IOCL Vocational Training Report

Published on May 2016 | Categories: Types, Presentations | Downloads: 147 | Comments: 0 | Views: 827
of 27
Download PDF   Embed   Report

IOCL Barauni Report

Comments

Content

Submitted by:






Acknowledgement
Indian Oil History
Barauni Refinery: Introduction
Present Configuration






Basic Refinery Processes
Primary Processing Units
Atmospheric Distillation Unit
Vacuum Distillation Unit

 Coker Unit
 Catalytic Reforming Unit (CRU)
 BXP Unit
(RFCCU, DHDT, SRU, HGU)
 Prime G+
(NHDT, ISOM, SHU)
 Some Units IN Detail with PFD
 Typical product pattern
 Safety measures in Refinery

ACKNOWLEDGEMENT
It’s a great for being a part of IOCL which is the world’s 98 th largest
public corporation according to the FORTUNE GLOBAL’s 500 list and
amongst the top companies of India by FORTUNE INDIA 500 IN 2011.
This acknowldgement is a way by which I am getting the opportunity
to show the deep semse of gratitude and obligation to all the
people who hav e prov ided me with inspiration and guidance during
the preparation of the training report.
I would take this chance to thank Mrs.Krishna Kumari, Officer T&D ,
Mr. Kalyan Bagchi DM (T&D) ,Ms Nilu Rani (O.A, T&D) for prov iding us
with this wonderful opportunity to interact with the experts in Barauni
refinery. I would also like to express my sincere gratitude towards Mr.
C.V.Ingle, Production Manager for mentoring us throughout the
training period and all the learned employees who took pains to
quench my curiosity and shared their knowledge.
Last but not the least; I would like to thank my parents whose
encouragement and motiv ation was a constant source of strength
and without which it wouldn’t hav e been possible.

INDIAN OIL HISTORY
Indian Oil, the largest commercial enterprise of India (by sales
turn ov er), is India’s sole representativ e in Fortune's prestigious listing
of the world's 500 largest corporations, ranked 189 for the year 2004.
It is also the 17th largest petroleum company in the world. Indian Oil
has a sales turnov er of 1, 20,000 crores and profits of 8,000 crores.
Indian Oil has been adjudged second in petroleum trading among
the 15 national oil companies in the Asia-Pacific region. As the
premier National Oil Company, Indian Oil’s endeav or is to serv e the
national economy and the people of India and fulfill its v ision of
becoming an integrated, div ersified, and transnational energy
major.
Beginning in 1959 as Indian Oil Company Ltd, Indian Oil Corporation
Ltd. was formed in 1964 with the merger of Indian Refineries Ltd.
(Est.1958). As India's flagship national oil company, Indian Oil
accounts for 56% petroleum products market share, 42% national
refining capacity and 67% downstream pipeline throughput
capacity. IOCL touches ev ery Indian’s heart by keeping the v ital oil
supply line operating relentlessly in ev ery nook and corner of India. I t
has the backing of ov er 33% of the country’s refining capacity
as on 1 st April 2002 and 6523 km of crude/product pipelines across
the length and breadth of the country. IOCL’s v ast distribution
network of ov er 20000 sales points ensures that essential petroleum
products reach the customer at the right place and at the right time.
Indian Oil controls 10 of India's 18 refineries - at Digboi, Guwahati,
Barauni, Koyali, Haldia, Mathura, Panipat, Chennai, Narimanam &
Bongaigaon with a current combined rated capacity of 49.30 million
metric tonnes per annum (MMTPA) or 990 thousand barrels per day
(bpd). Indian Oil’s world-class R&D Centre has won recognition for its
pioneering work in lubricants formulation, refinery processes, pipeline
transportation, and bio-fuels. It has dev eloped ov er 2,100
formulations of SERVO brand lubricants and greases for v irtually all

