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AN INDUSTRIAL REPORT
ON
M/s THE HINDUSTAN PETROLEUM CORPORATION LIMITED
VISAKH REFINERY
Submitted in partial fulfillment of requirements under
Mini-project for the award of
B.TECH IN CHEMICAL ENGINEERING
Submitted by
A.KARTHIK (10131A0803)
D.VINAY KUMAR (10131A0816)
U.SRI VENU GOPAL (10131A0849)
DEPARTMENT OF CHEMICAL ENGINEERING
Gayathri vidya Parishad College of engineering-530041
(MAY 03rd,2013 -30th MAY, 2013)
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INDEX
 INTRODUCTION
Page No.
5
 CRUDE HISTORY
8
 OVERVIEW OF REFINERY PROCESSES
10
 DETAILED PROCESS DESCRIPTIONS
 CDU
18
 FCCU
22
 VBU
28
 BBU
32
 DHDS
35
 VRCFP Units
 NHT
 CCR
 NIU
 FCC NHT
41
42
43
44
Page 3 of 42
INTRODUCTION:
Company Profile:
HPCL is a mega public sector undertaking (PSU) and is second largest integrated oil company with Navrathna Status. This refinery is located at latitude of 17’41” North and longitude of 83'17” East on an area taken on a 99 years lease from Visakhapatnam port trust.
Visakha refinery was established in 1957 as Caltex oil refining India Ltd., (CORIL). This
was the first oil refinery on the East Coast and the first major industry in the City of Visakhapatnam, HPCL came into being in mid 1974 after take over and the merging of Erst
while Esso and Lube India in 1976 and was subsequently merged with HPCL kosan Gas
Company in 1978. HPCL thus came into being after merged four different organizations
at different parts of time.
Visakha refinery covering an area of 515 acres of area is situated at Visakha 1 km (North
West) from the foot of Yarada hills. The refinery is flanked by HPCL terminal and HPCL
LPG bottling plant on the eastern side coromandal Fertilizers on the western side, Residential colonies on the Southern side, APL, EIPL in the Northern side. HPCL has an additional Tankage Project (ATP), which is on the Northern side of the refinery covering an
area of 215 acres.
HPCL has nearly 20% refining capacity and the market share and a commixture market
infrastructure. It operates two major refineries, one at Mumbai and other at Visakhapatnam. Its lube refinery at Mumbai is the largest in the country with a capacity of 3,
33,500TPA, which is nearly 40% of the country’s total lube refining capacity.
Visakha refinery has an initial capacity installed capacity of 0.675 MMPTA in 1957. The
crude capacity was raised to 1.5MMTPA through put level over a period of years by various modifications. The crude processing capacity was further expanded to 4.5 MMTPA
level during 1985 by commissioning separate stream of 3.0 MMTPA CDU, FCCU and
related utilities off site facilities at high seas (off shore tank terminal) and associated tank
age and product dispatch facilities by utilizing available space in a integrated manner and
these facilities was with state of all control system for better and efficient operation.
In order to cater to the increased LPG consumption in the region refinery was instrumental in developing first LPG import facilities on the east coast in 1987. As a step
towards surmounting the frequent power disruptions and to improve reliability of utilizes a
captive power plant (CPP) of 14MW capacity was commissioned in 1991. Refinery in its
efforts for product value addition and widening its product range commissioned Propylene
recovery unit (PRU) in 1992. In order to adhere to meet stringiest environment norms the
refinery had set up effluent treatment plant (ETP) in 1993 and sculpture recovery plant
(SRU) in 1994.with the second major expansion project VREP-II completed in 1999,
crude capacity was increased from 4.5MMTPA and secondary processing capacity increased from 1.0 MMTPA to 1.6MMTPA. TO meet the additional power requirement of
these new units CPP capacity was augmented by 40 MW in 1999 by increasing total pow-
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er generation capacity to 50MW. To meet the stringent diesel fuel specifications Diesel
Hydro Desulphurization (DHDS) units was also commissioned in 2000.
HPCL markets entire range of petroleum products from the lightest of LPG to the
heaviest of Bitumen including 200 grades of tubes and greases. The product state of the
refinery includes light distillates, which constitutes 22. %Wt on crude basis consisting of
Liquefied Petroleum Gas (LPG), Naphtha, Propylene, Motor Spirit ,Gasoline/ Petrol , and
Middle distillates which constitutes 52 Wt% on crude basis consisting of Mineral Turpentine Oil (MTO), Aviation Turbine Fuel (ATF) ,Jute Bleaching Oil(JBO), Superior Kerosene Oil(SKO), High Speed Diesel (HSD), Wash Oil, Light Diesel Oil (LDO), and Heavy
ends constituting 18wt % on crude basis consisting of Fuel Oil (FO), Low Sulphur Heavy
Stock (LSHS) and Bitumen. The majority business in retail sales with volume of MS and
HSD accounting for 49% of the total followed by the industrial sales of over 30% HPCL is
one of the two companies in India which own cross country product pipelines.
Configuration of the refinery:
SL.NO
PROCESS UNITS
CAPACITY
1.
2.
3.
4.
5.
CRUDE DISTILLATION UNIT-I
CRUDE DISTILLATION UNIT-II
CRUDE DISTILLATION UNIT – III
FLUIDISED CRACKING UNIT- I
FLUIDISED CRACKING UNIT- II
1.5 MMTPA
3.0 MMTPA
3.0 MMTPA
0.95 MMTPA
0.6 MMTPA (Being
revamped
to
1
MMTPA)
6.
PROPYLENE RECOVERY UNIT
PRODUCT TREATMENT UNITS
23,000 TPA
7.
LPG ATU& MEROX
GASOLENE MEROX & ATF MEROX
368,000TPA
256,000TPA
8.
9.
VISBREAKER UNIT(VBU)
BITUMEN BLOWING UNIT
DHDS
1.0 MMTPA
225,000 TPA
2.43 MMTPA
10.
CAPACITIES OF THE NEW UNITS INSTALLED UNDER VRCFP:
S.NO
UNIT
CAPACITY,
TPD
CAPACITY,
MMTPA
1
2
3
4
5
6
Naphtha Hydro treater Unit
Naphtha Splitter
Catalytic Reformer
Naphtha Isomerisation unit
FCC Gasoline Splitter
FCC Gasoline Hydro treating Unit
3462
3462
2341
1150
2680
1388
1.154
1.154
0.78
0.38
0.89
0.46
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AUXILIARY UNITS:
SL AUXILIARY UNITS
NO
1.
CPP ( GTG – I & II)
HRSG – I & II
2.
CPP (GTG – III & IV)
HRSG – III & IV
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
CAPACITY
2x9 MW at ISO conditions
2x28 TPH
2x25 MW at ISO conditions
2x60 TPH AT 12.5kg/cm²
PP – I (WIL BOILER & BHPV BOILER)
PP – II (2 WIL BOILER)
CO BOILER
CO BOILER – II
H2UNIT
SRU – I
SRU – II
SRU , DHDS
SWSU
ETP – I
ETP – II
2x50 TPH @ 28.0Kg/ cm²
2x50 TPH AT 38 kg/cm²
60 TPH
40 TPH
25,000 Nm3/hr
16 LTPD
32 LTPD
2x65 TPD
99.4 m3/hr
135 m3/hr
100 m3/hr – Stream-A
173 m3/hr -Stream-B
1.8 m3/hr-Stream-C
Daily production:
CRUDE PROCESSED
LPG
PROPYLENE
DIESEL
NAPHTHA
LSHS
FUEL OIL
ASPHALT
SULPHUR
Capacity in Tonnes
22500
610
100
7800
2150
1790
3500
15
17+65
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CRUDE HISTORY
Crude is a highly complex mixture of hydrocarbons and primarily contains Hydrogen and
Carbon. The main types of hydrocarbons present in crude petroleum are paraffin’s
(CnH2n+2), olefins (CnH2n), Napathenes ((CnH2n-2) and aromatics ((CnH2n-6) although dilphinia ((CnH2n-2) and other cuclic series hydrocarbons may find themselves in some
crudes. Small quantities of other elements which are considered as impurities are like sulphur, Nitrogen, Oxygen and some metal traces are also present in crude. Certain light
crude fractions know as mercaptans impart undesirable odor and corrosiveness to light
crude fractions. Hydrogen sulphide, water and common salt are also undesirable constituents of crude oil, which affect the efficiency of the operations and spoil the refinery
equipment.
Types of crudes:
Crudes oils are classified in various ways:
(a) Based on the types of series of hydrocarbons present in crude.
(i)
(ii)
Paraffin basic crudes: The crudes consist of mainly of paraffin hydrocarbons but less or no asphaltic matter. They usually give good yields of paraffin wax, high, high-grade kerosene and high grade lubricating oil.
Napthene base crudes: These crudes contain little or no paraffin wax but
asphaltic matter is usually present in large proportions, they yield lubricating oils, whose viscosities are more sensitive to temperature than those
from paraffin based crudes, but which can be suide equivalent to the later
by special refining methods. These crudes are particularly suitable for
marketing high quality Gasoline, machine lubricating oils and asphalt.
Mixed base crudes: These crudes contain substantial proportions of both
paraffin wax and asphaltic matter together with a certain proportions of aromatic hydrocarbons.
(iii)
(b)Based on the Sulphur Content:
(i)
High Sulphur / sour Crudes: These crudes are also known as sour crudes. These
are crudes with higher sulphur content and the heavier ends of these crudes are
normally absorbed in fuel oil. Most of the High Sulphur Crudes which Visakh
refinery is processing yield low aromatic Naphtha with high paraffins content
and most of the crudes are Bituminous and also bear Aviation Turpentine oil
Eg., Kuwait, Dubai, Arab mix Etc
(ii) Low sulphur/ sweet crudes: These crudes are with relatively low sulphur
content and hence called sweet crudes Ravva crudes are the sweetest crudes yield
Naphtha with relatively higher aromatic compounds and higher octane member
through they differ in the degree source of the low sulphur crudes have very high pour
point like Ravva, Bombay high etc which may demand for higher costs while handling. Eg, Lubruan, Bombay high Ravva etc.,
(c) Based on Apt Gravity
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(i)
(ii)
Crudes with low Density (High APT gravity) is called light crudes.
Crudes with high density (low APT gravity) are called heavy crudes.
Crudes may also be classified mainly into indigenous and imported. Bombay high,
Ravva are the main indigenous crudes Visakh refinery normally processes, while most of
our throughput is attainted on imported crudes like Qiboe, Labuan, Mirri light, Kuwait,
upper zakum, Arab mix etc.
Entire Ravva crude oil produced in Krishna Godavari basin is being refined in Visakh refinery only.
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Overview of Refinery Processes:
The crude consists of all petroleum products, which can be separated by simple
Distillation. This separation of products can be performed using their boiling range (differences in their boiling points). Compounds having lower boiling point easily evaporate
from the crude oil and the vapor moves up in the distillation column. It will be condensed
there and converted to liquid and can be collected there. This is the technique used in any
simple distillation process.
To carry out this simple distillation process a unit called Crude Distillation Unit is required. Crude Distillation Unit (CDU) is the Primary Unit of the refinery.
From CDUs we will get different petroleum products present in the Crude oil. But these
products may not be as good as we want. Simple Distillation may not produce products of
good quality and quantity. We need some Secondary Units to give some value addition to
the products that we got from CDUs. Fluidized Catalytic Cracking Unit (FCCU) is a
secondary unit in which the Vacuum Gas Oils produced in CDU can be processed to get
some useful products.
Vis Breaking Unit (VBU), Bitumen Blowing Unit (BBU) are also Secondary units.
Sometimes, the products coming from Primary and Secondary Units may not meet the required specifications of their properties. To meet these specifications, some Treating Units
are required. For example, Diesel streams coming from CDU and FCCU are to be desulfurized to meet the EURO specifications. For this a Treating Unit called Diesel Hydro Desulphurization Unit (DHDS) is required.
Primary Unit:
 Crude Distillation Unit (CDU)
Secondary Units:
 Fluidized Catalytic Cracking Unit (FCCU)
 Vis breaking Unit (VBU)
 Bitumen Blowing Unit (BBU)
Treating Units:
 Diesel Hydro Desulphurization Unit (DHDS)
 VRCFP units

