Project Hpcl

7/25/2019 Project Hpcl

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PROJECT REPORT

By

NIKITHA SARIPALLI

NATIONAL INSTITUTE OF TECHNOLOGY, WARANGAL


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CERTIFICATE

THIS IS TO CERTIFY THAT NIKITHA SARIPALLI WITH

REGISTRATION NUMBER 851262 OF NATIONAL INSTITUTE OF

TECHNOLOGY, WARANGAL OF CHEMICAL ENGINEERING HAS

UNDERGONE INDUSTRIAL TRAINING AT VISAKH REFINERY,

HINDUSTAN PETROLEUM CORPORATION LIMITED, FROM JUNE

02, 2014 TO JUNE 30, 2014.

DURING THE ABOVE MENTIONED PERIOD, HER CONDUCT WAS

FOUND TO BE ______________________________.

M. J. SATYA RAO UDIT NANDI

Chief Manager (Training) Manager (Technical Dept.)

HPCL HPCL

Visakh Refinery Visakh Refinery

Visakhapatnam Visakhapatnam


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KNOWLEDGEMENT

I have taken efforts in this project. However, it would not have been

possible without the kind support and help of many individuals and HPCL

officials . I would like to extend my sincere thanks to all of them.

I am highly indebted to Mr.Satya Rao(Chief Manager Training) and Mr.

Udit nandi ( Manager- Technical Department- VR) . My sincere thanks to

Mrs N.Richa (MS block) , Mrs K .Shailaja(FCCU ) , Mr Kailash Rathod

(Utilities ), Mr A.V.B.S Srinivas & Mr Sudheer (CDU) and Mr Anshul

Arora (DHDS) for their guidance and constant supervision as well as forproviding necessary information regarding the project & also for their

support in completing the project.

I would like to express my gratitude towards member of HPCL for their

kind co-operation and encouragement which helped me in completion of

this project.

I would like to express my special gratitude and thanks to industry persons

for giving me such attention and time.

My thanks and appreciations also go to my colleague in developing the

project and people who have willingly helped me out with their abilities.


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INDEX

Topic Pg no.

Cover Page 1

Certificate 2

Acknowledgement 3

Abbreviations 5Company profile 6

Technical-PAD activities 7

Oil storage and movement 8

Crude oil and petroleum refinery process 9

Product and its specifications 15

Production-primary unit-CDU 20

Secondary unit- FCCU 25

Treating units- DHDS 32

MS bock 39

Power and Utilities 53


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ABBREVIATIONS

FCCU: Fluid Catalytic Cracking Unit

CDU: Crude Distillation Unit

CPP: Captive Power Plant

ETP: Effluent Treatment Plant

DHDS: Diesel Hydro Desulphurisation Unit

PRU: Propylene Recovery Unit

SRU: Sulphur Recovery Unit

MMTPA: Million Metric Ton Per Annum

ATP: Additional Tankage Project

ADC: Atmospheric Distillation Column

RCO: Reduced Crude Oil

LVGO : Light vacuum gas oil

HVGO : Heavy vacuum gas oil

SR : Short residue

NHT : Naphtha hydro treating

DHDS : Diesel hydro de sulphurisation

FCC NHT : Fluid catalytic cracking naphtha hydro treating

CCR : Continuous catalytic reactor

CNU : Cryogenic nitrogen unit

BCW : Bearing cool water

DM : Demineralised

PP : Power plant


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COMPANY PROFILE

Hindustan Petroleum Corporation Limited is a mega public sector undertaking

(PSU) and a second largest integrated Oil Company with Navaratna status. It

operates two major refineries one at Mumbai and other at Visakhapatnam each

and has 20% market shares in refining. Its lube refinery at Mumbai is largest in

the country with 40% of the countrys total lube refinery capacity. HPCL

markets the entire range of petroleum products from the lightest of LPG to

heaviest of Bitumen including 200 grades of lubes and greases.

ABOUT VISAKH

REFINERY

HPCL-VR is commissioned with an installed capacity of 0.675 MMTPA in

1957 with a Crude distillation unit expanded to 1.5 MMTPA with various

modifications. Later capacity was increased with commissioning 2 more unitsof 3 MMTPA each to 7.5 MMTPA. Crude processing capacity is revised to 8.33

MMTPA after various modifications like PFDs in CDUs, FCC unit, offsite

facilities for online bending. A maximum refining capacity of 9.24 MMTPA is

achieved in the refinery. This refinery can process both indigenous and

imported crude as raw material.


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TECHNICAL- PAD ACTIVITIES

1. Normal products yield and quality monitoring

2. Unit test runs for evaluation/Process limitations

3. Process equipment performance analysis

4. Chemicals injection and corrosion monitoring

5. Catalyst performance monitoring and new catalyst

evaluation

6. Cyclone performance analysis (catalyst loss).

7. Performance evaluation of additives like ZSM, DeSOx , GSR.

The refinery operations are divided into different sections :

1. OM &S

2. PRODUCTION3. POWER AND UTILITIES.


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OIL MOVEMENT AND

STORAGE

The units are :

1. Off shore tanker terminal

OSTT located at outer harbour is used to unload crude oil from the tankers and

transported to refinery by pipelines of approximately 8.5 km.

2. Single point mooring facility

In order to handle large crude tankers up to 300,000 TMT, to meet crude requirements

of existing and future crude processing requirements, SPM facility is commissioned.

This facility is located around 4km from the shore and water depth SPM locations is

35 m.

The crude oil tankers will offload crude parcels via two numbers 24 inch floating hose

string connected to tanker cargo piping manifold and SPM piping system. Crude then

will be routed through two nos 24 inch under buoy hose string connected to the under

buoy piping on the SPM which will be routed to the crude oil storage facility of

Indian strategic petroleum reserve Ltd and refinery via a 4 km long 48 inch submarine

pipeline and 1,3 km long 48 inch onshore pipeline.

3. Storage

There are floating roof tanks and cone roof tanks for storage of lighter and heavier

hydrocarbons. Line blending facilities are provided in addition to blending facilities

at storage tanks.LPG used to be stored in Horton spheres. However with the

commissioning of mounded storage total LPG from the refinery is being stored in

LPG mounded storage.

4. Dispatch

Product movement is done through rail, road, pipelines, tankers. Products are

pumped to terminals located nearby refinery for onward distribution. Tankers are

positioned at western arm of inner harbour.


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CRUDE OIL

It is a naturally occurring, toxic, flammable liquid consisting of a complex mixture of

hydrocarbons of various molecular weights, and other organic compounds, that are found ingeologic formations beneath the earths surface.

Another Definition:

Crude oil is a mixture of hydrocarbon molecules, which are organic compounds of carbon

and hydrogen atoms that may include from one to 60 carbon atoms. The refining process

uses chemicals, catalysts, heat, and pressure to separate and combine the basic types of

hydrocarbon molecules naturally found in crude oil into groups of similar molecules. The

refining process also rearranges their structures and bonding patterns into different

hydrocarbon molecules and compounds. Therefore it is the type of hydrocarbon (paraffinic,

naphthenic, or aromatic) rather than its specific chemical compounds that is significant in the

refining process. In the reservoir, it is usually found in association with natural gas, which

being lighter forms a gas cap over the petroleum, and saline water, which being heavier than

most forms of crude oil, generally sinks beneath it.

The main types of hydrocarbons present in crude petroleum are:

Paraffin (CnH2n+2 )

Olefin (CnH2n)

Naphthenes (CnH2n-2)

Aromatic (CnH2n-6)

There are certain amounts of non hydrocarbons that are also present in the crude oil:

Sulphur Compounds

Oxygen Compounds

Nitrogen Compounds

Trace Metals

Salts

Carbon Dioxide

Naphthenic Acid


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Major Refinery Products :

1. Gasoline

2. Kerosene

3. Liquefied Petroleum Gas (LPG)

4. Distillate Fuels

5. Residual Fuels

6. Coke and Asphalt

7. Solvents

8. Petrochemicals

9. Lubricants

CHARACTERISTICS OF CRUDE OIL IN VISAKHA

REFINERY

1. Arab mix

Specific gravity at 15/15 Deg C : 0.8726API gravity at 15 Deg C : 30.8

Pour point, Deg C : -26.0

Kinematic viscosity (cst) at 37.8 Deg C : 10.7


Water content % wt : 0.4

Sulphur total % wt : 2.35

Nitrogen total % wt : 0.1

Carbon residue(Conradson ), % wt : 4.95


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Ramsbottom carbon % wt : 4.15

Asphaltenes, % wt : 15.35

Ash content % wt : 0.01

Wax content % wt : 2.75

Saponification No , mg KOH/ gm : 58.0

Total acidity, mg KOH/gm : 0.32

Inorganic acidity, mg KOH/gm : nil

Characterisation factor, KUOP : 11.9

Traces Metal, ppm :

Vanadium : 38

Nickel : 11

Iron : 5

Sodium : 9

Copper : 0.1

Chromium : 0.14

2. Mumbai HighSpecific gravity at 15/15 Deg C : 0.8282

Density, Kg/litre at 15 Deg C : 0.8278

API gravity at 15 Deg C : 39.35

RVP, Kg/sq.cm at 38 Deg C : 0.34

Pour point, Deg C : +30.0


Kinematic viscosity (cst) at 48 Deg C : 3.28

Kinematic viscosity (cst) at 50 Deg C : 2.24

Water content % wt : 0.4

Salt content % wt : 0.0032

Sulphur total % wt : 0.17

Nitrogen total % wt : 0.015

Carbon residue(Conradson ), % wt : 1.2

Asphaltenes, % wt : 0.28Ash content % wt : 0.01


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Wax content % wt : 10.6

Congealing point of wax, Deg C : 58.0

Water and sediments by centrifuge, % vol : 0.2

Total acidity, mg KOH/gm : 0.15

Inorganic acidity, mg KOH/gm : nil

Characterisation factor, KUOP : 11.7

Traces Metal, ppm :

Vanadium : 0.3

Nickel : 1.0

Iron : 0.3

PETROLEUM REFINERY PROCESS

Petroleum refining begins with the distillation, or fractionation, of crude oils into separate

hydrocarbon groups. The resultant products are directly related to the characteristics of the

crude processed. Most distillation products are further converted into more usable products

by changing the size and structure of the hydrocarbon molecules through cracking, reforming,

and other conversion processes. These converted products are then subjected to various

treatment and separation processes such as extraction, hydrotreating, and sweetening to

remove undesirable constituents and improve product quality.