conceiv able applications - automotiv e, railroad, industrial and
marine – meeting stringent international standards and bearing the
stamp of approv al of all major original equipment manufacturers.
The centre has to its credit ov er 90 national and international
patents. The wide range of brand lubricants, greases, coolants, and
brake fluids meet stringent international standards and bear the
stamp of approv al of all major original equipment manufacturers.
Indian Oil operates 17 training centres throughout India for upskilling, re-skilling, and
multi-skilling
of
employees
in
pursuit
of corporate excellence. Among these, the foremost learning
centres are Indian Oil Institute of Petroleum Management at
Gurgaon, Indian Oil Management Centre for Learning at Mumbai,
and Indian Oil Management Academy at Haldia, hav e emerged as
world-class training and management academies. Indian Oil Institute
of Petroleum Management, the Corporation's apex center of
learning,
conducts
adv anced management dev elopment
programs in collaboration with reputed institutes. It also offers a
unique mid-career International MBA programs in Petroleum
Management. Indian Oil aims at maintaining its leadership in the
Indian hydrocarbon sector by continuous assimilation of emerging
Information
Technology
and web-enabled
solutions
for integrating and optimizing the Corporation's hydrocarbon
v alue chain. It is has implemented an IT re-engineering project titled
Manthan, which includes an Enterprise Resource planning (ERP)
package which will standardize and integrate the Corporation's
business on a common IT platform through a robust hybrid wide area
network with appropriate hardware.

 Barauni Refinery, the second Public Sector Oil refinery of the
country, was built in collaboration with the erstwhile USSR &
limited Romanian participation.
 Inaugurated on 15 th Jan’65 by the then Hon’ble minister for
Petroleum & Chemicals, Prof. Humayun Kabir
 Located at a distance of approximately 120 km from Patna,
Bihar.
Facilities
• 16 nos. of Process Plants
• Offsite facilities including:
 Storage tanks
 Effluent Treatment Plant & Bio Treatment Plant
 Product dispatch facilities, including 3 nos. of gantries
• Captiv e Power Plant with:
 6 Boilers

: 5 X 75MT/hr+1X150MT/hr

 4 TG’s

: 1x 5.5 MW + 1X 12 MW + 1 X 12.5 MW +
1 X 20 MW

 2 Gas Turbines : 2X 20MW with HRSG (48MT/hr)

Present Configuration

Basic Refinery Processes
 Planning, Scheduling, Receipt & storage of crude oil
 Separation Processes
 Conversion Processes
 Treatment Processes
 Blending & Certification Processes
 Product storage & Dispatch operations
 Other refinery processes & Operations

Primary Processing Units
 The purpose of Primary unit is to separate the crude in to
different fractions through atm. & v ac. distillation.
 Important operations of AVUs:
 Crude desalting: Remov al of contaminants like salts,
water etc. from crude and can be compared with
human kidney.
 Crude pretopping: Remov al of lighter (E-1 gasoline/
K-1 Hy naphtha from crude to reduce load on main
fractionator.
 Atm. Distillation: Distillation of crude at atmospheric
pressure and remov al of lighter products up to gas
oil.

 Vac. Distillation: Distillation of crude in v acuum to
av oid thermal cracking at higher operating
temperatures.

Atmospheric Distillation Unit
Crude oil is sent to the atmospheric distillation unit after desalting
and heating. The purpose of atmospheric distillation is primary
separation of v arious 'cuts' of hydrocarbons namely, fuel gases, LPG,
naptha, kerosene, diesel and fuel oil. The heav y hydrocarbon
residue left at the bottom of the atmospheric distillation column is
sent to v acuum distillation column for further separation of
hydrocarbons under reduced pressure.
As the name suggests, the pressure profile in atmospheric distillation
unit is close to the atmospheric pressure with highest pressure at the
bottom stage which gradually drops down till the top stage of the
column.
The temperature is highest at the bottom of the column which is
constantly fed with heat from bottoms reboiler. The reboiler v aporizes
part of the bottom outlet from the column and this v apor is recycled
back to the distillation column and trav els to the top stage
absorbing lighter hydrocarbons from the counter current crude oil
flow. The temperature at the top of the column is the lowest as the
heat at this stage of the column is absorbed by a condenser which
condenses a fraction of the v apors from column ov erhead. The
condensed hydrocarbon liquid is recycled back to the column. This
condensed liquid flows down through the series of column trays,
flowing counter current to the hot v apors coming from bottom and
condensing some of those v apors along the way.
Thus a reboiler at the bottom and a condenser at the top along with
a number of trays in between help to create temperature and