Naphtha Hydro Treater (NHT)

Continuous Catalytic Reformer (CCR)

Naphtha Isomerization Unit (NIU)

FCC Naphtha Hydro treater (FCC NHT)
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Primary Unit:
CRUDE DISTILLATION UNIT
OBJECTIVE
To carry out distillation and get various products (separation based on Boiling point of the
mixtures).
CDU can process both High Sulphur and Low Sulphur Crudes .
Feed to CDUs : Crude oil (High Sulphur or Low Sulphur)
Capacity:
Visakh Refinery has three Crude Distillation Units . Two having capacity of 3 MMTPA
and one having capacity of 1.5 MMTPA.
CDU-I
-
1.5 MMTPA
CDU-II
-
3 MMTPA
CDU-III -
3 MMTPA
Secondary Units:
 FLUIDIZED CATALYTIC CRACKING UNIT (FCCU)
OBJECTIVE:
Value addition to the products by converting long chain, high molecular compounds to
light weight products.
Catalytic cracking is more efficient than Thermal cracking. Because it gives high quality
Gasoline and other products and it yields less gas like methane, ethane and ethylene.
The catalyst acts as a medium for heat transfer from one zone to another zone.
Feed to FCCUs:
Vacuum Gas Oils from Vacuum Column
Capacity:
Visakh refinery has two Fluid Catalytic Cracking Unit with a capacity of 0.95 MMTPA
and 0.6 MMTPA.
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FCCU-I --- 0.95 MMTPA
FCCU-II --- 0.6 MMTPA
The unit can be broadly classified into 3 sections. They are
 Catalyst section
 Fractionator section
 Gas concentration section
The reaction takes place in the catalyst section and resultant product is fractionated into
different products in the fractionator section, which are concentrated into final products in
the gas concentration section.
 VIS BREAKING UNIT
OBJECTIVE:
To reduce the viscosity of Short Residue (SR) by mild thermal cracking of vacuum residue
and to obtain the lighter product through conversion.
VBU reduces cutter consumption.
Feed to VBU:
Vacuum Residue from CDUs
Capacity:
Visakh refinery has a VBU with capacity of 1MMTPA

BITUMEN BLOWING UNIT
OBJECTIVE:
To obtain different grades of Bitumen
Feed to BBU: Short Residue
Capacity: BBU -- 0.225 MMTPA
The bitumen process a precisely controlled oxidation process is used to produce bitumen
of the highest quality from different types of feedstocks. The process can be operated in
batch as well as in continuous mode. It is most effective if operated in continuous mode
because of the proprietary agitator concept this bitumen process has the following advantages compared to the conventional blowing process.
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Treating Units:
 DHDS UNIT:
OBJECTIVE:
Desulphurize Diesel to meet EURO standards.
Here removed sulphur from diesel can be sold commercially for different purposes.
The sulfur recovered in the form of H2S by regeneration of rich amine and sour water
stripping. The H2S rich gases thus obtained are further processed for recovery of elemental
sulfur before letting the net gases to atmosphere.
Feed to DHDS:
Diesel from CDUs and FCCUs (1.6% wt. Of sulphur)
DHDS Unit consists of four major sections




DHDS reaction section
Amine absorption section
Stripping section
Naphtha stabilizing section
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VISAKH REFINERY CLEAN FUELS PROJECT (VRCFP)
 Naphtha HydroTreater (NHT)
OBJECTIVE
The Purpose of Naphtha Hydro Treating Unit is to protect the Reforming / Isomerisation
catalysts by reducing the impurities of the naphtha to an acceptable level.
Straight Run naphtha from CDUs is hydrotreated in “Naphtha Hydro Treating Unit”. The
treating is achieved by passing the naphtha over a fixed catalyst bed in an adiabatic reactor
in the presence of hydrogen. The hydro treated naphtha will be routed to Naphtha Splitter
Unit. Sulphur content in the feed should be less than 500 ppm. Catalyst used here is
Ni+Mo.
Feed: Straight Run Naphtha
Products:
Light Naphtha
Heavy naphtha
 Continuous Catalytic Reformer unit (CCR):
OBJECTIVE:
The Continuous Catalytic Reformer shall produce high-octane aromatics (RON-103) from
naphthenes and paraffins for use as a high-octane gasoline blending component.
The CCR feed comprises of low octane (RON<60) naphthaenes and paraffins.
Naphthenes convert rapidly and efficiently to aromatics. Paraffins do not, requiring higher
severity conditions.
During the process of refining coke deposition occurs on the catalyst. The catalyst is
continuously regenerated in the regenerator section.
Feed to CCR:
Heavy Naphtha from NHT – NSU.
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 Naphtha Isomerisation Unit (ISOM):
OBJECTIVE:
The objective of ISOM is to isomerizes normal C5 and C6 paraffins to their respective
isomers which have got higher octane values.
Paraffins having octane number of 60 are converted to their isomers with octane number
of 88.4 across ISOM reactors. Improves octane, lowers benzene and olefins and lowers
sulfur. The catalyst used is Platinum.
Feed to NIU:
Light Naphtha from NHT-NSU.
Products: Reformate for MS Blending
LPG
 PRIMEG+ FCC Naphtha HydroTreating Unit
The Prime G+ FCC NHT comprises the following:


Prime G+ Selective Hydrogenation Unit and Splitter Section
Prime G+ Desulfurization / Olefin Saturation Section.
OBJECTIVE:
The FCC Gasoline streams are routed are routed to the selective hydrogenation unit
where-in the Diolefins removal from the FCC gasoline and conversion of light mercaptans
to heavier sulfur compounds takes place. The treated FCC Gasoline from Selective Hydrogenation Unit is sent to Splitter. The lighter fraction is sent to the gasoline pool and the
heavier fraction is sent to Prime G+ Desulfurization (HDS)/ Olefin Saturation Section.
The purpose of Prime G+ HDS is to eliminate the impurities like Sulphur, nitrogen and
metals and also to hydrogenate the olefins lead to reduction in octane number.
The split of FCC LIGHT GASOLINE and FCC HEAVY GASOLINE is optimized based
on the pool octane requirements such that the FCC Heavy Gasoline is pre-dominantly
routed to MS pool only.
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Detailed Process Descriptions
Crude Distillation Unit (CDU):
Feed to CDUs : Crude oil (High Sulphur or Low Sulphur)
CDU Feed Battery Limit Conditions
1. Flow Rate
229167 Kg/hr
2. Pressure
2.0 Kg/cm2(without offsite booster)
6.0 Kg/cm2(with offsite booster)
3. Temperature 30 oC
4. Source
Tank Farm
Products from CDUs:
CDU Product Battery Limit Conditions
S.No Product
Temperature
Pressure
oC
(Kg/cm2)
Destination
%
Yield
1.
SRN
43
5
Merox
11.3
2.
LPG
43
15
ATU
1.6
3.
Heavy Naphtha
43`
6
Merox
7.0
4.
Kerosene/ATF/MTO
43
6
Merox
11.6
5.
Diesel
43
6
DHDS
23.2
6.
FO and LSHS
120
9
FO tanks
7.
LVGO+HVGO
70
6
FCCU
Major Equipments:
 Desalter,
 Furnaces,
 Columns,
 Preheat Exchangers
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 Coolers.
The main operations involved in CDU are