Listed below are 5 categories of general refinery processes and associated operations:

1.Separation processes

a. Atmospheric distillation

b. Vacuum distillation

c. Light ends recovery (gas processing)

2. Petroleum conversion processes


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a. Cracking (thermal and catalytic)

b. Reforming

c. Alkylation

d. Polymerization

e. Isomerisation

f. Coking

g. Visbreaking

3. Petroleum treating processes

a. Hydrodesulfurization

b. Hydrotreating

c. Chemical sweetening

d. Acid gas removal

e. Deasphalting

4.Feedstock and product handling

a. Storage

b. Blending

c. Loading

d. Unloading

5.Auxiliary facilities

a. Boilers

b. Waste water treatment

c. Hydrogen production

d. Sulfur recovery plant

e.Cooling towers

f. Blowdown system

g. Compressor engines


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PRODUCTS AND THEIR

SPECIFICATIONSThe product range of refinery includes :

1. LIGHT DISTILLATES

Constitutes 22 % on crude basis.

a. PROPYLENE:

Propylene also known as propene is the second most important starting product in

the petrochemical industry after ethylene. It is the raw material for a wide variety of

products. Manufacturers of the plastic polypropylene account for nearly two thirds of

all demand. The propylene produced in VR is mainly used in APCL. The propylene

produced has following specifications:

Purity: 95% by wt.

Total sulfur: 5%

Uses : As a petrochemical feedstock in polymer industry.

b. LPG

LPG is basically a flammable mixture of propane and butane. It has

wide variety of uses ranging from domestic purposes to locomotive fuel.

The LPG produced in VR is mainly used in cooking purposes in houses.

VR produces LPG of following specifications:

C5 and higher Hydrocarbons: 2.5%

Total sulphur: 150 ppm

c. MOTOR SPIRIT:

Motor spirit commonly known as petrol is basically a blended product of

many hydrocarbons. It is mainly used as fuel in low locomotives. The

motor spirit produced in VR has following specifications:

Density: 720-775 kg/m3
http://en.wikipedia.org/wiki/Petrochemicalhttp://en.wikipedia.org/wiki/Polypropylenehttp://en.wikipedia.org/wiki/Polypropylenehttp://en.wikipedia.org/wiki/Ethylenehttp://en.wikipedia.org/wiki/Petrochemical


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Research octane number: 91 min

Total sulfur: 150 ppm

Lead content: 0.005 g/ml

Benzene: 1% by vol

2. MIDDLE DISTILLATES

Constitute 52 % on crude basis

d. KEROSENE

Kerosene is one of the major combustible liquids which has wide uses in our daily

life. It is mainly used in cooking purposes. VR produces kerosene of following

specifications:

Smoke point: 18 mm

Total sulfur: 0.25% by wt

Flash point: 35 0C

Uses: As domestic cooking fuel

e. DIESEL:

Diesel is also a blended product like motor spirit. It is mainly used in transportation

purposes. It is used as fuel in higher locomotives.

Cetane index: 46 min

Flash point: 35 0C

Kinematic viscosity: 2-5 cSt

Density: 820-845 kg/m3

Total sulphur: 350 ppm

Water: 0.055 by vol

Uses: As transportation fuel and in power generation

f. JUTE BATCHING OIL

Flash point : 100 0 C

Kinematic viscosity : 15 cSt


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Uses : In jute industry solvent.

3. HEAVY ENDSConsists of 18 % crude basis.

g. FUEL OIL

Water : 1% by vol

Asphaltenes : 10% by wt

Kinematic viscosity : 80-370 cSt

Sulphur : 4% by wt

Pour point : 27 0 C

Uses : As industrial fuel.

h. LOW SULPHUR HEAVY STOCK

Water : 1% by vol

Kinematic viscosity : 5-100 cSt

Sulphur : 1.8 % by wt

Pour point : 66 0 C


Uses : As industrial power generation fuel.

i. BITUMEN

Water : 0.2 % by volPenetration point : 30

Penetration : 30-40,60-70,80-100.

Softening point : 40-55 0 C


Uses : In road paving.


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The specifications of diesel and gasoline to be produced is :

Specifications of Diesel

Existing Bharat Stage II EURO III EURO IV

Sulfur, PPMW Max 2500 500 350 50 (2005)

10 (2011)

Cetane Number, Min 48 48 51 51

Poly aromatics % Max No Spec No Spec 11 11

Density Kg/M3 820-860 820-860 820-845 820-845

Distillation

T 85 Max 350 350 360 360

T 95 Max 370 360 No Spec No Spec

Gasoline Specifications

Present EURO II EURO III EURO IV

ppmw sulphur, max. 1000 500 150 50 (2005)

10 (2011)

%Benzene, max. 3 for

Metros

5 for rest

5.0 1.0 1.0

%Aromatics, max. - - 42 35

%Olefins, max. - - 18 18

RON, min. 88 95 premium

91 regular

95 premium

91 regular

95 premium

91 regular

MON, min. - 85 premium

81 regular

85 premium

81 regular

85 premium

81 regular

RVP, kpa, max. 60 70 60 60

Lead content, g/l, max. 0.013 0.013 0.013 0.013

%Oxygen, max. - Varies 2.7 2.7


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PRODUCTIONThis includes:

1. CDU

2. FCCU

3. DHDS

4. MSBLOCK

%Ethers containing 5 or

more C atoms

- 15 15

%Distilled at 100 deg C,

min.

40 40 46 46

%Distilled at 150 deg C,

min.

75 75


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CRUDE DISTILLATION UNIT

(CDU)It is a primary process unit and consists of CDU I , II, III .

MAJOR EQUIPMENT:

Desalter, Atmospheric column, Atmospheric furnace, Vacuum furnace, Vacuum column,

Preheat exchangers/coolers.

PROCESS:

Crude oil is removed of impurities and salts in desalter. It is then preheated in a

battery of heat exchangers to required temperature from the return streams of

atmospheric and vacuum column and finally in a furnace.

In the atmospheric column, the crude oil is fractionated into 5 streams :

Unstabilized Naphtha, Heavy Naphtha , kerosene, diesel, reduced crude oil.

Unstabilized Naphtha is further processed in Stabilizer where LPG and Naphtha

are separated. Naphtha and diesel are sent to blending pools. ATF & MTO are

produced from kerosene cuts.

Reduced crude oil is sent as feed to vacuum distillation unit. The feed is

preheated in fired heater furnace and the vacuum is achieved with the help of set

ejectors. The different fractions obtained are Vacuum diesel, Low vacuum gas

oil, Heavy vacuum gas oil , Short residue.


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SR is sent to bitumen blowing unit or visbreaking unit. Gas oils are sent to FCC

units.

UNIT FLOW PROCESS DESCRIPTION.

1. DESALTING:

Crude oil often contains water, inorganic salts, suspended solids, and water-soluble

trace metals. As a first step in the refining process, to reduce corrosion, plugging, and

fouling of equipment and to prevent poisoning the catalysts in processing units, these

contaminants must be removed by desalting (dehydration).

Here electrical desalting process is applied. The oil phase and aqueous phase is

separated with the help of a strong electric field. Electric Desalting is the application

of high-voltage electrostatic charges to concentrate suspended water globules in the

bottom of the settling tank. Surfactants are added only when the crude has a large

amount of suspended solids.

The crude received from the off-site storage is pumped by Unit charge pumps. Crude

is preheated to desalting temperature of 129-136 deg Celsius in successive heat

exchangers, utilizing relatively low temperature fluids such as heavy naphtha, vacuumdiesel, kerosene product, heavy diesel product respectively.

Stripped water from sour water stripper and DHDS-SRU is used for desalting. On

mixing, the undesirable salts present in the crude get dissolved in the wash water and

hence get separated from the crude.

Brine from the desalter is sent to sour water stripper unit and then transferred to ETU.