pressure gradients along the stages of the column. The gradual
v ariation of temperature and pressure from one stage to another
and considerable residence time for v apors and liquid at a tray help
to create near equilibrium conditions at each tray.
The heav iest hydrocarbons are taken out as liquid flow from the
partial reboiler at bottom and the lightest hydrocarbons are taken
out from the partial condenser at the column ov erhead. For the in
between trays or stages, the hydrocarbons become lighter as one
mov es up along the height of the column. Various other cuts of
hydrocarbons are taken out as sidedraws from different stages of the
column. Starting from LPGat the top stages, naptha, kerosene, diesel
and gas oil cuts are taken out as we mov e down the stages of
atmospheric column.

Vacuum Distillation Unit
Crude oil is first refined in an Atmospheric Distillation Column.
Fractions of crude oil such as lighter gases (C1-C4), gasoline,
naphtha, kerosene, fuel oil, diesel etc. are separated in the
atmospheric distillation column. The after taking out these lighter
hydrocarbon cuts, heav y residue remaining at the bottom of the
atmospheric distillation column needs to be refined. These heav y
hydrocarbon residues are sent to a Vacuum Distillation Column for
further separation of hydrocarbons under reduced pressure.
Heav ies from the atmospheric distillation column are heated to
approximately 400˚C in a fired heater and fed to the v acuum
distillation column where they are fractionated into light gas oil,
heav y gas oil and v acuum reside. Some heav y hydrocarbons
cannot be boiled at the operating temperature and pressure
conditions in the atmospheric distillation column. Hence they exit the
bottom of the column in liquid state and are sent to the v acuum
distillation column where they can be boiled at a lower temperature

when pressure is significantly reduced. Absolute operating pressure in
a Vacuum Tower can be reduced to 20 mm of Hg or less
(atmospheric pressure is 760 mm Hg). In addition, superheated
steam is injected with the feed and in the tower bottom to reduce
hydrocarbon partial pressure to 10 mm of mercury or less. Lower
partial pressure of the hydrocarbons makes it ev en more easier for
them to be v aporized, thus consuming less heat energy for the
process.
Two different cuts of hydrocarbons - 'light v acuum gas oil' and
'heav y v acuum gas oil' are separated in the v acuum distillation
column at different stages of the column, based on the difference
between their boiling point ranges. The liquid being drawn at low
pressure needs to be pumped. Then it is heated and partially
recycled back to the column. Part of it is taken out as v acuum
distillation products - 'light v acuum gas oil' or 'heav y v acuum gas oil'.
Light v acuum gas Oil is sent to a hydrotreater and then to a
'catalytic cracking' unit to obtain smaller chain hydrocarbons. Heav y
v acuum gas oil is also sent for cracking using hydrogen in a
'hydrocracking unit' to produce smaller chain hydrocarbons.
Heav y hydrocarbons which cannot be boiled ev en under reduced
pressure remain at the bottom of the column and are pumped out
as 'v acuum residue'. The v acuum distillation column bottom residue
can only be used for producing coke in a 'coker unit' or to produce
bitumen.

Coker Unit
Coking is a refinery unit operation that upgrades material called
bottoms from the atmospheric or v acuum distillation column into
higher-v alue products and, as the name implies,
produces petroleum coke—a coal-like material.
Petroleum coke has uses in the electric power and industrial sectors,
as fuel inputs or a manufacturing raw material used to produce
electrodes for the steel and aluminum industries. In 2011, the refining
industry supplied 132 million barrels of petroleum coke with most of it
subsequently consumed as fuel.
Two types of coking processes exist—delayed coking and fluid
coking. Both are physical processes that occur at pressures slightly
higher than atmospheric and at temperatures greater than 900 oF
that thermally crack the feedstock into products such as naphtha
and distillate, leav ing behind petroleum coke. Depending on the
coking operation temperatures and length of coking times,
petroleum coke is either sold as fuel-grade petroleum coke or
undergoes an additional heating or calcining process to produce
anode-grade petroleum coke.
With delayed coking, two or more large reactors, called coke drums,
are used to hold, or delay, the heated feedstock while the cracking
takes place. Coke is deposited in the coke drum as a solid. This solid
coke builds up in the coke drum and is remov ed by hydraulically
cutting the coke using water. In order to facilitate the remov al of the
coke, the hot feed is div erted from one coke drum to another,
alternating the drums between coke remov al and the cracking part
of the process. With fluid coking, the feed is charged to a heated
reactor, the cracking takes place, and the formed coke is
transferred to a heater as a fluidized solid where some of it is burned
to prov ide the heat necessary for the cracking process. The
remaining coke is collected to be sold.
Like other secondary processing units, coking can play an important
role in refinery economics depending on the type and cost of the
crude oil run at a refinery. As the quality of crude oil inputs to a
refinery declines, coupled with greater demands for transportation