Crude feeding/preheating (stage 1)
Crude desalting
Crude feeding/preheating (stage 2&3)
Crude feeding to atmospheric heater
Fractionation
Product stripping/stabilization
Product cooling/treating to desired condition
PROCESS DESCRIPTION:
Atmospheric Section:
Crude oil is supplied to the unit by off site crude oil booster pumps. In the atmospheric section the crude oil is first boosted to a pressure of 25kg/cm2 g and passed
through a train of exchanger where it gets preheated from 30Oc to 1250C. To separate salt
and water from crude oil the crude oil is passed through a desalter where intensive electric
field is applied. The desalter crude oil coming out from the desalter is again boosted to a
pressure of 35kg/cm2g and divided into two streams is also preheated to nearly same temperature in another series of exchangers. In all the exchangers various stream drawn from
atmospheric distillation column and vacuum column transfer same of their sensible heat to
crude oil. Preheated crude from both the sections joins together and enters the PFD.Pre
flash is a vertical hallow vessel having fitted with only a demister pad to knock off any
liquid intrained with the vapors and here the vapors from the crude get separated due to
reduction in pressure from 20 kg/cm2g to 7kg/cm2g. Crude from bottom of PFD gets
boosted and gets split into from stream and enter the furnace in 4 passes. Fuel oil and fuel
gas are burned in the furnace to heat the crude from 2800c to 3800c. The furnace is
equipped with air preheater. Induced draft fan (ID FAN), forced draft fan (FD-fan) for
efficient furnace operation.
The crude oil at 3600c-3800C is allowed to flash in the atmospheric distillation column flash zone. Part of the crude oil converts to vapor phase and travel to the top section
of the column. While the balance crude oil which is in the liquid form travel to the bottom
section of the column. Stripping stream is introduced at the bottom of the column to strip
off the lighter fractions present in the bottom product. This also helps in vaporization of
hydrocarbons by lowering of partial pressure. In the upper section the hydrocarbons are
separated into four fractions namely the overhead fractions and three side draw offs as per
their boiling points. The overhead fraction is totally condensed in the overhead condensers and is collected in the reflux drum. To control the column top temperature a part of
the condensed liquid is returned to the column top as reflux and the balance is fed to naphtha stabilizer. Heavy naphtha, kerosene (ATF) and diesel are the three side draw offs from
the column. These side draw offs are further steam stripped in strippers, to meet the given
specification. Beside these, three circulatory refluxes (CRS) namely top pump around,
kero CR and diesel CR are also drawn separately and a part of their sensible heat is re-
Page 17 of 42
moved and they are returned back to the column. In this way the temperature profile inside the column is maintained.
The condensed atmospheric column overhead product is known as unstabilised
naphtha, which is a mixture of naphtha, and LPG is stabilized in the naphtha stabilizer.
The unstabilised naphtha is preheated in exchangers and fed to the flash zone of stabilizer.
The heat to maintain the required bottom temperature of the stabilizer is provided by a reboiler. The overhead vapors from the stabilizer are condensed in the overhead condensers
and a collected in the reflux drum. To maintain the required pressure in the stabilizer condensed vapor in overhead condensers released to fuel gas system through a control valve.
A part of the condensed liquid i.e. LPG is returned back to the column top as reflux and
the balance is routed to Merox unit for further treatment. The straight run naphtha (SRN)
is treated with caustic drum and later washed with water in water washing drum to remove
caustic carry over and is routed to storage tank.
The bottom product from atmospheric distillation column also known as reduced
crude oil (RCO) is next sent to vacuum column section for further processing.
Vacuum Section:
The reduced crude oil from the atmospheric section is heated to about 380 0-4050c in
vacuum heater. Fuel oil and fuel gas are burned inside the furnace to give the necessary
heat input. While processing heavier crudes like Basrah, the RCO from atmospheric section goes directly to furnace, while processing lighter crudes like BH, the RCO from atmospheric section is routed to exchangers (fully or partly) to remove some of its sensible
heat, transfer it to crude oil and RCO is then routed to furnace. The RCO enters furnace in
four passes. At the out let of the furnace the four passes again joint together. The heated
RCO is now introduce the four passes again joint together. The heated RCO is now introduced in the flash zone of vacuum column.
The vacuum residue is with drawn from the bottom of the column. On part of the
short residue is pumped back to the vacuum column bottom as quench after transferring
some of its sensible heat to crude oil. The balance VR is sent to fuel oil tanks and or as
feed to bitumen blowing unit while processing liquid lighter crude like BH the balance VR
is routed to LSHS tanks.
The slop distillate cut is withdrawn as the first side draw product. About half of this
is recycled back to the RCO at vacuum furnace inlet, the balance is mixed with vacuum
residue product and sent to storage after exchanging heat. The slop cut helps to achieve the
quality of FCC feed i.e., heavy vacuum gas oil (HVGO) by keeping metal content and
asphaltenes in check.
The vapor rising from slop cut/flash zone passes through a demister pad to ensure
removal of entrained asphaltenes. The hydrocarbon vapor is condensed in the HVGO and
LVGO section by respective circulating refluxes to yield side draw products. HVGO is
the second side stream drawn as the product stream, the circulating reflux and internal reflux also known as wash oil going to the wash zone. The HVGO circulation reflux is used
to preheat crude oil in exchangers and the is to generate steam in steam generators and finally returned to the top packing of HVGO section after filtering in HVGO CR strainer,
Page 18 of 42
while the product stream gives off some of its sensible heat to crude oil in exchanger and
gets cooled to about 750c. The cooled HVGO is routed to storage tanks or FEED.
LVGO is the third side stream draw as the circulating reflux and internal reflux
which is returned to the HVGO packing. LVGO circulating reflux is split into 2 streams.
One stream transfers its sensible heat to crude oil in exchangers and is further cooled in
LVGO cooler. The other stream is cooled directly in exchangers. Both stream joins together and after filtering in LVGO CR strainer goes as reflux to the top of LVGO packing.
Both LVGO and HVGO product can be mixed together and can be sent as feed to
FCCU directly or to FCCU feed storage tanks separately. LVGO R/D can be routed to
LDO/Diesel and HVGO can also be routed to LDO pool.
Vacuum in the column is maintained by a three stage ejector system with surface
condensers. The overhead vapor from the column flows to the first stage ejector. MP
steam is used as motive fluid here. The discharge from first stage ejectors goes to the 1st
stage condenser. The Non-condensable from this condenser are sucked by the second
stage ejector. The discharge from 2nd stage goes to the 2nd state condensers. Non condensable from the condenser are further sucked by the 3rd stage ejectors, the discharge of
which is finally condensed in the last of three condensers. A part of the non-condensable
may be recycled back for maintaining the desired column pressure by circulation back to
inlet of first stage ejector through a pressure control valve. The set of non-condensable are
led to the hot well through a liquid seal (to avoid air ingress of to the system) and finally
vented to the atmospheric. The condensed liquid from all the three condensers flow down
through barometric legs (which are dipped into the water) into the hot well. A small
amount of oil which might be carried over is collected in the hot well, which after separating from the water is pumped to slop diesel or to tank by slop oil pump.
Sour water from the hot wells is pumped by pumps to SWSU. Baffle of suitable
height (80cm) is provided in the hot well to separate oil and water. Oil being lighter will
float on after and when level rise above the baffle, it falls into the other chamber from
where oil is pumped.
DIFFERENCES BETWEEN CDU-1,CDU-2 AND CDU-3
CDU-1 and CDU-2 primarily differ in their diesel cuts and VGO cuts.
 In cdu-1 there will be 3 diesel cuts namely VD,LD,HD but whereas in cdu-2 only
one diesel cut i.e HD is obtained.
 In cdu-1 only VGO is obtaine as single cut, whereas in CDU-2 VGO is obtained
as:
1. Heavy Vacuum Gas Oil (HVGO)
2. Light Vacuum Gas Oil (LVGO)
But CDU-3 is quite similar in design and in cuts to CDU-1.
Page 19 of 42
Page 20 of 42
Fluid Catalytic Cracking Unit (FCCU)
Feed to FCCUs:
Vacuum Gas Oils from Vacuum Column
Feed Battery Limit Conditions
Feed
Pressure (Kg/cm2) Temperature oC
VGO (Hot) 4.0
VGO (Cold) 4.0
Source
120 (min) / 160 (max) VDUs
70 (min) / 90 (max)
Storage
Products from FCCUs:
Product Battery Limit Conditions
S.
Product
Pressure
No
(Kg/cm2)
1.
2.
3.
4.
5..
6.
7.
8.
LPG
CRN
LCO
HCO
Clarified Oils
Fuel Gas
Sour Water
Slop
19.0
13.0
5.0
13.0
13.0
6.1
4.0 Max
5.5
Major Equipments:
 Regenerator,
 Reactor,
 Main Fractionator,
 Primary Absorber,
 Sponge Absorber,
 Main Air Blower(MAB),
 Wet Gas Compressor(WGC),
 Debutaniser,
 Stripper.
Temperature
oC
Destination
%
Yield
40
38
40
60
60
40-50
38-40
ATU/Merox
Merox
HSD Storage
FO Storage
FO Pool
SRU/FG System
SWSU
Slop Tanks
14.6
40.3
25.7
11.1
5.6
Page 21 of 42
The unit can be broadly classified into 3 sections they are
o Catalyst section
 Reactor
 Regenerator
o Fractionator section
 Main fractionating column
o Gas concentration section
 Primary absorber
 Sponge Absorber
 Stripper
 Stabilizer
The reaction takes place in the catalyst section and resultant product is fractionated into
different products in the fractionator section, which are concentrated into final products in
the gas concentration section.
PROCESS DESCRIPTION:
The vacuum gas oils at a pressure of 4.0k/cm and 165-1200C at a pressure of
4.0k/cm and 20-900C from the crude distillation units is received in the feed surge drum
operating at a pressure of 0.8kg/cm2 and a temperature of 70-1650C from where it is
pumped to feed preheat circuit, which comprises of a train of heat exchangers in series.
The fresh VGO feed after preheat attains a temperature of 343.40C. The HCO recycle from
the main fractionator joins the feed upstream of feed heater. The combined feed is further
heated in feed heater to the desired temperature of 3830C/417.20C. the heater feed outlet
temperature is reset based on the set point spinal from the reactor, which in turn controls
the amount of fuel oil fuel gas firing. The feed from the heater is a total liquid stream and
is diverted to the catalyst section.
The catalyst section mainly consists of reactor and regenerator. The feed along
with reslurry enters the reactor riser where it comes in contact with hot catalyst. The feed
vaporizes and starts cracking into lighter products. The cracked vapors and spent catalyst
travel up the riser and enter the reactor. The temperature in the reactor is controlled by
flow of hot catalyst from the regenerator into the riser, the flow being controlled by a slide
valve. There is a pressure differential over ride which closes this slide valve when ever
the differential pressure across the slide valve is below a given set value.
In the reactor the catalyst in the vapor disengages and vapors go to the fractionator
through a cyclone. The catalyst (containing deposited coke, entrained hydrocarbons) falls
down to the reactor stripper. The catalyst stripper surrounds the upper portion of the reactor riser. In the stripper; the catalyst flows over baffles (disk-doughnut trays) counter current to the rising stripping steam.
The stripping steam displaces oil vapors from around the catalyst particles and returns this oil vapor to the reactor. The spent catalyst then flows back to the regenerator
under a level control and slide valve control: which is also having a differential pressure
override. The catalyst is continuously circulated from the reactor zone to regenerator zone.
In addition to promoting the catalytic action, the catalyst also acts as a vehicle for the
transfer of heat from one zone to another. In regenerator coke is burned off by air. Air is
Page 22 of 42
compressed by a turbine driven air blower and introduced into regenerator through directfired air heater and air distributor. The flue gas from regenerator goes to orifice chamber
through two sets of cyclones. Flue gas ex-orifice chamber can be diverted either to co
boiler or stack. The regenerated catalyst from bottom of regenerator is sent back to riser
bottom for further contact with fresh combined feed. Thus catalyst circulation is maintained. The air rate in the regenerator is so adjusted that partial combustion of coke take
place and the co produced is burnt into CO2 in co boiler to generate steam.
Main Fractionation Section:
The main fractionator consists of 36 valve trays and 6 rows of disc and doughnut trays. The fractionator consists of 2 sections. Top section is the regular fractionator
and the lower one is quench or desuperheating section. The reaction effluent consisting of
cracked hydrocarbon vapors, steam and non-condensables enter the fractionator at the bottom of the quench section or Desuperheating section consists of disc and doughnut trays.
The quench section operated at a pressure 2.05 Kg/Cm2 and at a temperature of 3600c.In
the quench section, the superheated cracked vapor are cooled by a circulating slurry pump
around stream also scrubs any entrained catalyst in the cracked vapor. The fractionator
bottom has a high coking tendency. Coking is further promoted by higher liquid temperature and long residence time to maintain the fractionate bottom temperature at a desired
level i.e. about 3600c, a cold quench stream from the slurry pump around system is directly mixed under column bottom stream temperature control with the fractionator bottom
liquid. Further, stream is injected into the bottom liquid through a steam ring to contract
coke formation and to maintain catalyst and coke particles in suspension. To ensure that
large coke particle in the bottom stream donot hamper the operation of the bottom pump.
A coke trap is put around the bottom nozzle to filter out such lumps.
The column bottom liquid which serves as slurry pump around and net bottom
product is with drawn from the fractionator and is fooled by exchanging heat with fresh
feed in the fresh feed/slurry pump around heat exchangers and subsequently in the MP
Stream generator. Varying the flow of slurry pump around through the slurry pump around
MP stream generator can vary slurry pump around stream temperature. Too much by
passing will result in unacceptable low velocity of slurry trough the exchanger tubes resulting in quick fouling of the tubes.
Provision is made to return this stream at three locations in the column bottom section:
 On the top of Desuperheating trays
 On the middle of the desuperheating section
 In the column bottom as quench stock
Beside the quench stream, most of the circulating slurry stream is normally returned at the
top of the desuperheating trays.
A part of the total bottom liquid stream from slurry operations at pressure
of 11.5kg/cm2 and a temperature of 3600c pump around pumps is taken to the slurry settler operated at a pressure 11.5Kg/Cm2 and 3600cfor removal of the entrained catalyst.
The slurry feed enters the settler tangentially where catalyst fines are removed by settling.
The catalyst rich stream from the slurry settler bottom is returned to the reactor under flow
Page 23 of 42
control on its own pressure. Provision exists for mixing the recycle slurry with the combined feed upstream of the feed injection nozzle as well as to route it independently to riser through dedicated injection nozzle. The decanted clarified oil obtained from the settler
has about 0.2%wt catalyst fines and is cooled by exchanging heat with fresh feed in
feed/LCO heat exchanger and finally in the LCO product cooler before it is routed to storage. A part of the clarified oil from settler top is routed to the fractionator. The combined
stream of HCO pump around and HCO recycle are drawnin from the chimney tray #2.
The HCO pump around stream is pumped by HCO pump around pump and is utilized to
provide necessary heat for debutaniser reboiler and to generate MP steam in MP steam
generator. The cooler pump around stream is returned to tray #5. The LCO stripper operated at a pressure of 1.01kg/cm2 and 3180c at the top and at a pressure of 1.06kg/cm2 and
3010c at the bottom.
The HCO recycle stream is sent to a side stripper column which is operated
at a pressure of 1.01Kg/Cm2g and 3180c at the top andat a pressure of 1.06Kg/Cm2g and
3010c at the bottom.The provision of stripper helps in improving the diesel yield by recovering diesel component from the recycle stream. Unstripped HCO recycle will result in
cracking of the diesel component into lighter components such as gas, gasoline etc, in the
reactor. MP steam is used as the stripping medium for HCO stripping. The stripper overhead vapor is returned to the main column. The stripped HCO liquid is recycled to the
fresh feed stream upstream of the heater during diesel maximization. During Gasoline
maximization, the stripped HCO liquid is the net product and is routed to storage (fuel oil
pool) after heat recovery.The product is stored at a pressure of 13Kg/Cm2g and 600c. The
HCO run down stream is combined with LCO product upstream of feed preheat exchanger. The combined stream of LCO pump around and product is drawn from chimney tray
#1. The LCO pump around is pumped through LCO PA pump and is heated recovered by
preheating fresh feed in feed /LCO pump around exchanger and subsequently by providing heat for the stripper reboiler-I. The cooler LCO pump around stream is returned to the
main fractionator column through a duty controller. The LCO stripped is operated at a
pressure of 0.8kg/cm2 and 2410c at the top and at a pressure of 0.85kg/cm2 and a temperature of 2190c at the bottom. The LCO product is sent to a side stripper which is operated at
a pressure of 0.8Kg/Cm2g and 2410c at the top and at a pressure of 0.84Kg/Cm2g and
2190c at the bottom.. The lighter components presents in LCO stream are stripped off using MP steam as striping medium. The stripped LCO is then heat recovered by exchanging heat with rich sponge oil in rich oil/LCO exchanger
Fresh feed in feed / LCO exchanger and coiler feed water in LCO/BFW
exchanger. The final cooling is done in LCO air cooler and LCO trim cooler. A part of
the cooled LCO stream is used as lean storage oil and is routed to sponge absorber. The
net LCO product is routed to storage at a pressure of 5 kg/cm2 and a temperature of 40 0c
provision is also given for routing LCO product to fuel oil system for on line blending or
unit/refines flushing oil system. Lean sponge oil drawn fro LCO product stream after final
cooling is pumped through lean sponge oil pump to sponge absorber. The rich sponge oil
drawn from sponge absorber column in bottom is returned to main fractionator after preheating in stabilized naphtha product exchanger.
The fractionator overhead vapor consists of naphtha and lighter hydrocarbons together with steam and non-condensables. The total overhead vapors from the fractionator along with wash water and spill back stream from inlet gas compressor are cooled
Page 24 of 42
in main fractionator overhead air cooler and finally in the fractionator overhead trim condenses. The three phase mixture of Non-condensables hydrocarbons liquid and water is
returned to the top tray of the fractionator which is operated at a pressure of 5Kg/Cm2g
and1370c. as reflux through main fractionator reflux pump. The net liquid from accumulator pumped through unstabilised naphtha pump to wet gas compressor inter condenser.
The sour water from the accumulator which is operated at a pressure of 0.35Kg/Cm2g
and400c. is pumped from boot through main fractionator sour water pumps. The sour water is normally routed to the inlet of compressor after cooler as wash water. The water after separation in the HP receiver is routed on its own pressure to the inlet compressor inlet
cooler. The net water separated in the inter stage knock out drum is sent out to sour water
stripping unit. For treatment. Demineralised water is used as make up water for meeting
the wash water requirement.
The net gas from the accumulator flows to the WGC through suction knock
out drum in the gas concentration unit for recovery of LPG and gasoline. Since the WGC
drawing gas from the fractionator accumulator is driven by a fixed motor, the compressor
is operated at a constant volumetric flow. Thus mass flow of gas through the compressor
is high at high suction pressure as well as to maintain a constant pressure in the fractionator accumulator. A spill back is provided from WGC discharge to upstream of the air
coolers. In case of fall in pressure in the accumulator one of the PIC’s provided on the
accumulator actuates the spill back control valve and recycle of the gas begins, in case of
rise in pressure in accumulator, the gas spill back stops to allow maximum gas evacuation
from system. If the pressure continues to rise, the control valve on the line to flare from
accumulator starts opening and the excess gas is flared.
Gas Concentration Section:
The wet and unstabilised naphtha streams from the fractionator’s overhead
accumulator are the feed for gas concentration section. In this section, the wet gas
cons1sting of lighter hydrocarbons and Non-condensable LPG and stabilized naphtha are
separated. The net pages are routed to sulphur recovery unit fuel gas network where as
LPG and stabilized naphtha are routed to storage after the treatment in Merox unit.
The wet gas from main fractionator overhead accumulator is first flashed in
compressor suction knock out drum which is operated at a pressure of 0.35Kg/Cm2g
and400c. to remove any condensate. The condensate from the drum is pumped back to
accumulator through compressor suction knock out drum liquid pump. The flashed gases
from the drum are compressed in a two stage centrifugal compressor to 16kg/cm2g. The
compressor suction line is steam traced down stream of suction knock out drum to avoid
any condensation due to ambient cooling. The gases from compressor first stage mix with
unstabilised Naphtha from accumulator along with was water and are cooled in compressor interstage cooler. The mixture of cooled gases condensate and water is flashed in the
compressor interstage knock out drum operating at a pressure of 2.64kg/cm2g and 38 0c.
The sour water drawn from the boot is routed on its own pressure to sour water stripping
unit. The hydrogen liquid from the drum is pumped by interstage pump to the inlet of
compressor after cooler for reconnecting.
Page 25 of 42
Page 26 of 42
Vis Breaking Unit (VBU):
Visbreaker is a well established non-catalytic thermal process that converts atmospheric or
vacuum residues to gas, naphtha distillates and tar. Visbreaking reduces the quantity of
cutter stock required to meet fuel oil specifications while reducing the overall quantity of
product.
Feed to VBU:
Vacuum Residue from CDUs
Feed Battery Limit Conditions
Pressure (Kg/cm2) Temperature oC Source
Vacuum Residue 8.5
120
150-160
VR Storage
CDU/VDU
Products from VBU:
S.No Product
Pressure (Kg/cm2) Temperature oC Destination
% Yield
1.
1.
2.
3.
4.
10.0
16.0
14.0
6.0
9.0
0.8
3.4
11.2
83.3
VB Gas
VB LPG
VB Naphtha
VB Gas Oil
VB Tar
45 max
40 max
40 max
40 max
80-100
SRU
LPG ATU
Gasoline Merox
FO Tank
FO Tank
Major Equipments:






Furnace,
Soaker,
Main Fractionator,
Compressor,
Stabilizer,
Sponge Absorber.
Process chemistry:
Visbreaker is a well established non catalytic thermal process that converts atmosphemic or vacuum residues to gas naphtha distillates and tar visbreaking reduces the quality of cutter stock required to meet fuel oil specifications while reducing the overall quantity of fuel oil produced.
The conversion of these residues is accomplished by heating the residue material to
high temperature in furnace. The material is passed through a soaking zone located at the
Page 27 of 42
heater or in an external drum, under proper temperature and pressure constraints so as to
produce the desired products. The heater effluent is then quenched with a quenching medium to stop the reaction.
The VBU breaking processes are commercially variable. The first process is the coil
or furnace type. The coil process achieves conversion by high temperature cracking with
in a dedicated as a result of temperature and residence time route process.
The main advantage of the coil type design is the two zone fired heater. This type
heater provides for a high degree of flexibility in heat input resulting in better control of
the material being heated with the coil type design. Decoking of the heater tubes is accomplished more easily by the use of steam air decoking. The alternative soaker process
achieves some conversion with in the heater. However the majority of the conversion occurs in a reaction vessel or soaker which holds the phase effluent at an elevated temperature for a predominantal length of time. Soaker visbreaking is described as a low temperature high residence time route by providing the residence time required to achieve the desired reaction. The soaker drum design allows the heater to operate at lower outlet temperature. This lower heater outlet temperature results in lower fuel cost. The disadvantage with this technology is the decoking operation of the heater and soaking drum.
The conversion of residue to distillate and higher products is commonly used as a
measurement of the (4820c) material present in the vacuum residue feed stock which is
visbreked into higher boiling components.
PROCESS DESCRIPTION:
Vacuum reside from either CDU’S or storage is received in visbreaking feed surge
drum. It operates at a pressure which is floating on main fractionating pressure visbreaker
feed @ 5.0kg/cm2g 1200C-1600C from surge drum is pumped by visbreaking feed charge
pump which are of screw type to a pressure of 7.6kg/cm2g. It is then heated in visbreaking
tar exchanged to 3200C by visbreaking tar from fractionator bottom. Visbreaker tar gets
cooled to 2400C visbreaking crude is then routed to heater through booster pumps @
5.8kg/cm2g preheated visbreaker feed enters both passes of visbreaker heater under individual pass flow control visbreaker heater is a two pass single shell heater with a bridge
wall type configuration turbulising water (BFKL) is injected to both the passes at a point
where visbreaking reaction starts. Flue gasses heat visbreaker feed to 4550C -4700C.
Visbreaker heater effluent is routed to soaker drum to complete visbreaking reaction.
20minutes residence time is provided and effluent from soaker drum is quenched with gas
oil. Quench effluent enters main fractionator @ 4250C and 7kg/cm2g where it is separated
into visbreaker tar as bottom, gas oil as side stream and Naphtha and gas as O/H product.
Fractionator has 26 valve trays+3 chimney trays for required separation of various
products 6 single pass valve trays (1 to 6) are provided in bottom stripping section. 4 segmental baffle trays (7 to10), 3double pass valve trays (11 to 13) are provided in section
above flash zone 3 double pass (14 to 16), 10 single pass valve trays (17 to 26) are provided in top section. Feed enters at flash zone above tray 6 @4250C MP Steam @ 10
kg/cm2g and 2500c enters below tray.
Vapors from fractionator are partially condensed. Liquid vapor mixture from condenser outlet @ 650c is further cooled to 400c in trim condenser liquid vapor and the mixture is separated in reflux drum. Uncondensed vapors are sent to fuel gas compressor in no
LPG production and to sponge absorber during LPG recovery case. Reflux is pumped
back to fractionator on 26th tray by reflex pumps. Sour water from reflux drum is routed to
SWSU. Gas oil is drawn from 14th chimney tray. A part of Gas oil CR (Gas oil Quench
Page 28 of 42
+lean oil) is pumped by gas oil CR pumps to stabilizer reboiler where it heats reboiler bottom to 2100C. Rest goes to gas oil CR/MP Steam generation. The 2 streams then combine
and are separately taken as quench lean oil CR streams. CR steam is taken back to column
above 16th tray. Gas oil stream enters stripper on 6th tray. It has 6 single pass valves trays.
Lighter components are stripped by MP Steam. Vapors from top are routed to fractionator
16th tray. The product is then routed to visbreaker tar stream as cutter stock or visbreaker
Gasoil / LD exchangers and visbreaker gas oil coolers. VB tar@ 3550C is passed through
coarse filters to get rid of coke particles and then pumped to visbreaker feed exchanger
where it is cooled to 2400C. A portion of cooled tar goes as quench to column bottom to
control bottom temperature. VBtar is then mixed with cutter stocks to give fuel oil.
Visbreaker FO is then cooled in visbreaker fuel oil / LP stream generator further cooled in
FO coolers and then sent to storage.
Unstabililsed Naphtha is sent to stabilizer Via Stabilizer feed/ bottom exchanger
where feed is heated to 1100c necessary heat is supplied to column through horizontal
thermo siphon reboiler, where gas oil CR is used as heating medium O/H vapors are condensed in O/H condensers, routed to whom it may concern sponge absorber or to fuel gas
compressor in case of no LPG production and sour water stripping unit. stabilized naphtha is cooled by stabilizer feed bottom exchanger and visbreaker Naphtha coolers sent for
caustic wash.
Fractionator O/H reflux drum vapor and stabilizer O/H reflux drum vapors are routed
to sponge absorber. It has 24 single pass valve trays. Feed enters at bottom of column.
Lean oil is cooled by exchanging heat with rich oil in exchanger and lean oil is further
cooled by cooling water to 400C in lean oil coolers and enters at top and flows down absorbing heavier components (LPG) present in vapors. Rich oil is then pumped to main
fractionator @ 16th tray via lean oil/ rich oil exchanger. Sour water from sponge absorber
is routed to SWSU. Pressure in sponge absorber is controlled by controlling off gases going to fuel gas compressor provided to compress fuel gas routed to SRU to meet VBU battery limit pressure requirement of 9 kg/cm2g.
Page 29 of 42
Page 30 of 42
Bitumen Blowing Unit
The bitumen process a precisely controlled oxidation process is used to produce bitumen
of the highest quality from different types of feedstocks. The process can be operated in
batch as well as in continuous mode. It is most effective if operated in continuous mode
because of the proprietary agitator concept this bitumen process has the following advantages compared to the conventional blowing process.