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2. Separation Processes

The first phase in petroleum refining operations is the

Separation/Fractionation/Distillation of crude oil into its major constituents using 3

petroleum separation processes: atmospheric distillation, vacuum distillation, andlight ends recovery (gas processing).

3. Fractionation

The separation of crude oil in atmospheric and vacuum distillation towers into groups

of hydrocarbon compounds of differing boiling-point ranges (relative volatility) called

"fractions" or "cuts."

4. Atmospheric Distillation Tower

At the refinery, the desalted crude feedstock is preheated in exchangers using

recovered process heat. The feedstock then flows to a direct-fired crude charge heater

and fed into the vertical distillation column just above the bottom, at pressures slightly

above atmospheric and at temperatures ranging from 650 to 700 F (heating crude oil

above these temperatures may cause undesirable thermal cracking). All but the

heaviest fractions flash into vapour. As the hot vapour rises in the tower, its

temperature is reduced. Heavy fuel oil or asphalt residue is taken from the bottom. At

successively higher points on the tower, the various major products including

lubricating oil, heating oil, kerosene, gasoline, and uncondensed gases (which

condense at lower temperatures) are drawn off. In order to maximize heat recovery

and balance tower loading, different refluxes are circulated.

The fractionating tower, a steel cylinder about 120 feet high, contains horizontal steel

trays for separating and collecting the liquids. At each tray, vapours from below enterperforations and bubble caps. They permit the vapours to bubble through the liquid on

the tray, causing some condensation at the temperature of that tray. An overflow pipe

drains the condensed liquids from each tray back to the tray below, where the higher

temperature causes re-evaporation. The evaporation, condensing, and scrubbing

operation are repeated many times until the desired degree of product purity is

reached. Then side streams from certain trays are taken off to obtain the desired

fractions. Products ranging from uncondensed fixed gases at the top to heavy fuel oils

at the bottom can be taken continuously from a fractionating tower. Steam is often


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used in towers to lower the vapour pressure and create a partial vacuum. The

distillation process separates the major constituents of crude oil into so-called

straight-run products. Sometimes crude oil is "topped" by distilling off only the

lighter fractions, leaving a heavy residue that is often distilled further under high

vacuum.

5. Vacuum Distillation

In order to further distil the residuum or topped crude from the atmospheric tower at

higher temperatures, reduced pressure is required to prevent thermal cracking. The

process takes place in one or more vacuum distillation towers. The principles of

vacuum distillation resemble those of fractional distillation and, except that larger-

diameter columns are used to maintain comparable vapour velocities at the reduced

pressures, the equipment is also similar.

Topped crude withdrawn from the bottom of the atmospheric distillation column is

composed of high boiling-point hydrocarbons. When distilled at atmospheric

pressures, the crude oil decomposes and polymerizes and will foul equipment. To

separate topped crude into components, it must be distilled in a vacuum column at a

very low pressure and in a steam atmosphere. In the vacuum distillation unit, topped

crude is heated with a process heater to temperatures ranging from 370 to 425C (700

to 800F). The heated topped crude is flashed into a vacuum distillation column

operating at absolute pressures ranging from 350 to 1400 kilograms per square meter


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(kg/m2). In the vacuum column, the topped crude is separated into common boiling-

point fractions by vaporization and condensation.

Stripping steam is normally injected into the bottom of the vacuum distillation column

to assist the separation by lowering the effective partial pressures of the components.

Standard petroleum fractions withdrawn from the vacuum distillation column include

lube distillates, vacuum oil, asphalt stocks, and residual oils. The vacuum in the

vacuum distillation column is usually maintained by the use of steam ejectors but may

be maintained by the use of vacuum pumps.

PLANT CAPACITIES

CDU I

Design capacity : 1.8 MMTPA

Actual feed rates : 300 to 330 m3/hr

CDU II

Design capacity : 3.1MMTPA


CDU III

Design capacity : 3.4 MMTPA



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FLUID CATALYTIC CRACKING

UNITIt is one of the secondary processing unit.

CRACKING

Cracking involves the decomposition of heavier hydrocarbon feedstocks to lighter

hydrocarbon feed stocks.

Cracking can be carried out to any hydrocarbon feedstock but it is usually applied for

vacuum gas oil (VGO).

Cracking can be with or without a catalyst.

When cracking is carried out without a catalyst higher operating temperatures and pressures

are required. This is called as thermal cracking. This was the principle of the old generation

refineries.

Now a days, cracking is usually carried out using a catalyst. The catalyst enabled the

reduction in operating pressure and temperature drastically.

CRACKING CHEMISTRY

1. Long chain paraffins converted to olefins and olefins.

2. Straight chain paraffins converted to branched paraffins.

3. Alkylated aromatics converted to aromatics and paraffins.

4. Ring compounds converted to alkylated aromatics.

5. Dehydrogenation of naphthenes to aromatics and hydrogen.

6. Undesired reaction: Coke formation due to excess cracking.

7. Cracking is an endothermic reaction.

Therefore, in principle cracking generates lighter hydrocarbons constituting paraffins, olefins

and aromatics. In other words, high boiling low octane number feed stocks are converted to

low boiling high octane number products.

CATALYST


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Acid treated silica-alumina was used as catalyst . 20 80 mesh size catalysts used for FCCR

and 34 mm pellets used for MBRs. During operation, poisoning occurs with Fe, Ni, Vd and

Cu.

EQUIPMENT

The major equipment are regenerator, reactor, main fractionators, primary absorbers, sponge

absorbers, main air blower, wet gas compressor, De butaniser, stripper.

PROCESS DESCRIPTIONThe main process technology consists of two flow sheets namely the cracking coupled with

main distillation column and stabilization of naphtha.

The cracking reaction is mainly converting long chain, high molecular compounds to light

weight products for maximisation of CRN and LPG production by value addition of gas oils.

This process employs a catalyst of silica alumina based zeolite in form of very small

spherical particles which behaves as a fluid when aerated with vapour/air .

Vacuum gas oil from vacuum column is pumped to furnace for achieving the desiredtemperature.

Fresh feed is mixed with hot regenerated catalyst and enters the reactor at base of riser where

it gets vaporized at the reactor temperature by the hot catalyst. The gas oil commences to

crack immediately after coming in contact with hot catalyst in riser and continues until the oil

vapours are disengaged from the catalyst in the reactor.

Coke which is generated in the cracking reaction gets deposited on the circulating catalyst in

the reaction zone and the spent catalyst flows from the reactor to regenerator, where coke is


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burnt off, by air. The flue gases leaving from the top goes to CO boiler where steam is

generated.

Vapours from reactor are fractionated in fractionation section into recycle gas oil that returns

to reactor and products like light and heavy cycle oil fractions are routed to blending pools,

Clarified oil, unstabilized naphtha undergoes further treatment to satisfy the environmental

norms and the sent to storage and dispatch.

UNIT PROCESS FLOW DESCRIPTION

1. Feed

Heavy gas oils and light gas oils from CDU unit is the feed for FCC unit. Feed enters

the cracking reactor. Old regeneration refineries use moving bed reactors. Now a

days, fluidized catalytic cracking reactors are used. The cracked product from the

reactor enters the main distillation column that produces unstabilized naphtha, light

gas oil, heavy gas oil, slurry and gas. The products are distilled to give light gas,

gasoline and light gas oil. The heavier products may be recycled or sent for further

processing elsewhere.

2. Reactor

The basic principle of FCCR is to enable the fluidization of catalyst particles in the

feed stream at desired pressure and temperature.


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Another issue for the FCCR is also to regenerate the catalyst by burning off the coke i

air. Therefore, the reactor unit should have basically two units namely a

reactor(FCCR) and a catalyst regenerator(CR). The FCCR consists essentially of two

important components in a sophisticated arrangement. These are the riser and the

cyclone unit assembled in a reactor vessel. Riser: in a riser(long tube), the feed is

allowed to get in contact with the hot catalyst. The hot catalyst is enabled to rise

through the lift media in the riser. The lift media is usually steam or light hydrocarbon

gas. The riser contact time is about 250 milli seconds. The riser is eventually

connected to cyclone units. The catalyst n the vessel is subjected to stream stripping

in which direct contact with steam is allowed to remove hydrocarbons from catalyst

surface.

3. Catalyst Regenerator(CR)

The spent catalyst is sent to a regenerator, where the coke is burned off in air. This

combustion also serves to heat the catalyst The hot regenerated catalyst is then

returned to the riser. Catalyst temperature raised to620 to 750 0C. Lower catalyst

temperature gives partial combustion to CO and needs post combustion. Higher

catalyst temperature gives complete combustion. Flue goes 600 to 760 oC and to 1 to

1.7 bar. Heat recovery from flue gas for steam generation. The spent catalyst which is

relatively cold enters the regenerator unit. Here, air enters the vessel through a sparger

set up. The catalyst is subsequently burnt in the air. His enables both heating the

catalyst(which is required to carry out the endothermic reaction) and removing the

coke so as to regain the activity of the coke. The catalyst + air after this operation will

enter the cyclone separator unit. Unlike the FCCR, the CR does not have a riser.