fuels, coking operations will serv e to meet transportation fuel
demands and also produce increasing quantities of fuel-grade and
anode-grade or needle petroleum coke.

Catalytic Reforming Unit (CRU)
Catalytic reforming is a major conv ersion process in petroleum
refinery and petrochemical industries. The reforming process is a
catalytic process which conv erts low octane naphthas into higher
octane reformate products for gasoline blending and aromatic rich
reformate for aromatic production. Basically, the process re-arranges
or re-structures the hydrocarbon molecules in the
naphtha feedstocks as well as breaking some of the molecules into
smaller molecules. Naphtha feeds to catalytic reforming include
heav y straight run naphtha. It transforms low octane naphtha into
high-octane motor gasoline blending stock and aromatics rich in
benzene, toluene, and xylene with hydrogen and liquefied
petroleum gas as a byproduct. With the fast growing demand
in aromatics and demand of high - octane numbers, catalytic
reforming is likely to remain one of the most important unit processes
in the petroleum and petrochemical industry.
Basic steps in catalytic reforming involve
1) Feed preparation: Naphtha Hydrotreatment
2) Preheating: Temperature Control,
3) Catalytic Reforming and Catalyst Circulation and Regeneration in
case of continuous reforming process
4) Product separation: Remov al of gases and Reformate by
fractional Distillation
5) Separation of aromatics in case of Aromatic production
REACTIONS IN CATALYTIC REFORMING
Following are the most prev alent main reactions in catalytic
reforming

Desirable
Dehydrogenation of naphthenes to aromatics
Isomerisation of paraffins and naphthenes
Dehydrocyclisation of paraffins to aromatics
Non-Desirable
Hydrocracking of paraffins to lower molecular weight compounds
Dehydrogenation & Dehydrocyclization: Highly endothermic, cause
decrease in
temperatures, highest reaction rates, aromatics formed hav e high
B.P so end point of gasoline
rises
Dehydrogenation reactions are v ery fast, about one order of
magnitude faster than the other
reactions. The reaction is promoted by the metallic function of
catalyst
Methyl cyclohexane
Toluene + H2
MCP Benzene + H2
Dehydrocyclisation: It inv olv es a dehydrogenation with a release of
one hydrogen mole
followed by a molecular rearrangement to form a naphthene and
the subsequent dehydrogenation of the naphthene. i-paraffins to
aromaticsof paraffins
n-heptane , toluene + H2
Favourable Conditions: High temperature, Low pressure, Low space
v elocity, Low H2/HC ratio
Isomerisation: Branched isomers increase octane rating, Small heat
effect, Fairly rapid reactions.
Favourable Conditions: High temperature, Low pressure, Low space
v elocity, H2/HC ratio no significant effect
Naphthenes dehydro-Isomerisation: A ring re-arrangement reaction,
Formed alkyl-cyclohexane dehydrogenate to aromatics.• Octane
increase is significant, Reaction is slightly exothermic

BXP Units

RFCCU

A Residue FCC (RFCC) unit expands the versatility and profitability of
an FCC to crack a wider variety of feedstock:


Traditional FCC feedstocks



Deeply Deasphalted Oil



Atmospheric Residue

Vacuum Residue
The quality of the feed is the main determinant of the yields and
product properties. The yield of v aluable gasoline and LPG products
in the FCC unit will be mainly influenced by the hydrogen content of
the feed. Feed contaminants such as sulfur, nitrogen, Conradson
Carbon Residue (ConC) and metals also impact the yield and/or
product quality. As a result it is often adv antageous to either partially
or fully hydrotreat the feedstock to improv e the hydrogen content
and reduce the lev el of contaminants.
When processing residues containing high lev els of metals (Ni, V and
Na) and ConC v alues of 3-10 wt%, more sophisticated FCC designs
are required. The reaction section will be designed to inject and
efficiently crack heav ier molecules. The regenerator section is


designed to burn more coke, minimize catalyst deactiv ation in the
presence of high metals loading on the catalyst, and control the
heat balance by using a two-stage regenerator design (R2R).
For expanded product flexibility, the RFCC unit can be integrated
with upstream units such as resid hydrotreating/hydrocracking to
balance the gasoline and distillate products, or downstream units
such as Polynaphtha (FlexEne™concept) in order to offer higher
flexibility toward targeted products (Gasoline, Diesel or Propylene).

Diesel Hydrotreating Unit (DHDT)
Objective : To meet the Euro –III/IV diesel quality requirement (
350/50 ppm‘S’and Min. 51 Cetane No.)
 Feed : Straight run diesel / FCC diesel component/ Coker and
Visbreakerdiesel components.
 Catalyst : Ni-Mo oxides
 Chemical reactions: Desulphurisation and Denitrification
In Dieselhydrodesulfurization / hydrotreating process, diesel feed is
mixed with recycle Hydrogen ov er a catalyst bed in a trickle bed
reactor at temperature of 290-400°C and pressure of 35-125 bar. The
main chemical reactions in DHDS/DHDTare
hydrodesulphurization(HDS), hydrodenitrification (HDN), and
aromatic and olefin saturation. These reactions are carried on bifunctional catalysts. Reactor effluent is separated into gas and liquid
in a separator. Gas is recycled back to the reactor after amine wash
along with make-up Hydrogen and liquid is sent to the stripper for
remov al of light gases and H2S.
Advantages:
 Indigenous Process design& technology
• Capable of producing ultra low Sulfur meeting BS-IV diesel
specifications

• Proprietary Reactor internals. • Competitiv e with foreign
licensors
• Proprietary DHDS/DHDT catalyst system so as to offer a
complete package.
• Design and Engineering experiences of EIL

Sulphur Recovery Unit (SRU)
Sulphur remov al facilities are located at the majority of oil and gas
processing facilities throughout the world. The sulphur recov ery unit
does not make a profit for the operator but it is an essential
processing step to allow the ov erall facility to operate as the
discharge of sulphur compounds to the atmosphere is sev erely
restricted by env ironmental regulations.
The basic Claus unit comprises a thermal stage and two or three
catalytic stages.
Typical sulphur recov eries efficiencies are in the range 95-98%
depending upon
the feed gas composition and plant configuration
H2S + 1½O2 > SO2 + H2O (1)
2H2S + O2 <-> 3/x Sx + 2 H2O (2)
Some of the H2S in the feed gas is thermally conv erted to SO2 in the
reaction furnace of the thermal stage according to reaction (1). The
remaining H2S is then reacted with the thermally produced SO2 to
form elemental sulphur in the thermal stage and the subsequent
catalytic stages according to reaction (2). Claus reaction (2) is
thermodynamically limited and has a relativ ely low equilibrium
constant for reaction (2) ov er the catalytic operation region.
As the feed acid gas normally contains other compounds, which
could include carbon dioxide, hydrocarbons, mercaptans and
ammonia, the actual chemistry in the furnace is v ery complex.

 The hot combustion products from the furnace at 1000- 1300°C
enter the
waste heat boiler and are partially cooled by generating
steam. Any steam lev el from 3 to 45 bar g can be generated.
 The combustion products are further cooled in the first sulphur
condenser,
usually by generating LP steam at 3 – 5 bar g. This cools the gas
enough to condense the sulphur formed in the furnace, which is
separated from the gas and drained to a collection pit.
 In order to av oid sulphur condensing in the downstream
catalyst bed, the gas leav ing the sulphur condenser must be
heated before entering the reactor.
 The heated stream enters the first reactor, containing a bed of
sulphur conv ersion catalyst. About 70% of the remaining H2S
and SO2 in the gas will react to form sulphur, which leav es the
reactor with the gas as sulphur v apour.
 The hot gas leav ing the first reactor is cooled in the second
sulphur condenser, where LP steam is again produced and the
sulphur formed in the reactor is condensed.
 A further one or two more heating, reaction, and condensing
stages follow to react most of the remaining H2S and SO2.
 The sulphur plant tail gas is routed either to a Tail Gas treatment
Unit for further processing, or to a Thermal Oxidiser to incinerate
all of the sulphur compounds in the tail gas to SO2 before
dispersing the effluent to the atmosphere