Best possible oxygen utilisation and hence lesser quality of air requirement
Optimum temperature control by water injection along with air
Reduced residence time and hence smaller reactor volume
Lesser cocking tendency due to more effective air d1stribution and hence eases of
maintenance.
 Flexibility of producing different grades of bitumen
Feed to BBU: Short Residue
Feed Battery Limit Conditions
1. Flow Rate (Kg/hr) Grade S35
30194
S65
26324
S90 37589
2. Pressure
Kg/cm2
8.0
3. Temperature
o
230-250
C
CDU-I/CDU-II/CDU-III
4. Source
Products from BBU:
Bitumen of different grades
Product Battery Limit Conditions
1. Flow Rate (Kg/hr) Grade S35
29439
S65
25534
S90 30799
2. Pressure
Kg/cm2
7.5
3. Temperature
o
145-150
C
4. Source
Capacity: 0.225 MMTPA
TK 20-D-35/ TK 20-D0-34
Page 31 of 42
Major Equipments:
 Reactor,
 Heat Exchangers
 Compressor.
PROCESS DESCRIPTION:
FEED PREPARATION: The unit receives hot vacuum residue as feed directly from
crude distillation units through the vacuum bottom pumps. The temperature of the feed
will be in the range of 230-2500C which is cooled in heat exchanger by generating MP
steam. Precise temperature control is achieved by a three way control valve, which by
passes a part of the feed across exchanger as required which is a kettle type exchanger
having two tube bundles in a single shell. Which one of the tube bundles was being used
for product cooling purpose both the bundles will be used for maintaining the heat temperature feed is split and sent to both the bundles. The feed outlets are provided with drain
connections to OWS and CBD. BFW enters the exchanger shell at two points for uniform
distribution.
BITUMEN CONVERSION: Vacuum residue at 230-2320c is fed to the Biturox reactor
at the bottom. The reactor is a vertical cylinder vessel with 4.0m diameter and air over all
height of 13.0m. Air for the oxidation reaction is supplied by the air compressor which is
lubricated horizontal, reciprocating balanced opposed p1ston, two stages, six cylinders,
double acting type. It is a motor driven. The flow of air to the reactor is regulated which
enters the reactor at the top and run down through the length of the reactor. The boiler
feed water is used for reactor temperature control . It is injected to air lines before entering the reactor.
The main component of the reactor is the proprietary agitator which is a motor driven
and mounted on the top of the reactor. The agitator has three stages of disk mixers attached to the shaft. It rotates in a guiding cylinder inside the reactor. The guiding cylinder, located concentric to the shell, contain two coalescing plates, are of which is located
under the middle disc mixer and the other under the upper disc mixer. Specified quantities
of feed stock air and water are simultaneously feed into and processed with in the reactor
unit. The size of the air injection pipes at the reactor bottom are so chosen that the bubbles
created at the bottom of the pipe are large and, as such minimize the amount available oxygen at that point which prevents over heating and coke formation. However as the air
bubbles begin to rise in the reactor, they are immediately broken up, become smaller, collected by the coalescing plate and are dispersed by the first disc mixer. It is at this point
because of the maximum oxygen utilization due to reduced size of air bubbles, that the
optimum intensive reaction begins involving the combination of feed stock, air and
steam.The small bubbles continue to raise inside the guiding cylinder, grow and become
large are again collected by the second coalescing plate and are again broken up dispersed
by third disc mixer.
A low liquid level has a negative influence on the circulation inside the reactor. To prevent overfill of the reactor during operation high –high level switch is provided which a causes an emergency shut off of the reactor: air, water and feed air shut off
Page 32 of 42
dry air interlock. During operation the vapor space temperature will be a minimum of
300c less than the bitumen temperature. In case of higher vapor temperature LP steam can
be introduced to the vapor space for quenching purposes. The quench steam is also used
when the oxygen content in the reactor off gas is too high, this is indicated by the oxygen
analyzer.
Product Cooling and Rundown:
Bitumen product is withdrawn from the reactor at two locations. The bottom one is
used during batch operation where as the one above is used continuous operation Bitumen
is pumped by the bitumen product pump. A spillback from the pump is discharge is provided to the reactor feed line. Bitumen product from pump at about 2700C is first cooled in
LP steam generating exchanger to about 2420C and then in LP steam generating exchanger
to about 2200c. These steam generating are horizontal. LP steam is generated at a pressure
of 4.0kg/cm2g and a temperature of 1520C.The Bitumen product is product is further
cooled temperature in trim coolers. The Bitumen gets cooled to about 1600C at first and
attains the storage temperature of 1450C to 1500C in the same. Tempered at 600C is used
in these exchanger as the cooling medium. The tempered water outlet temperature will be
in the range of 850C.
Reactor Overhead System:
The reactor shall be operated at a pressure of about 0.71kg/ cm2g. The vapors and off
gas from the reactor at about 2200C are routed to a quench drum. A service water connection is provided on the quench drum for reducing the temperature of the off gas to about
800C. The condensed hydrocarbon and water flows to ows. The quenched off gas from the
quench drum passes through a water seal drum where the temperature of the off gas is reduced to about 500C by bubbling though water. The off gas from water seal drum is routed
to the stack of CDU vacuum furnace above stack damper.
Page 33 of 42
Page 34 of 42
DHDS Unit
Feed to DHDS:
Diesel from CDUs and FCCUs (1.6% wt. Of sulphur)
Feed Battery Limit Conditions
S.no Streams
Pressure
(Kg/cm2)
1.
Feed
5.0
2.
Hydrogen Make-up
20
3.
Sour Gas from H2 5.0
Unit
Temperature
oC
86
40
40
Source
Feed Surge Drum
Chlorine Absorber
LPAmine
Absorber
Products from DHDS:
 Diesel meeting EURO specifications (0.25% wt. Of sulphur)
 Nitrogen (200 Nm3/hr)
Product Battery Limit Conditions
S.no Streams
Temperature
oC
60
Destination
54
Fuel Gas Header
2.
Pressure
(Kg/cm2)
Off Gas: Purge Gas(from 4.5
HP absorber)
Off Gas: Fuel Gas( from LP 4.5
Absorber)
Stabilized Naphtha
5.5
42
3.
Treated Diesel
6.0
45
4.
Rich Amine (From LP ab- 4.9
sorber)
Waste Water:Sour Water
4.0
68
Offsite
tank
Offsite
tank
ARU
42
SWSU
1.
5.
Capacity: 2.4 MMTPA
Major Equipments:
 Reactor,
 Heater,
 MGC,
 RGC,
 Feed Filter,
 Stripper,
 Stabilizer,
 Heat Exchanger,
 Cold Separator and
 Coalescer.
Make up Drum
Storage
Storage
Page 35 of 42
DHDS Unit consists of four major sections