Therefore, air enters a dense phase of catalyst and also enables the movement of the

catalyst to a dilute phase of catalyst + air. The cyclone separators separate the flue

gas and catalyst as a fluid operation . The activity regained catalyst is sent to the riser

through a pipe. During this entire operation, the catalyst temperature is increased to

620 750 0C. The flue gas is obtained at 600- 760 0 C and is sent for heat recovery

unit to generate steam.


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4. Naphtha stabilization

The naphtha obtained is unstabilized, as it consists of various hydrocarbons. It is

therefore subjected to stabilized by continued processing.

The slurry enters a phase separation unit which separates decant oil and a heavier

product. The heavier product is recycled back to cracking reactor. The unstabilized

naphtha subsequently enters a unsaturates gas plant. In the unsaturates gas plant, the

gas obtained from the main distillation column is sent to a phase separator. The phase

separator separates lighter hydrocarbons from heavier hydrocarbons.

The phase separator is also fed with the unstabilized naphtha. The unstabilized

naphtha from the main column is first fed to a primary absorber to absorb heavier

hydrocarbons in the gas stream emanating from phase separator. The gas leaving the

primary absorber is sent to secondary absorber where light gas oil from main

distillation column is used as a absorbent to further extract any absorbable

hydrocarbons into light gas oil. Eventually, the rich light gas oil enters the main

distillation column. The naphtha generated from the phase separator is sent to

stripping to further consolidate and stabilize naphtha. The stabilized naphtha is further

subjected to distillation in debutanizer and depropanizer units. The debutanizer unit

removes butanes and lower hydrocarbons from the naphtha. The naphtha obtained asbottom product in the debutanizer is termed as debutanized stable naphtha or gasoline


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.The butanes and the other hydrocarbons are sent to a depropanizer unit where butanes

are separated from propanes and other lighter hydrocarbons. Thus, butanes are

obtained as lower product and propanes along with other lighter hydrocarbons are

obtained as the top product in the depropanizer unit.

CATALYTIC CRACKING VS THERMAL CRACKING

Catalytic cracking gives more stable products .

For thermal cracking yield or quality of gasoline.

Catalytic operates serve conditions.

ADVANTAGES OF FCCHeat is efficiently used.

Temperature is controlled.

Catalyst regeneration also controlled.

PLANT CAPACITIES

FCCU -1:

Unit design capacity = 0.95 MMTPA

Unit actual capacity = 1.2 MMTPA

FCCU-2:

Unit design capacity = 0.97 MMTPA

Unit actual capacity = 0.8 MMTPA

PROUCTS:

Fuel gas, LPG, Naphtha, Light Cycle oil, Heavy Cycle Oil, Clarified Oil, Sour water,

Slop.


31/65

Vis breaking unit

It is one of the secondary processing units

EQUIPMENT

Furnace, soaker, main fractionators, compressor, stabiliser, sponge absorber.

Process

Vacuum residue from vacuum column after preheating is heated to desired temperature in

fired heater furnace. Streams coming out of furnace are routed to soaker drum for completing

visbreaking reaction. The soaker effluent streams are routed to fractionators column after

quenching by gas oil generating LPG, naphtha, Gas oil, VisTar.

Plant capacities

Design capacity : 1.0 MMPTA

Feed rate : 110 m3/hr

Bitumen blowing unit

It is one of the secondary processing units

EQUIPMENT

Reactors, heat exchangers, compressors.

ProcessHot vacuum bottoms is cooled to 230 oC in steam generator before entering bitumen

converter where air is blown. Reaction is exothermic and heat is recovered from injecting

steam. Different grades of bitumen are obtained by improving penetration.

Plant capacities


Feed rate : 30 m3

/hr


32/65

DIESEL HYDRO

DESULPHURISATION UNIT(DHDS):

It is a treating unit.

Objective of DHDS unit is to supply high speed diesel with 20 ppm wwt sulphur content with

a capacity of 2.4 MMTPA. The units is set up to remove sulphur from diesel.

The units in this plant are :

1. DHDS unit

2. Hydrogen unit

3. Sour water stripping unit

4. Sulphur recover unit

5. Utilities and off sites


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1. Deisel Hydro De-sulphurisation Unit (DHDS)

MAJOR EQUIPMENT:

Reactor, heater, MGC, RGC, feed filter, stripper, stabilizer, heat exchanger, hot

separator, cold separator, coalescer.

PROCESS:

The sulphur compounds present in the diesel is removed in the presence of hydrogen

and catalyst in the reactor maintained at desired temperature and high pressure. H2S

generated in the process is removed after amine treating in SRU.

It consists of two important process-

Pre de-sulphurisation i.e. reduction of sulphur content from 1000 ppm to 10 ppm

And then reduction of sulphur content to less than 0.5 ppm

2. Hydrogen generation unit

MAJOR EQUIPMENT:

Reactor(Desulphurisation), stripper, heater, vaporiser, reactor(H2S adsorption) ,

Reformer, Steam drum, Degassifier, Pressure swing absorption vessels , Purge vessel.

PROCESS:

Hydrogen required for the DHDS process is generated in the hydrogen plant using

naphtha as a feed and fuel for burning. The steam reforming reaction of naphtha is

high temperature reaction.

3. SULPHUR RECOVERY UNIT

PROCESS

Hydrogen sulphide rich gas DHDS is routed to SRU for recovery of sulphur and

reducing the h2s content in the fuel gas.


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4. LPG MEROX

MAJOR EQUIPMENT

Extractor, caustic pre-wash, disulphide separator, oxidizer, sand filter, caustic settler.

PROCESS

Traces of H2S and mercaptans present in straight and cracked LPG are removed by

oxidizing then into odourless disulfide.

5. CRN MEROX

MAJOR EQUIPMENT

Reactors, caustic settler, sand filters

PROCESS

Cracked naphtha from FCCU mixed with air and routed to a reactor where MEROX

catalyst impregnated on charcoal be removes the foul smelling mercaptans by

converting them to odourless disulfides.

6. ATF MEROX:

MAJOR EQUIPMENT

Coalescer, reactor, water washer, caustic settler

PROCESSKerosene along with air is routed to the merox reactor where mercaptans are

converted to disulfides. Entrained caustic is separated out and moisture, extraneous

matter are removed in filters. This helps in manufacture of ATF.

The feed to this unit is a blend of Straight run and cracked gas oil from storages and

refineries in order to produce low sulphur content diesel oil. This unit consists of four

major sections:


35/65

DHDS reaction section

Amine absorption section

Stripping section

Naphtha stabilizing section

DHDS reaction section is a hydro treating process, which mainly consists of two

kinds of reactions:

Refining reaction

Hydrogenation

1. Refining reactions.a. Desulphurisation

Mercaptans, sulphides, disulphides easily react leading to corresponding saturated

or aromatic compounds sulphur combined into cycle of aromatic structures like

thiophene is more difficult to eliminate. This reactions lead to H2S formation and

H2 consumption.

b. Denitrification.

The Denitrification reaction rate is lower than desulphurisation. It occurs in

heterocyclic compounds having aromatic structure. These leads to NH3 formation

and H2 consumption.

2. Hydrogenation reactions

These reactions affect diolefins , olefins and aromatics are exothermic. Diolefins and

olefins converted to saturated compounds. Hydrogenation rate of aromatics are

limited.


36/65

PARAMETERS

1. Temperature

Hydro treatment leads to increase in temperature and eventually lead to increase incoke deposit which should be controlled. Thus temperature is maintained.

2. Space velocity

Lower the space velocity then higher is the reaction rates. As catalyst quantity is

constant space velocity charged by flow rate.

3. Hydrogen partial pressure.

Increase in this will lead to decrease in coke deposit on catalyst and hydrogenation

reaction is enhanced.

4. Feed quantity

It should be a constant. Severity can be with increase with high feed impurities.

Catalyst can absorb silicon, arsenic, metals etc which will affect compounds activity

of catalyst is drastically reduced.

UNIT PROCESS FLOW DESCRIPTION

1. FEED PREHEATING / REACTION / SEPERATION SECTIONS

The part of feed to DHDS is directly brought to upstream units whereas the rest is sent

to the surge drums level control. The feed blend is filtered though feed filter package

and sent to feed surge drum. Surge drums generate turbulence in the feed flow so that

the feed flow rate does not affect the centrifugal pumps that pump the feed into the

columns.

The liquid phase feed is pumped with the hydrogen recycle. With this we are able to

ensure an adequate hydrogen partial pressure at the inlet of the reactor train.

Polymerisation inhibitor is injected by antifouling agent pumps in the fresh feed

before the feed pump. The make up gas flow rate to the reaction section is controlled

by means of a compressor spill back. The make up gas joins the recycle gas upstream.


37/65

The combined make up and recycle stream is routed to the recycle gas compressor.

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. The reactor effluent is split in to two (to

maximize the heat recovery), then mixed together before it enters the effluent

exchanger. To avoid ammonium salt deposits and risk of corrosion, water is injected

at the inlet of effluent gas air condenser by washing water pumps. The sour water

containing ammonium salts is partly recycled to the washing water drum under level

control of cold separator boot.

Only some part of the gas phase from the cold separator goes to the high pressure(HP)

amine absorber. From here, H2S is removed. The rest bypasses the absorber and is

directly routed to the recycle compressor drum. This bypass allows for control of H2S

concentration. In the HP amine absorber, the gas is washed by 25%wt.