MSQ UNIT
It consists of:
1. PRIME G+
2. NHDT
3. ISOM

Prime G+
The Prime-G+ process relies on unriv alled expertise to prov ide the
most appropriate catalytic solution based on simple and robust
designs that can achiev e the following targets:
 Very high desulfurization rate with good octane retention


Excellent gasoline yield retention without RVP increase (no
cracking reactions)



Minimum hydrogen consumption



High operational reliability through a tailor-made conv entional
hydrotreatment



Low capital cost inv estment through a simple fixed bed
technology



High catalyst cycle length that keeps the unit running 100% of the
FCC turnaround



Fully regenerable catalysts (in-situ or ex-situ) at low contaminant
lev els



Ability to co-process other sulfur-rich streams such as light coker,
v isbreaker, straight run or steam cracker naphthas



Ability to retrofit existing assets
Axens Prime-G+ offer is particularly flexible allowing different process
configurations (schemes with or without
splitter, 1st stage or 2nd stage selectiv e HDS unit) to best fit the
gasoline pool requirement and also maximize refinery profitability.
Although the naphtha splitter may be optional depending on the
required HDS sev erity, the preferred arrangement for minimization of
octane loss is a scheme with the association of a Prime-G+ selective
hydrogenation unit (SHU) and a splitter, the so called the "Prime-G+
1st Step" for light naphtha desulfurization and sweetening. It ideally
complements the selectiv e HDS on the heav ier fraction that
outperforms all other processes.

All Prime G+ catalysts present a low sensitivity to impurities and
excellent stability suitable for the processing of cracked feedstock
due to their optimized metal content and highly neutral carrier.
Specific grading materials dev eloped by Axens are often installed at
the top of reactor catalytic beds in order to extend catalyst cycle
lengths when processing highly reactiv e cracked feedstocks.
Depending on the crude, FCC gasoline can contain arsenic which is
a poison for all hydrotreatment catalysts. In the case of sev ere
contamination, Axens can offer to install as part of the grading
material a dedicated trapping mass which deliv ers v ery high arsenic
retention without olefin saturation to preserv e the octane of the
desulfurized FCC gasoline product.

Selective Hydrogenation Unit
(SHU)
Unsaturated LPG cuts from FCC and coker or Steam Cracking units
contain unwanted dienes and/or acetylenes that need to be
remov ed before further treatment.
It’s used for upgrading unsaturated LPG cuts; by conv erting
butadiene and MAPD, it greatly enhances the performance of
downstream units.
Here treatment of unsaturated LPG is required. Depending on the
downstream utilization of LPG cuts it can be used
 at low sev erity for selectiv e butadiene/MAPD hydrogenation
 at higher sev erity to promote Hydroisomerization of 1-butene to 2butene.
Whatev er the application, special attention is paid during design to
minimize losses of v aluable olefins.
A series of catalysts is av ailable to ensure high activ ity and optimum
selectiv ity throughout the run cycle. It is important to make the

choice of catalyst in conjunction with the contaminants (e.g. sulfur)
that are often present in cracked feedstock.
This technology can be used to treat C3, C4 or combined C3 and
C4 olefinic cuts.

