the bundle in the waste heat boiler. After
the cooling of flue gas by HP and LP stream, it is sent back to stack. The provision for
introducing quench air in the flue gas line in case its temperature becomes too high.

46. 46
HYDROGEN GENERATION UNIT (HGU)
Need of hydrogen is increasing day after day for treating the products
like motor spirit, HSD, fuel oils and feeds for FCC and other plants for
bringing down sulphur.
Hydrogen gas in the refinery comes from
a) Hydrogen production plant – as described below
b) Catalytic reformers (CRU) of the refinery.
Name Of Plant Hydrogen generation unit
Capacity 34000MTPA
Feedstock 70% SRN from CRU(C5-90o
C& C5-140o
C) and
30% RFCCU Off-gases (having about 16% H2)
Products 99.9% hydrogen gas & impurities like
CO,CH4,CO2
HP steam 37-44 kg/cm2
at 400o
C
PROCESS FLOW DIAGRAM OF HGU

47. 47
Process description
This plant deals with following process steps:-
1) Hydrogenation
2) Dechlorization & desulfurization
3) Steam reforming- adiabatic & tubular
4) Gas purification
The sulfur and chlorine has to be removed from the feedstock to a very low level (to
avoid poisoning of catalyst) before it is sent to reforming section. Hydrogen is added to
mix of RFFCU off gases and naphtha, the total mix is preheated to 260 to 380o
C
(dependent of olefins presence.
HYDROGENATION
The vaporized mixture of feedstock is passed through hydrogenator section where
cobalt-molybdenum based ring-shaped hydrogenation catalyst TK-250(Topse catalyst,)
transforms organic sulfur compounds and organic chloride compounds into H2S and HCl.
RCl + H2 -> RH + HCl
RSH + H2 -> RH + H2S
R1SSR2 + 3 H2 -> R1H + R2H +2 H2S
C4H4 S+ 4 H2 -> C4H10 + H2S
COS + H2 -> CO + H2S
R1= R2 + H2 -> H R1- R2H + heat; where R, R1, R2 are radicals of hydrocarbons.
Important points-
• The maximum activity of catalyst depends on H2 concentration and for temperature
range of 380-400o
C. Above 400o
C, coke could be formed on the surface of catalyst
and thus decrease the activity.
•
•

48. 48
• Improper mixing of hydrocarbons and H2 may cause gradual decrease of carbon layout
and a deactivation of the catalyst leading to poor conversion; increased Cl and S clip
to reforming section.
• As the feed may contain olefins, it is mandatory to pre-sulfide (above 2 ppm) the
catalyst, otherwise hydro-cracking might occur and increased tendency of
methanation if CO/CO2 is present.
CO2 + 4 H2 -> C H4 + 2 H2O
CO + 3 H2 -> C H4 + H2O
DECHLORIZATION
Now HCl is absorbed in the Cl guard vessel (loaded with 6.8 m3
in one bed of the Topse
HTG-1 catalyst in 5mm rings). The adsorption curve is very steep, ensuring an extremely
low content of HCl in the exit stream.
K2CO3 + HCl -> KCl + KHCO3
KHCO3 + HCl -> KCl + H2O + CO2
The calculated equilibrium constant is 2 x 1014
at 400o
C.
DESULFURIZATION
H2S is absorbed in this section in the two identical reactors located in series, each loaded
with 12.95 m3
of Topse HTG-3 catalyst having 4 mm ZnO extrusions. The S content is
down to a level of less than 0.05 ppm by weight.
H2S + ZnO -> ZnS + H2O
REFORMING SECTION
The gas from the desulfurization section is mixed with steam and sent to the reforming
section – consisting of an adiabatic pre-reformer and a tubular reformer – where
hydrocarbons are reacted over nickel catalyst with steam.
i. CnHm + n H2O -> nCO + (n+ m/2) H2 (endothermic)