1. STRIPPING

The liquid hydrocarbon phase of the cold separator is the stripper feed. First it is

preheated by the heat exchanger to reach the required stripper inlet temperature. Light

ends and H2S gather at the top of the stripper. Inhibitor is injected in the stripper

overhead line. The stripper outlet compressing three phases is separated in the stripper

reflux drum. The vapour feed to the low pressure(LP) amine absorber and vapour

generated from flashing of rich amine from HP amine absorber is washed by lean

solution to remove H2S. Later the vapour from this section is sent to the LP absorber

drum.

The decanted water from the stripper reflex drum is sent under boot level control to

the washing surge drum. The hydrogen liquid phase is split into reflux which is

returned to the stripper. The stripper feed is fed to the top of the naphtha stabilizer.

This stabilizer is reboiled.

A part of the stripper bottom is sent to reboil the stabilizer bottom and later mixed

with the original stream. Final cooling is achieved in the hydro treated diesel cooler.

The free water contained in the product is removed and routed to the washing water

drum.


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2. CATALYST REGENERATION

During catalyst regeneration a mixture of nitrogen and oxygen is circulated by the

recycle compressor through the reaction section. The reactor effluent is neutralised by

the injection of ammonia before being cooled. Caustic soda is also pimped by thewashing water pump into the mixture to control the salt deposit. The spent caustic

soda is sent for recycling. The make up oxygen in the system is made by plant air

through the make up compressor.

Reactions:

Elimination of Sulphur

Elimination of nitrogen and oxygen

Elimination of metals Saturation of olefins and diolefins

PLANT CAPACITIES

DHDS

Unit design capacity : 2.43MMTPA

Unit actual capacity : 2.43MMTPA

LPG MEROX

Design capacity: 35.9 m3/hr LPG

CRN MEROX

Design capacity: 86.8 m3/hr

ATF MEROX

Design capacity: 39.28 m3/hr

PRODUCTS

Hydro treated diesel, Stabilized Naphtha, Rich Amine and fuel gas from LP absorber,

sour water, Desulphurised diesel.


39/65

MS BLOCK

The main objective of MS block is to hydro treat straight run naphtha and heavy run naphtha

from CDUs and even from VBUs and removal of sulphur , nitrogen and other impurities from

the feed. Each unit of MS block has targeted qualities of octane number, olefins content,

aromatics content, parrafins content which is blended in the MS pool.

MS block consists of five major units :

1. NHT

2. NIU

3. CCR platforming

4. CCR cyclemax

5. FCC NHT

3030

SRN+HN

FROM CDUS918(2754){114750}

PRIME G+HDS

PRIME G+SHU FCCNSU

NIU

CCR573(1719){71625}

NHT NSU

LT. FCC NAP 303 (909){37875}

REFORMATE 511 (1533){63885}

GAS

TOS

RU

INT

2.33(6.98){291}

LT. NAPHTHA TO NAPHTHA POOL 181 (543) {22625}

LPG 17.5 (52.4){2182}

1.

03

(3)

{129}

7.76

(23 .2){ 9 70 }

3.

23

(9.

7)

{404}

CCR H2 GAS GROSS 43.5

NET H2 GAS EXPORT29.15(87.5){3644}

OFFGAS 1.72 (5.2) {215}

LPG 14.4 (43.2){1799}

LT.ISOM.104.5 (313.4){13058}

HVY.ISOM.45.17 (135.5) {5646}

GAS TO SRUINT

GAS TO SRU INT

HVY. FCC TREATED NAPHTHA385(1155){48125}

FCC NAPHTHA688(2064){86000}

ISOM FEED162.5 (487.5) {20313}

DOMESTICNAPHTHA

120

EXPORTNAPHTHA

117

PREMIUMMS390

REGULARMS

263

HVY. FCC NAPHTHA385(1155) {48125}

LEGEND :MTPA (TPD){kg/hr}MS-BLOCK BLENDS FOR ITB CASE

8.33 MMTPA

LPG FROM MS BLOCK: 31.8PRU LPG : 172TREATED LPG : 150

TOTAL LPG : 353.8

14.35

EURO-IIMS

650

42

196

84

68

20

90

66

87

42

225

153

230

72

45

DHDS NAPHTHA 11.0

109

OFFGAS 0.91(2.7){113}


40/65

NHT

Equipment

HDS reactor , stripper, charge heater, splitter and splitter reboiler

1010

Feed surgedrum

HeaterCold sep

Stripper NaphthaSplitter

Light Naphtha to ISOM

Unit

Heavy Naphtha to CCR unit

Off gases

NHT reactorSchematic sketch of NHT

Make-up Hydrogen +Recycle gas

Process

The sulphur present in the straight run naphtha is removed in the presence of hydrogen and

catalyst in the reactor maintained at desired temperature high pressure .Hydrogen sulphide

generated in the process is removed by stripping. Sweet naphtha splits into light naphtha(

feed to isom) and heavy naphtha(feed to CCR ) in splitter.

Unit process flow description

1. Feed

SRN an heavy naphtha from CDU is stored in feet surge drum and send to the reactor

by centrifugal pumps.

2. Reactor

Naphtha from the pumps is combined with hydrogen rich recycled gas from the

recycled gas compressor.

The combined feed is preheated by reactor stream by a set of heat exchangers. Then

it is further heated in a heater to the required temperature for the activation of the

catalyst. Then it is send to the NHT reactor. The NHT reactor removes sulphur,


41/65

nitrogen and other contaminants from the feed with the help of down flow catalyst

bed.

The catalyst used are aluminium and compounds of Ni and Mo. Reactor effluent

passes through the product condenser to condense naphtha vapours to low

temperature to recover naphtha and then enters the separator.

The separator is provided with water wash to wash off the salts and then separated

into 3 phases that include liquid naphtha , sour water and hydrogen recycle gas .

The hydrocarbon liquid from the separator is routed to stripping section to stripper

feed bottom exchangers where it is preheated. The sour water is send to sour water

stripper. The hydrogen recycle gas is recycled by a recycle compressor to combine

feed exchanger.

3. Stripping section

The hydrocarbon liquid from the separator is reboiled in a reboiler using VHP steam.

It is then sent to the stripper where H2S, water traces , light hydrocarbons , hydrogen

is stripped off at the bottom. The overhead vapour is sent to air cooler and then to the

stripper receiver where the vapour is sent to the splitter. The lighter hydrocarbon

collected from the stripper receiver is returned back to the stripper. Then any water

molecules condensed is routed to sour water stripper. The off gas from the splitter

receiver is removed under high pressure control to SRU.

4. Splitter section

The splitter splits hydro treated naphtha to light naphtha which is sent to the NIU unit

feed and heavy naphtha to CCR platform unit.

The splitter overhead vapours from top naphtha splitter is condensed by the

condensers and cooled. It is then sent to the splitter overhead receiver which is

pumped has light naphtha. A part of light naphtha is sent to NIU unit and other part is

pumped back to the splitter.

The splitter bottom is also divided into 2 streams. One part of the stream is sent to the

splitter reboiler, the other part is cooled in exchanges and the heavy naphtha

temperature is dropped to the atmospheric temperature and then sent to storage.


42/65

Plant capacities



NIU

Objective

Isomerisation of light hydro treated is carried out in series of two fixed bed reactors. Benzene

hydrogenation is highly exothermic , so separate bed reactor, installed upstream of twoisomerisation reactors. To limit temperature across hydrogenation reactor a part is cooled is

recycled to reactor.

The C5 or C6 isomerisation converts C5 /C6 parrafins to isoms and higher octane branched

arrangement over Pt catalyst in presence of hydrogen.

Reaction depends on equilibrium operations conducted . The low octane methyl pentanes and

unconverted n-hexanes are recycled back to the isomerisation reactor to achieve RON 88.5

minimum accuracy to estimate value.

Stabiliser column is used to remove light ends from reactor and remains effluent to

deisohexaniser (DIH)

DIH is used for removing and recycle low octane methyl pentanes and unconverted n-

hexanes . 2,3 dimethyl butanes , 2,2 dimethyl butanes and 2 methyl butanes are sent to MS

pool and bottom stream to LPG recovery.

The stabiliser reflux drum contains LPG, hydrogen, chloride which is sent to LPG recovery

via caustic scrubber where chlorides are removed by neutralisation with caustic soda.

Equipment-

Hydrogenation reactor , isomerisation reactors, flash drum, stabiliser column, deisohexaniser,

hydrogen dryers. Naphtha dryers, LPG separator drum, Scrubber drum,H2 gas compressor.


43/65

C4ISOMERIZATION

C5AND C6ISOMERIZATION

Process

The objective of isom unit is to process light naphtha from NHT to obtain high octane

number gasoline. Benzene content in light naphtha will reduced to cyclohexane in thehydrogenation reactor and n-paraffinic HC present in light naphtha get converted into

isoparrafins by isomerisation reaction. LPG and fuel gas are the by products in the process.

Light isomerate and heavy isomerate are the products from the unit which are routed to

gasoline pool of the refinery.


44/65

Unit flow description process

1. Dryer section

The light naphtha is fed to the feed surge drum is pumped into the dryers in series.