DHDS reaction section
Amine absorption section
Stripping section
Naphtha stabilizing section
Main features: DHDS reaction section is a hydro treating process, which mainly consists
of two kinds of reactions. They are
(i)
(ii)
Refining reaction
Hydrogenation
Refining Reaction:
(A)
Desulphurisation: Mercaptides,sulphides and disulphides easily react leading to
the corresponding saturated or aromatic compounds sulphate combined into cycle of aromatic structures, like thiophenes is more difficult to eliminate. The reactions lead to H2S
formation and hydrogen consumption
(B) De-Nitrification: The Denitrification reaction rate is lower than that of desulphurisation. It occurs mainly in the case of hetrocyclic compounds having an aromatic structure. These reactions lead to NH3formation and H2 consumption
Hydrogenation Reaction: These reactions effect the olefines and aromatics and are
highly exothermic diolefines and olefines and converted into saturated compounds.
The hydrogenation rate of aromatics is limited.
Feed, Reaction, Separation and Absorption Section:
The feed to DHDS unit is blend of straight run and cracked gas oils. Part of feed is directly brought to upstream units where as rest is fed to the unit from storage under feed
surge drums level control. The feed blend is filtered through feed filter package and sent
to feed surge drum. The pressure in the feed surge drum is maintained by fuel gas blanketing.
The liquid phase feed is pumped under flow control by feed pump mixed with hydrogen recycle compressor delivery stream and let in the heat exchanger train the mixing
of recycle hydrogen with feed ensures an adequate hydrogen partial pressure at the inlet of
the reactor train. Polymerization inhibitor cant fouling agent is injected by antifouling
agent pumps in the fresh feed before the feed pump.
The hydrogen make – up coming from the battery limits is routed through chlorine
absorbent hot to the make up, KO drum it is then compressed by the make up compressor.
The make up gas flow rate to the reaction section is controlled by means of a compressor
spill back, which is sent back to the make up KO drum after cooling through spill back
water cooler. The make up gas joins the recycle gas up stream. The combined make up
Page 36 of 42
and recycle stream is routed to the recycle gas compressor. A part of the compressed gas
from KO drum is sent as quench gas to the reactor.
The mixed feed stream (feed+recycle H2) is heated in first feed / effluent exchanges then in second feed (effluent exchanger and finally in the reactor heater to the required
reaction inlet temperature. The reactor inlet temperature is maintained by controlling the
fuel gas/ fuel oil to the heater burner. The stream is then let in the first reactor, which includes catalyst installed in three beds. Cold quenches of hydrogen coming from recycle
compressor are added at the inlet of each new bed under TIC/FIC cascade to control the
bed inlet temperature.
The reactor effluent is split is to two, in order to maximize the heat recovery. On
part exchanges heat with the stripper feed in stripper feed pre-heat exchanger under temperature control of the stripper feed while the remaining part of exchanges with the reactor
feed in second feed/ effluent exchanger. The two streams are mixed together before entering first feed/ effluent exchanger. Final coding of the reactor effluent is achieved first in
the effluent air condenser and then in the effluent trim condenser.
To avoid ammonium salt deposits and risk of corrosion, water is injected at the inlet of effluent gas air condenser by washing water pumps. This washing water is mixture
of recycled water from the cold separator and water recovered at the condenser and the
stripper stabilizer reflux drum. This mixture is collected in the washing water drum to
avoid air entry. The effluent of the trim condenser is collected in the cold separator where
these phases are separated. The sour water containing ammonium salts is partly recycled
to the washing water drum under level control of this drum while the other part is sent to
the sour water stripping stripper under level control of cold separator boot.
The gas phase from cold separator goes to the HP amine absorber KO drum and
then is partly sent to the HP amine absorber where H2S is removed the other part of by
passes the HP amine absorber and is directly routed to recycle compressor KO drum. This
by pass allows for control of H2S concentration. In the HP amine absorber the gas is
washed by a 25% wt. The lean DEA pumped by DEA plumped by DEA booster pump
from HP amine surge drum injected at the top of absorber under flow control reset by level
control of the HP amine surge drum which is maintained under fuel gas pressure to avoid
air entry. Anti-foaming agent is injected to the lean DEA pollution before it is pumped the
rich DEA pollution is with drawn under level control and the bottom of the absorber to
feed to the LP amine absorber to control the build up of heavies in the hydrogen gas recycle stream. Normally the flow rate of this stream is 0. The hydrogen liquid phase from
the cold separator drum is level control to the stripper feed / bottom exchanger.
Pressure control in the reaction section is achieved by action as the make up compressor spill back if required, because of too high pressure, the HP purge is opened.
Stripping, Stabilizing And Absorption Section:
The liquid hydrocarbon phase of the cold separator is the stripper feed. The stripped
feed is first pre-heated by the heat exchange against stripper bottom product in the stripper
feed/ bottom exchanger and then by heat exchange against the reactor effluent in the stripper pre-heater exchanges in order to reach the required stripper inlet temperature.
Page 37 of 42
Medium pressure steam superheated in the reaction heater is injected under flow
control at the bottom of the stripper in order to produce a diesel with correct flash point
and H2S content. Light ends and H2S gather at the top of the stripper. Stripper overhead
and stabilizer overhead are mixed before being partially condensed in the stripper/ stabilizer air condenser and then in the stripper/ stabilizer trim condenser. Inhibitor is injected
in to the stripper overheadline before mixing with stabilizer overhead. The stripper/stabilizer trim condenser outlet compressing three phases (hydrocarbon liquid phase
wild naphtha, a flue liquid water phase and a vapor stream) is separated in the stripper/
stabilizer reflux drum.
The vapor stream after mixing with sour gas stream drum is fed to the LP amine
absorber. The vapor feed to the LP amine absorber and vapor generated from flashing of
rich amine from HP amine absorber is washed by lean DEA solution to remove the H2S.
The lean DEA, to which anti-foaming agent is injected, is fed at the top of the column under level control. .
The decanted water from stripper/stabilizer reflux drum is sent under boot level
control to the washing surge drum. The hydrocarbon liquid phase is split into reflux
which is returned to the stripper under flows control and liquid distillate (wild naphtha)
which, is routed to the stabilizer feed/ bottom exchanges under flow control reset by level
control on stripper /stabilizer reflux drum
The stripper feed/ bottom exchanger effluent is fed to the top of the naphtha stabilizer. Light ends and H2S gather at the top of the stabilizer to be mixed with its overhead.
The naphtha stabilizer is reboiled by the stabilizer where heat is exchange against a part of
the stripper bottom. The flow rate of the steam from stripper bottom to the stabilizer reboiler is controlled by the temperature at the sensitive tray of the stabilizer.
The stripper bottom is pumped by hydro treated diesel pump. A part of this stream
then goes to reboil the stabilizer bottom. It is then mixed again with the stream by passing
the stabilizer reboiler and cooled against the stripper feed in stripper bottom/ feed exchanger. Final cooling is achieved in the hydro treated diesel an cooler and in the hydro
treated diesel trim cooler. The free water contained in the product is removed in the coalescer (including a coalescer prefilter) and routed to the washing water drum. The dry
product is finally sent to battery limit under stripper bottom level control.
Catalyst Regeneration Section:
During catalyst regeneration a mixture of nitrogen and oxygen (up to 1%) is circulated
by the recycle compressor through the reaction section. The first feed/ effluent exchanger
is by passed. The gaseous stream is preheated against the reaction effluent in second
feed/effluent exchanger. A by pass of this exchanger (under temperature control of air
condenser) is used to control the air condenser. Inlet temperature. The temperature at the
inlet of air condenser should not be below 1800C to avoid salt deposit. The required reaction inlet temperature is reached into reaction header.
Page 38 of 42
Page 39 of 42
Visakh Refinery Clean Fuels Project (VRCFP)
In order to meet the increasing demand of gasoline meeting Euro III specifications in the
future, Visakh Refinery Clean Fuels Project (VRCFP) is being implemented at Visakh Refinery to produce Euro III MS of both Regular grade and Premium Grade (primarily for
export requirments). The new major units that are going to be commissioned at refinery
under VRCFP project are:




Naphtha Hydrotreater (NHT)
Naphtha Isomerisation Unit (NIU)
Continuous Catalytic Reformer (CCR)
PRIME G+. (FCC NHT)
The objective of “Clean Fuels Project (CFP)” is
I.
II.
To meet future specifications (Euro III/ Euro IV) for MS in line with the Auto Fuel
Policy.
To maximize Product yields and returns.
Naphtha HydroTreater (NHT)
OBJECTIVE
The Purpose of Naphtha Hydro Treating Unit is to protect the Reforming / Isomerisation
catalysts by reducing the impurities of the naphtha to an acceptable level.
Straight Run naphtha from CDUs is hydrotreated in “Naphtha Hydro Treating Unit”. Impurities, which are considered detrimental to the catalyst activity, are Sulphur, Nitrogen,
Water, halogens, di-olefins, olefins, arsenic, and other metals. The treating is achieved by
passing the naphtha over a fixed catalyst bed in an adiabatic reactor in the presence of hydrogen. The hydro treated naphtha will be routed to Naphtha Splitter Unit. Sulphur content
in the feed should be less than 500 ppm. Catalyst used here is Ni+Mo.
Feed: Straight Run Naphtha
Products:
Light Naphtha
Heavy naphtha
Major Equipments:
 Feed Exchangers,
 Reactors,
 Coalescer,
 Heater,
 Compressors,
 Pumps(injection),
 Stripper
Page 40 of 42
Continuous Catalytic Reformer unit (CCR):
OBJECTIVE:
The Continuous Catalytic Reformer shall produce high-octane aromatics(RON-103) from
naphthenes and paraffins for use as a high-octane gasoline blending component.
The CCR feed comprises of low octane (RON<60) naphthaenes and paraffins. A typical
feed to a reforming unit contains :




45-70% paraffins
20-25% naphthenes
4-14% aromatics
0-2% olefins.
During the reforming reactions,
 aromatics increase to 60-75%
 paraffins decrease to 20-45%
 naphthenes decrease to 1-8% and
 olefins disappear virtually.
Naphthenes convert rapidly and efficiently to aromatics. Paraffins do not, requiring higher
severity conditions.
During the process of refining coke deposition occurs on the catalyst. The catalyst is
continuously regenerated in the regenerator section.
Feed to CCR:
Heavy Naphtha from NHT – NSU.
Major Equipments:









Pumps
Interheater
Exchanger
Reactors (4)
Condenser
Compressor
Cooler
Chiller
De-etherizer
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Naphtha Isomerisation Unit (ISOM):
OBJECTIVE:
The objective of ISOM is to isomerizes normal C5 and C6 paraffins to their respective
isomers which have got higher octane values.
Paraffins having octane number of 60 are converted to their isomers with octane number
of 88.4 across ISOM reactors. Improves octane , lowers benzene and olefins and lowers
sulfur. The catalyst used is Platinum.
Process Chemistry:

Benzene Hydrogenation

Isomerization

N-Pentane RON is 62 and I-Pentane RON is 93.
of
Feed to NIU:
Light Naphtha from NHT-NSU.
Products: Reformate for MS Blending
LPG
Major Equipments:







Depentaizer
Steam reboiler
Condenser
Pumps
Reactor
Deiso-hexaniser
Scrubber
N-paraffins(N-Pentane
I-Pentane)
Page 42 of 42
PRIMEG+ FCC Naphtha HydroTreating Unit
The Prime G+ FCC NHT comprises the following:


Prime G+ Selective Hydrogenation Unit and Splitter Section
Prime G+ Desulfurization / Olefin Saturation Section.
OBJECTIVE:
The FCC Gasoline streams are routed are routed to the selective hydrogenation unit
where-in the Diolefins removal from the FCC gasoline and conversion of light mercaptans
to heavier sulfur compounds takes place. The treated FCC Gasoline from Selective Hydrogenation Unit is sent to Splitter . The lighter fraction is sent to the gasoline pool and the
heavier fraction is sent to Prime G+ Desulfurization (HDS)/ Olefin Saturation Section.
The purpose of Prime G+ HDS is to eliminate the impurities like Sulphur, nitrogen and
metals and also to hydrogenate the olefins lead to reduction in octane number.
The split of FCC LIGHT GASOLINE and FCC HEAVY GASOLINE is optimized based
on the pool octane requirements such that the FCC Heavy Gasoline is pre-dominantly
routed to MS pool only.