49. 49
ii. C H4 + H2O -> CO +3 H2O (endothermic)
iii. CO + H2O -> CO2 + H2 (exothermic shift reaction)
ADIABATIC REFORMING
After mixing with steam, gas from the desulfurization section is preheated to 500o
C by
heat exchange with hot flue gas and continues to pre-reformer in presence of 6.8 m3
of
RKNGR catalyst, where all the higher hydrocarbons are reformed in to the H2, CO and CO2
as per reactions (i), (ii) and (iii).
Here carbon deposition is possible only in case of very low steam/carbon ratio (<1.5) or
in case of overheating of the feed (>540o
C), so ratio of 2.5 is maintained.
TUBULAR REFORMING
As higher hydrocarbons are no longer present in the gas leaving adiabatic pre-reformer,
it can be heated to 650o
C without risk of carbon formation due to thermal cracking. Here
most of the methane reforming takes place. The reaction is highly endothermic and the
heat of the reaction is supplied indirectly from furnace. The furnace consists of a single
row of 110 centrifugally cast tubes fabricated of high alloy of Cr-Ni steel. The tubes in the
furnace are heated by 180 nozzle burners arranged in 6 rows on each side of the furnace
to provide easy control of a uniform temperature along the length of the tubes.
The process gas flows downwards with the gas entering at the top of the vertically
mounted tubes f4rom a header through ‘hairpins’ at a temperature of about 650o
C. The
gas leaves the tubes at about 930o
C and enters directly into a refractory lined collector.
GAS PURIFICATION
The carbon oxides are removed before use by means of Pressure swing adsorption (PSA)
with molecular sieves for the final purification. The PSA works by adsorbing all impurities
from the syngas stream to leave a pure hydrogen gas. It relies on the fact that under high
pressure, gases tend to be attracted to solid surfaces, or "adsorbed". The higher the
pressure, the more gas is adsorbed; when the pressure is reduced, the gas is released, or
desorbed. PSA processes can be used to separate gases in a mixture because different
gases tend to be attracted to different solid surfaces more or less strongly.

50. 50
OFFSITE FACILITIES AND ITS MANAGEMENT
In a Refinery, 80% to 90% area is covered by offsite facilities. Traditionally, more
attention used to be given to process units. However, with Refinery margin shrinking,
stringent safety, Health and Environmental stipulations, and increased customer
expectations, now more and more emphasis is given for improved profitability through:
Major Offsite functions in a Refinery are
1. Crude oil receipt- Normally crude oil is received in land locked refineries through
crude pipelines from the production source. Before bringing the crude from oil
fields, gas, water and sludge are removed by settling and processing through
desalters. In coastal refineries, crude oil is received through tankers. Depending on
the capacity of the refinery, crude tankage available, draft available at receiving oil
jetty, size of crude oil tanker varies from small to very large. Quantity of crude
received in the refinery is monitored by measuring dip of receiving tank and flow
meter readings installed on crude pipeline. India imports almost 70% of its crude
oil requirement. Due to strategic reasons, crude oil storage is being increased from
15 days to 45 days of the refinery.
2. Crude preparation for feeding to distillation unit- Though in the oil field, major
quantity of sludge, water and associated salts are removed before bringing crude
to refineries, yet some quantities of sludge and water still are received in the
refinery tanks. This is removed by allowing the crude to settle in the tanks and
draining from bottom to the effluent treatment system. The final removal of water
associated with salts and sludge takes place in desalter in the crude distillation
unit. Unless crude preparation is done properly, the unit performance will be
affected adversely due to fouling of pipes, exchangers, furnace tube corrosion,
corrosion of various equipments and upsets in plant operation. This will also lead
to increased fuel consumption and loss in the units.
3. Receiving rundown streams from various units- From crude distillation unit and
other secondary units, we get various products streams, most of which are to be
treated in secondary processing units and blended in required proportion to
produce finished products which are then dispatched to the market. Except LPG