Feed dryers protect the isomerisation catalyst from moisture air and water whichdeactivates or poisonous to it.

Hydrogen from the CCR is taken to the knock out drum and then compressed and

cooled. Part of it is sent to FCC-NHT.

Dried hydrogen is mixed with dried naphtha and sent to benzene hydrogenation

reactor.

2. Hydrogenation section

Combined two phase fed is preheated in reactor and mixed with diluents recycle from

hydrogenation reactor and then heated by HP steam to reaction temperature.

Benzene is hydrogenated to cyclohexane which is highly exothermic reaction and

then sent to flash drums. A part of it free from benzene is sent to isomerisation

reactors.

Incase of high benzene content, the diluents is cooled to control isomerisation reaction

temperature. Diluents recycle should not exceed

30 oC for exothermicity in hydrogenation reactor.

3. Isomerisation reactor

Isomerisation reactor feed from flash drum is mixed with hydrogen and small amount

of chloriding agent in order to maintain chloride balance on isomerisation catalyst .

the first stage isomerisation reactor converts C5 into methyl butanes which is then

cooled and set to second stage isomerisation reactor. In the second stage reactor C6

are converted to methyl pentanes which are further converted to di methyl butanes

and enters the stabiliser .

4. Stabilizer section

C1 to C4 hydrocarbons are removed from the top of the column. LPG , hydrogen, HCl

are stripped off to LPG recovery section via caustic scrubber. The bottom is sent to

deisohexaniser column via chloride bed where the chloride is removed.


45/65

5. Deisohexaniser

The feed from the DIH ump is pre heated and fractionated into 3 columns. The top

part is the light isomerate which is stabilised in the MS pool while the bottom is the

heavy isomerate which consists of 7 , C6 and naphthenes which is sent to LPG

recovery section for lean oil makeup.

The low octane methyl pentanes and n-hexanes are recycled back to the reactors.

6. Scrubber section

It is caustic treated and water washed before being release to LPG recovery section.

The off gas enters bottom of the caustic scrubber. The gas leaving caustic wash

section is washed with water to top pa section to remove entrained caustic and then to

LPG recovery section.

7. LPG recovery section

The dry off gas is sent to LPG refrigeration system and then to LPG separate drum

where it is separated as gas and liquid phase. Stabiliser and lean gas gives LPG.

8. Dryers regeneration

The naphtha feed and hydrogen scrubber off gas are sent to respective dryers in series.

Feed H2 scrubber of gas dryers are regenerated to vaporised deisohexaniser distilled.

9. Chloride injection facilities

For isomerisation reactions tetra chloro ethylene , C2Cl4 is recommended as chloride

agent. , C2Cl4 is converted into HCl and with the addition of NaOH is converted into

NaCl which is removed in the caustic scrubber.

Plant capacities




46/65

CCR

Equipment

CCR reactor, Stabiliser, De ethaniser, Charge heater, inter heaters, cyclemax

regeneration section.

The objective of CCR unit is to process straight run gasoline to obtain high octane

number gasoline.

Process.

Naphthenic and paraffinic HC present in heavy naphtha get converted into aromatics

by catalytic reforming reactions in platformer at desired temperature and low pressure

in presence of platforming catalyst. Hydrogen and LPG are by products in this

process. Stabilized reformate is routed for blending of motor spirit. Catalyst

deactivates in the reaction due to coke formation and the same can be regenerated

continuously in CCR cycle max regeneration section and reused.

CCR Platforming

Objective

n-parrafins and iso parrafins are converted into cyclo pentanes and then into

cyclohexane and thus aromatics needed for MS pool.

More amount of naphthenes and less amount of parrafins are needed for production

of aromatics.

In reactor aromatics pass unchanged but naphthenes get cconverted to aromatics .

main carbon used are C6-C7. Rich naphtha feed is used from NHT.

Hydrogen rich gas from DHDS ia imported to start CCR platforming.


47/65

Unit flow process description

1. Feed section

Heavy naphtha from NHT bottom splitter is preheated by reactor effluent and

treated with sulphur injection, perchloroethylene injection and cold condensate

injection.

Chloride needed to maintain acidic sites for catalyst for isomerisation reactions to

occur and water to distribute chlorides throughout catalyst. The reactor effluent

moves in one direction while cold stream moves in opposite direction in heat

exchanger thus leading to heat transfer in feed .the hydrogen rich gas is heated up

to maintain hydrogen/hydrocarbon ratio for catalyst.

2. Reactor

Catalyst stability should be maintained. Steam generation from the flue gases in

heaters to HP and MP steam. It consist of four reactors :

a. Interheater no 1b. Interheater no 2

c. Interheater no 3

d. Charge heater

Effluent from each reactor stage is heated and enters the next

reactor to maintain temperature . hydrogen gas is stacked back

and sent for recycle. Gas stream hydrocarbon is purged and

spent catalyst is sent for regeneration of CCR section.

The cold effluent from the reactors is sent to the separators.


48/65

3. Separator

The cold effluent is separated as hydrocarbon stream and hydrogen rich gas.

In the hydrogen rich gas part of it is sent as recycle to reactor and CCR

regeneration section, while remaining of the gas is cooled off and sent to

recontacting section. The hydrocarbon stream from top is sent to recontacting and

fractionation.

4. Recontacting section

The hydrogen C1,C2,C3,C4,C5 from the separator is sent to the recontacting

section. It enters the first stage reactor where it is cooled and the gas coming from

the first stage discharge is sent to second stage reactor where is again cooled and

sent to second stage discharge. The liquid from the first and second stage

discharge and the liquid hydrocarbon from separator is sent to the stabilizer.

The off gas coming out of second stage discharge is routed to remove chlorine and

the sent to LPG recovery section by adding propane to chiller and above product.

5. Stabilizer

The product is preheated and then sent to stabilizer column where overhead gas is

recycled to first stage suction drum , overhead liquid in which some part is sent

back as reflux and other part is sent to de ethaniser and then to chloride unit to

recover stabilised LPG as bottom product and while the bottom rich reformate to

sent to MS pool.

The catalyst used is chlorided Al base . the reformates consists from C5 .

CCR cyclemax

It consists of catalyst regeneration and catalyst circulation.

1. Catalyst regeneration

It basically includes :

a. Coke burning

b. Oxychlorination

c. Drying in regeneration tower

d. Reduction zone


49/65

2. Catalyst circulation

The catalyst is transformed from platforming reactor to regeneration reactor.

Spent catalyst flows from bottom of last reactor to catalyst collector.Circulators N2 from lift gas blower engages catalyst lifts to disengaging

hopper .in hoper fine removal blower separates the additional fines and

nitrogen from catalyst from the top gas. Fines are collected in the dust

collector and nitrogen circulates back.

Whole catalyst drops from regeneration tower by gravity to nitrogen seal drum

and then to lock hopper. Then the hydrogen rich gas from recontact engages

catalyst and lifts it through catalyst lift line in regeneration zone to top of first

reactor and then catalyst collector.

The spent catalyst is the catalyst that leaves reactor purged to remove

hydrocarbon . Catalyst environment is changed from hydrogen to nitrogen

and done during lift operation of catalyst from bottom of reactor to top of

regeneration.

The regenerated catalyst environment is changed from nitrogen to hydrogen

from bottom of regenerator to top of reactor.

Regeneration tower catalyst passes through :

a. Burn

b. Reheat

c. Chlorination

d. Cooling zones

e. Drying

Two ways to operate regeneration :

1. Black burn

The burn and reheat zone contains oxygen while chlorination, drying,

cooling contains N2 . It is used when coked catalyst is in chlorination,

drying, cooling zone and restarting regeneration tower.

2. White burn

The burn and reheat contains oxygen while chlorination, drying,

cooling zone contains air. It is operated in regeneration tower.


50/65

Oxychlorination needs air and chlorine. It is used to redisperse metals

after burning and adds chlorine to catalyst. After black burn no coked

catalyst should go into zone and it be devoid of coke and then white

burn is started. It is important to start regeneration in white burn if

there is a risk of coked catalyst below burn zone. Otherwise high

temperature will lead to catalyst phase change and loosing activity.

Plant capacities



FCC NHT (PRIME G+)

Equipment

Feed surge drum, Selective hydrogenation unit reactor, Splitter column, HDS reactor ,

Stabiliser, Amine absorber etc.

Objective

The objective of FCC NHT is to process FCC gasoline to obtain product streams(Light

gasoline and heavy hydrotreated gasoline ) with targeted qualities of octane number, sulphur

content, benzene content and olefins content. Prime G+ provides us to meet EURO-

3/EURO-4 specifications of gasoline wrt :

Diolefins : nil

Olefins : 18% Max

Sulphur : 50 ppm

Benzene : 1%


51/65

2121

Schematic sketch of FCC NHT unit

Light FCC gasoline to MS pool

SHU FCC Naphtha

SplitterUnit

HDS

Heavy FCC gasoline toMS pool

Process

FCC CRN from FCCU unit is taken to the unit as hot feed. The CRN is taken to the feed

surge drum. CRN is then pumped to a series of heat exchangers and enters into selective

hydrogenation unit reactor. The purpose of the reactor is to convert diolefins to olefins and to

convert Mercaptans and lighter boiling sulphur compounds in the feed to higher boiling

sulphur species.