Naphtha Hydrotreatment Unit
(NHDT)
Naphtha hydrotreatment is important steps in the catalytic reforming
process for remov al of the v arious catalyst poisons. It eliminates the
impurities such as sulfur, nitrogen, halogens, oxygen, water, olefins, di
olefins, arsenic and other metals presents in the naphtha feed stock
to hav e longer life catalyst..
* Sulphur: Mercaptans, disulphide, thiophenes and poison the
platinum catalyst. The sulphur content may be 500 ppm.
*Maximum allowable sulphur content 0.5 ppm or less and water
content <4 ppm.
*Fixed bed reactor containing a nickel molybdenum where both
hydro desulphurisation reactions and hydro de nitrification reactions
take place.
*The catalyst is continuously regenerated. Liquid product from the
reactor is then stripped to remov e water and light hydrocarbons.
Various sections in the naphtha hydro treatment unit are:
Charge Heater: Preheating reactor feedstock to reaction
temperature of 340 oC. Charge heater has four passes four gas
burners. Heater tubes are made up of SS-321
Reaction Section: The reactor consists of two catalyst beds.
Stripping Section: Stripping section uses air for stripping the light ends
mainly hydrogen sulfide from reactor product, stripper temperature
14 kg/ cm2 and temp. 172 0C
Stripper Reboiler: Stripper reboiler supply heat required for striper
Operating Variables Naphtha Hydrotreatmernt
*Reactor temperature
*Space v elocity

*Hydrogen partial pressure
*H2/HC ratio, feed quality
*Stripper bottom temperature

Isomerization Unit (ISOM)
Isomerization is a process in petroleum refining that conv erts nbutane, n-pentane and n-hexane into their respectiv e isoparaffins of
substantially higher octane number. The straight-chain paraffins are
conv erted to their branched-chain counterparts whose component
atoms are the same but are arranged in a different geometric
structure. Isomerization is important for the conv ersion of n-butane
into isobutane, to prov ide additional feedstock for alkylation units,
and the conv ersion of normal pentanes and hexanes into higher
branched isomers for gasoline blending. Isomerization is similar
tocatalytic reforming in that the hydrocarbon molecules are
rearranged, but unlike catalytic reforming, isomerization just conv erts
normal paraffins to isoparaffins.
Butane isomerization produces feedstock for alkylation. Aluminum
chloride catalyst plus hydrogen chloride are univ ersally used for the
low-temperature processes. Platinum or another metal catalyst is
used for the higher-temperature processes. In a typical lowtemperature process, the feed to the isomerization plant is n-butane
or mixed butanes mixed with hydrogen (to inhibit olefin formation)
and passed to the reactor at 230°-340° F and 200-300 psi. Hydrogen
is flashed off in a high-pressure separator and the hydrogen chloride
remov ed in a stripper column. The resultant butane mixture is sent to
a fractionator (deisobutanizer) to separate n-butane from the
isobutane product.

Pentane/hexane isomerization increases the octane number of the
light gasoline components n-pentane and n-hexane, which are
found in abundance in straight-run gasoline. In a typical
C5/C6 isomerization process, dried and desulfurized feedstock is
mixed with a small amount of organic chloride and recycled
hydrogen, and then heated to reactor temperature. It is then passed
ov er supported-metal catalyst in the first reactor where benzene and
olefins are hydrogenated. The feed next goes to the isomerization
reactor where the paraffins are catalytically isomerized to
isoparaffins. The reactor effluent is then cooled and subsequently
separated in the product separator into two streams: a liquid
product (isomerate) and a recycle hydrogen-gas stream. The
isomerate is washed (caustic and water), acid stripped, and
stabilized before going to storage.

Some Refinery Units In Detail
With PFD’s and Explanation :
1. AVUs
2. BXPs
 RFCCU
 DHDT
 HGU
 SRU
3. CRU
4. MSQ
 NHDT
 ISOM
 PRIME G+

Typical Product Pattern

1.12
0.82

0.80%

2.23%

0.20%

4.86%

3.97%
15.29%

48.65%
13.1%

LPG
RPC

SRN
Bitumen

MS
FO

SKO
CBFS

HSD
Sulphur

Safety Measures in Refinery











Process interlocks
Work permit systems
Personal Protectiv e Equipment (PPE)
Special height and fire permit
Gas detector
Safety training
Standing instructions
Firefighting equipments
Material Safety Data Sheet (MSDS)
Safety relief systems

Sponsor Documents

Or use your account on DocShare.tips

Hide

Forgot your password?

Or register your new account on DocShare.tips

Hide

Lost your password? Please enter your email address. You will receive a link to create a new password.

Back to log-in

Close