51. 51
and Naphtha, all other products are blends of various streams from different units.
Depending on the capacity of refinery, number of products marketed, types of
crude oil processed, complexity of the refinery, the tankages provided for receipt
of rundown streams varies. The facility for water draining and re-processing of
offspec. Streams are provided. Flexibility is also provided for alternative routing of
streams in case there is change in demand in product pattern. Light and heavy slop
tanks are also provided to receive offspec. Streams during start up, shutdown,
emergencies and upsets in the plants. The same are reprocessed in the units in a
regulated manner during normal run. By on-line blending and utilizing advanced
process control, the tankage for receiving rundown streams can be minimized.
Pump stations are provided for transfer of products.
4. Blending the rundown streams- Various straight run streams and secondary
processing units’ streams are mixed in suitable proportion for the production of
finished marketable petroleum products. The mixture is circulated in the tank to
make it of uniform quality. After settling in tank for draining any water and testing
the sample in the laboratory to ensure that it meets quality specifications, it is
dispatched to market. Storage facility at various locations particularly for MS, SKO
and HSD is being augmented. It is proposed to provide 35 days storage capacity
based on 75% utilization factor.
5. Co-ordination with laboratory- After blending of various streams and circulation in
tank, samples of products are sent to the laboratory for testing. Once the product
meets the quality specification as per BIS or customers requirement, then the
certificate of quality is issued by the laboratory. Thereafter, product is dispatched
to market.
6. Flare management- To take care of emergency release of gaseous hydrocarbon,
flare headers are provided for collecting off gases from process units and offsite
areas. After separating the entrained liquid, the gas is burnt at high point to avoid
hazard and pollution. Three categories of flare systems are provided. E.g. High/low
pressure flare, H2S flare.

52. 52
7. Refinery water supply
i. Fresh water supply system: This provides utility water supply, make up to
the circulating water system, make-up to fire water supply system and make
up to drinking water treatment system.
ii. Fire water supply system: Throughout the process units and off sites areas,
the fire water supply pipeline network is laid in the form of ring. Firewater
tanks are provided in off-sites area to have an immediate supply source for
fighting any major fire. In critical areas, long distance throw nozzles are
provided.
iii. Recirculating hot and cold water system: For cooling of hot products, this
system is provided. It is having chemical treatment system to avoid scaling
and corrosion in related pipelines and equipment. Cooling Towers are also
provided in the system where water is cooled by evaporation before
recirculation. Blow-down in the form of leakage and manual draining is
provided to avoid buildup of salt concentration. Make up water is taken
from fresh water system. In some of the coastal refineries, once through
cooling water system is used and sea water is utilized for the cooling of
products.
i.
8. Captive power plant: To provide uninterrupted power and steam supply for
running the pumps, compressors and other equipment, captive power plant is
provided in the refinery. For meeting any emergency, alternative source of power
supply from outside is also lined up. Superheated and saturated steams at various
pressures are also supplied for process units and off sites area from this system.
Steam is used for heating, stripping in columns, and atomization of fuel oil before
burning in furnace, fire-fighting, driving steam turbines and power generation.
Fresh water is used in DM plant before utilizing in boilers for steam generation. To
ensure supply of steam and power to critical plants/equipment in emergencies,
load shedding scheme exists.
9. Fuel oil and fuel gas system: For providing fuel supply to process units’ furnaces,
and boilers in captive power plant, this system is provided. In fuel gas, mostly
methane, ethane and purged gases from hydrogen units are used. The supply

53. 53
system is maintained at constant pressure. For fuel oil, varying range of fuels from
LDO to Asphalts is used. Storage tanks, blending facilities and pumping system are
provided for supply of fuel oil to furnaces and boilers.
10. Hydrogen, Nitrogen and air supply systems: Hydrogen is generated in Hydrogen
plant or catalytic reformer unit. It is utilized in hydro-treatment units. It is a very
hazardous gas to handle as the flame cannot be seen. Nitrogen is used for catalyst
regeneration, blanketing tanks from atmospheric oxygen in the case of lubes and
other products which form explosive mixture when coming in contact with air, and
maintaining inert atmosphere in the process unit equipment. Nitrogen is produced
in generators installed in the refinery or is purchased from outside. Air is used for
utility purposes, catalyst regeneration, decoking of furnace tubes and
instrumentation etc. It is taken from atmosphere and compressed before using.
Table:
Utility Unit Rupees/unit
Power Kwh 9.02
HP steam MT 1926.57
LP steam MT 174.67
MP steam MT 1824.66
Fresh water CUM 5.63
Circulating water CUM 1.73
DM water CUM 54.56
Compressed air CUM 2.65
Fuel Oil MT 38484
Fuel gas MT 32139