The outlet from the SRU reactor is routed to splitter where light naptha, heart cut naphtha and

heavy naphtha is separated. Light naphtha is directly routed to MS pool where as heart cut

naphtha which is rich in benzene content is routed to NHT unit.

The bottom heavy naphtha is passed again through series of heat exchangers and routed to

hydrodesulphurisation reactor (HDS reactor). Here the sulphur of the heavy naphtha is

reduced to allowable extent and the Desulphurised heavy gasoline (HCN) from the HDS

reactor is routed to naphtha stabiliser. The HCN is stripped off any dissolved H2S or lighter

compounds like C1.C2s and the stable HCN is routed to final refinery MS pool.

Unit process description flow

1. Selective hydrogenation unit

The feed from the FCC CRN and FCCU is preheated and send to feed filter. From

the feed filter it goes to SHU feed surge drum where the pressure is controlled and

pumped to SHU feed pumps. H2 makeup from the unit is mixed with the fresh feed.Then it enters the tube side of SHU feed and the mixture is heated by the heat of HDS


52/65

effluent. It then enters the SHU pre-heater and at proper reactor inlet temperature it

flows to SHU reactor where the hydrocarbon mixture is heated. The SHU reactor

consists of 2 beds catalyst to optimise and provide selective hydrogenation of

diolefins in feed and convert light Mercaptans into heavier boiling temperature

sulphur compounds. The SHU feed filter then enters the splitter.

2. Splitter section

The splitter section consists of 52 trays. The feed enters at the 19 th tray from the

bottom where it is fractionated to produce LCN and HCN. The splitter overhead is

condensed by air cooling in the splitter overhead air condenser. Vapour is separated

from the reflux liquid in splitter reflux drum. The splitter is again condensed and the

vapour is purged by split range control of pressurising hydrogen and venting the fuel

gas header. The reflux is then pumped to the pump by splitter reflux. The tray number

48 accumulator gives LCN which is cooled and stored. The splitter bottom is reboiled

by steam and heavy naphtha is sent to HDS unit. In tray number 36 benzene heart cut

is obtained which is cooled by air cooler and sent to storage.

3. HDS [Hydro Desulphurisation Unit]

Heavy naphtha from the splitter enters the HDS feed drums which is mixed with

recycled hydrogen. The HDS feed effluent is then divided into 3 beds where it is

heated and the inlet temperature is controlled by fuel gas and the bottom product leads

to hydrocarbon liquid. The heater is simultaneously cooled by HDS effluent cooling

air and washing water injection to flush salt deposits formed.

A part of hydrocarbon liquid is sent back to the HDS and the other part is sent to the

stabiliser section. The vapours from the stabiliser section are sent to the amine

knockout drum which is free from condensed liquid hydrocarbon by the help of

demister. From the knockout drum it enters the amine absorber where it is pre-heated

to maintain 100C and then contacted with DEA solution to remove H2S gas. The H2S

enriched DEA is sent to DEA regeneration unit where the part of the gas is purged to

fuel gas while the other part of the sweetened gas is mixed with hydrogen maker and

sent to recycle compressor knockout drum and back to HDS reactor.

4. Stabiliser section

The liquid is heated by the stabiliser feed bottom and sent to the stabiliser column. A


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part of the liquid phase is cooled in the stabiliser overhead cooler and then sent to the

stabiliser reflux drum, while water phase is sent to the sour water treatment and in the

vapour phase the pressure is controlled by the gas flow. The other part of the liquid

phase coming from the stabiliser bottom is reboiled by VHP steam bailer which is

separated into 2 streams. Then the bottom product is treated and sent to MS storage

pool while the other part is cooled by stabiliser feed and heavy gasoline is obtained

which is recycled back.

Plant capacities




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POWER AND UTILITIES

The main plants in utilities are :

1. Raw water systems

2. De mineralised plant

3. Power plants I &II

4. Captive power plant

5. Cryogenic nitrogen unit

6. Flare system

1. Raw water systems

Raw water is received from Tatipudi, Raiwada and Mindi reservoirs. There are high

lift pump house and low lift pump house for sourcing sea water for cooling process

streams and fire fighting systems.

There are cooling water towers to provide cooling water to cool equipments. Drinking

water plants to satisfy drinking water demand in refinery.

The water system from Yarada bore well was used but stopped later on due to the

contamination of ground water system.

There are 3 types of water systems:

a. Raw water system

Water from Tatipudi and Mindi is sent to the de mineralised plant and power plant

I depending on the equitability of water. If the pump is tripped or failed,

alternative sources are used and maintenance is done.

b. Service water system

It was installed during the time of VREP I and VREP II. From PP I service water

is sent to VR and VREP II and then sent to CDU I, CDU III, FCCU, flairs and

desalters. From VREP I service water is sent to desalter CDU II and BBU.

c. Drinking water

The drinking water consists of PSF and activated carbon filters. Filtered water is


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chemically dosed and stored in drinking water sump. In sump NaOCl is added to

kill bacteria and free residual chlorine is maintained.

2. Demineralised plantEquipment:

Sand filter, Strong acid cation , Weak base anion, Strong base anion, Degasser ,

Mixed bed.

Process:

Raw water is processed in ion exchangers to get demineralised water. The latest

technology used in VRCFP for demineralising water is reverse osmosis. Morpholine

is used to maintain pH of water.


1. Alum dosing tank

There is a mixer and level gauge, depending on how raw water is analysed

percentage of aluminium dosage is prepared and used. Suction line is provided

with strainer.

2. Alum dosing pump

Flow adjustment depends on raw water turbidity. For light particles dosing is not

enough so poly electrolyte is added. In laboratory alum dosing quantity is

determined to have better filtration in PSF.

3. Sodium sulphite dosing tank

Mixer and level gauge, suction line are provided with strainer.

4. Sodium sulphite dosing tanks

Delivery line is connected to PSF inlet.

5. PSF [pressure sand filters]

To measure the differential pressure a DP indicator is used. In PSF mechanicalfiltration of coagulated raw water is achieved and turbidity is reduced. Non ionic


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and suspended impurities like dirt, salt and mud is removed.

6. SAC [strong acid cation]

There are 2 co-flow operation pipes and 1 counter current regeneration. After 10

cycles or when DP is greater than 0.8kg/sq cm it is back washed.Ca2+, Mg2+,Na+

are removed by exchange of H+ ions in the resins and convert into acids. It is

then passed through degassed tower.

7. Degassed tower

The water devoid of cations is passed to degasser air blower.

8. Degasser air blower

Low pressure and high velocity is maintained here. Degasser water is sent from

top to bottom of the blower while the air from bottom to top. When H2CO3 comes

in contact with O2 and splits as water and CO2 which blows out of the vent hole.

Residual free CO2 is maintained in degasser storage tank.

9. Degasser water storage tank

It is an inlet to air blower and outlet to water pumps degasser.

10. Degasser water pumps

There are 3 service pumps and 1 standby pump. The degassed water is transferred

to WBA/SBA for further ion exchange. A part of water is sent to SAC for

regeneration.

11. WBA [weak base anion]

There are 2 pipes in service and 1 in standby for regeneration. It exchanges load

such as Cl, NO3, SO4 from degassed water. Outlet is checked by conductivity test.

12. SBA [strong base anion]

Weak acids such as leakages from degasser, traces of chlorides and silica is

exchanged to OH form. It is then sent to MB polisher units.


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13. Mixed bed

Anion and cation resins are in mixed form. Due to differences in specific gravity

both cation and anion resins are separated in back wash. First anion resin is

regenerated and then the cation resin. Both resins are then mixed with mixed bed

blower and anions are trapped in resins. It is then stored in DM storage tank.

14. DM storage tank

The demineralised water is stored here and sent to various units of the plant like

Deaerator, DHDS, CPP etc.

15. Acid day tank

It is used for regeneration of resins.

16. Alkali day tank

It is used for regeneration of resins.

Plant capacities

Design capacity :

DM I : 75 M3/Hr

DM I : 120 M3/Hr

DM I : 180 M3/Hr

3. Power plants

Equipment:

Deaerator , Economiser , Bank tubes , Super heater , CO chamber.

Process :

DM water is processed to generate VHP , MP, HP steam in boilers.

Steam is also generated from the heat conservation of CO. Power plants are mainly

used for steam generation and power generation. Steam is also generated from the

flue gas from the gas turbine gas generators. PP I consists of WIL- 8 , BHPV, NCO ,IBH-9, IBH-10 boiler . PP II consists of WILB , CO, BOP boilers. Water from DM


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plant is sent to Deaerator where dissolved oxygen present is water is removed by HP

steam and then sent to boilers in PP I & PP II.

PP I generates HP, LP, MP steam for CDUs, Desalter, FD fans for boilers.

PP II generates HP, MP steam for deaerators , oil burners and heating systems.

Unit process flow description of boilers :

In a boiler the upper drum is called the steam drum and the lower drum is called the

mud drum which are connected by bank of tubes.

The water cooled furnace wall is welded along with the tube tank. The main tube tank

forms one side of the furnace and the water wall tubes cover the opposite wall. The oil

burner is mounted on brick lined wall in boiler front area. The furnace front is fixed

and is free to expand in the rear along the length of the drum. The furnace D wall

tubes joining both steam and mud drum, and located on the roof as well as floor of the

furnace cool the refractory.

Superheater is of single element drainable type. It is located between the upper and

lower drums at the end of the furnace. Combustion gases pass over superheater

element before entering the main tube tank .It is also called the conventional radiation

section. Dry saturated steam from the steam drum passes through the inlet header of

superheater via super heating connecting pipes by absorbing the convection heat. The

saturated steam gets converted into superheated steam. It then passes to the main

steam line.

The economiser is located in the second pass of the boiler. The tubes bare are

arranged in horizontal rows. At tube circuits originates from inlet header and

discharge to outlet header. Feed water is supplied to the economiser inlet header and

after being preheated goes to the steam drum. In the process, waste heat is recovered

from the flue gases.

Boiler tank tubes, water wall tubes and the furnace wall tubes are rolled into the

drums by expansion. Other connections like feed water line, safety valves and

saturated steam are strength welded to drums.

Steam drum capacity is more than that of mud drum. It is large enough to provide

adequate storage capacity and minimise water level fluctuation causing out of sudden

change in steam demand. It is also provides space for internals. The objectives of

drum internal is to reduce the moisture content in saturated steam leaving drum by


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mechanical means. This helps in reducing the proportion of solid content in steam and

sending a dry saturated steam to the sulphur heater. Steam that enters the drum is

collected in the compartment formed by baffles. The baffles completely reverse the

direction of flow. In the process, steam loses most of its entrained water. Thereafter it

flows over the corrugated sheet. The provides steam with tortuous path and thereby

forcing any remaining entrained water against corrugated plated. Since the velocity is

relatively low water cannot be picked up again and therefore runs down the

corrugated plate and returns to the lower part of the drum.

The direction of steam si reversed again before entering the series of holes in dry box.

Dry steam leaves the drum through inlet nozzles.

In addition to the water separation system, the internals also consist of feed water

distributing pipe running along the length if the stream drum, blow down piping

which has uniformly pitched smaller diameters holes through which a portion of water

of high solid can be tapped off. Gauge glass to detect water level and a main blow

down piping connected to the mud drum.

Fuel gas leaving the economiser enters the stack through a duct, which is provided

with a damper and a discharge to the atmosphere.

Soot blowers are provided to remove the soot deposited on the tubes. Soot is removed

to increase the heat transfer and also to avoid local and secondary burning.

In the rotary blower remains in the boiler at all items supported by element bearing

usually attached to the booster tubes. Specially designed nozzles are located on the

element for each specific installation . dry saturated steam is used as blowing medium

to prevent penetration of corrosive fuel gases through the element to the head valve a

scavenging air check valve is furnished. The soot blowing element is driven by a

motor.

Plant capacities :

PP I :

WIL 8 : 50 T/Hr

BHPV : 50 T/Hr

NEW CO : 40 T/Hr


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PP II

CO : 60 T/Hr

4. Captive power plantEquipment :

Gas turbine generators , Deaerator, HRSGs ,Economiser , bank tubes ,Super heater

Process:

Naphtha is used to run a gas turbine generator and thus produce power to cater the

demands of the whole refinery.

This also helps to generate steam using flue gas from GTGs .

It is used in cogeneration of steam and power leading to more energy efficient use of

fuel as compared to a conventional power plant. The fuel used is 4 naphtha tanks and

2 diesel tanks to supply for GTGs.

Unit process flow description :

1. Gas turbines

MS3002 is for GTG 1 & 2 in VR. The equipments used are diesel engine, torque

convertor, accessory gear box, gas turbine, load gear box, generator, complete set

of lube oils. High pressure air is added to one side of compressors while in the

opposite direction fuel addition takes place in the combustion chamber. The

combustion consist of 15 stage compressors and 6 combustion chambers and

products are directed to nozzles under high pressure turbines. Gases from high

pressure are reduced to low pressure and given out. MS5001 is for GTG 3 & 4 in

VREP I. This consists of 17 compressors and 10 combustion chambers and 2

stage turbines are used for output.

2. Generators

It is coupled with the gas turbine through gear box that reduces turbines speed.

The DC current enters the generator and then the automatic voltage regulator to

keep voltage constant. The various electrical instruments are 1 KV switch gear,

LT switch gear, 3 KV switch gear, uninterrupted power supply and CT switchgear.


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3. Heat recovery steam generator

Deaerator provides water for HRSGs. They are used to recover heat from turbine

exhaust gases. They is natural circulation single pressure horizontal duct fired

water tube boiler. The firing facility is also and steam production in HSRG is

done. The power from CPP is supplied to DM plant, feed water facilities and

Deaerator .

PLANT CAPACITIES

GTGs : 7.18 & 21.31 MW

HSRGs : 27 & 60 T/Hr

5. Flare system

Equipment:

Flare tip, Flare stack, Fluidic seal , Flame front generator, Water seal drum, Knock

out drum , Blow down pumps

Objective :

Flare facilities are provided in order to avoid releasing of in burnt hydrocarbons to the

atmosphere. Facilities exists for injecting steam to stack for smokeless flare for

refinery.

In view of additional hydrocarbon load subsequent to VRCFP commissioning,

additional flare facilities are provided in order to avoid releasing of un- burnt

hydrocarbons to the atmosphere.

This flare system also comprise of a separate AAG flare which is non smokeless type.

The liquid hydrogen discharges and separates to slop tank and knock out drums.

The existing system consists extremely toxic gases coming from VR & VREP I. CDU

I, CDU II, FCCU I. FCCU II, FCCU III & PRU total load is 698.5 tonnes/hr.


1. Collection of gases

Gasses from CDU III, VBU, FCCU I, PRU, SRU, DHTS, CDU II, FCCU II, CDU

I are passed from the headers to the final knock out drum and then condensed

hydrocarbon is separated in the KO header to water seal drum and then the gases


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go to the flare stack where it is burnt. The flare seal is at stream of flare tip.

2. New flare knock out drum

It is used to trap liquid droplets. Knock out drum receives liquid and vapour where

the liquid droplets are trapped in the KO drum and vapour goes away. Water is

recovered by slope tanks blow down pumps.

3. Blow down pumps

They are motor driven centrifugal pumps. The hydrocarbon liquid in the KO drum

is given to the slope header where BCW requirement is controlled.

4. Water seal drum

Water seal drum is situated at the base of flare stack. It maintains pressure in flare

header to prevent flame flash back. The water is supplied continuous and level is

maintained and entry of air is restricted.

5. Flare stack

The top point is sent to the flare tip while the bottom is sent to flare system

bottom. Then it is sent to check O2 in gases. Continuous flue gas purge is provided

to keep pressure constant.

6. Flare seal

It is a gas lead pipe and it has an inverted cylinder over the lead pipe. The top of

the cylinder is closed while the bottom is opened. The lighter gases are collected

in the upper bend while heavier gases settle down in the lower bend.

7. New flare tip

The tip is on the top of flare system. The upper part of tip is high heat resistant

stainless steel and remainder is carbon steel. The flame is retained at emission

rates. The 3 pilot burners are equally spaced. Then the upper manifold injects

steam into flame at the tip outlet to promote smokeless combustion.

8. New flame font generator

For ignition of pilot, this is installed. It does gas and air mixing, it has a separate


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valve foe gas and air and 3 valves to direct ignition.

Plant capacities

New flare : 698.5 MT/HrOld flare : 284.716 MT/Hr

VRCFP flare : 490.6 MT/Hr

6. Cryogenic nitrogen unit

Equipment:

Air compressors, moisture separator, air purification unit, regeneration reactor,

distillation column, expansion turbine, heat exchangers, cold box, vaporisers.

Process :

1. Air suction and compressor

Air suction filter is compressed by main air centrifugal compressors to control the

pressure.

2. Air pre-cooling

The shell and tube heat exchangers cool the air by chilled water and the moisture

separator condenses water and separates moisture and sends the dry water to the

knock out drum. The cooling water which is cooled by waste N2, comes out of

cold box in the evaporation cooling tower. The chilled water is pumped into after

cooler and the return water is circulated back to evaporation cooling tower where


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the losses are balanced.

3. Drying

Chilled air is passed to the adsorber where saturated moisture , CO2 are removed

by using aluminium and molecular sieves.

4. After filters

After elimination of aluminium and molecular sieve dust the degeneration steam

is mixed with waste air from cold box and heated. The hot gases passed through

the sieves to regenerate absorbents.

5. After cooling

Purified air is cooled down by return gases in heat exchangers. Cooled by GAN

the waste gases from condenser return to the turbines.

6. Distillation

In the distillation column O2 rich liquid and gaseous N2 is obtained from bottom

and top of the distillation column respectively. The rich liquid is throttled and then

vaporised and then condensed.

7. GAN & LIN

A part of GAN obtained from the top part is warmed to ambient temperature while

other part is condensed thus obtaining liquid nitrogen. A part of the bottom LIN is

sent to LIN high pressure storage system while other part is sent as reflux back to

the column,

Plant capacities

Design capacity : 245 Nm3/Hr


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Project Hpcl

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