fcc discription given in detail

1. Project Report On
The Fluidized Catalytic Cracking
Unit
Essar Oil Limited, Vadinar
Submitted By: Guided By:
Himanshu Jain Mr. Dipesh A. Modi
B.Tech (Chemical Engg) DGM (FCCU)
IIIrd year
IT-BHU
1

2. ABSTRACT
This report is prepared at Essar Oil Ltd, Jamnagar as a part of the industrial training
and contains a brief description of the refining process employed in the Essar Oil Ltd.
It mainly focuses on the process description of the Fluidized Catalytic Cracking Unit
(FCCU) and the Unsaturated Gas Separation Unit. The details of the project
undertaken in the same unit as a part of practical training along with the
methodology and the procedure adopted are also included in this report.
Project guide,
Mr.Dipesh.A.Modi
DGM (FCCU)
2

3. ACKNOWLEDGEMENT
It has been an immense pleasure and truly enriching experience doing my
vocational training at Essar Oil Limited, Vadinar.
I take this opportunity to thank all those people who have made this
experience a memorable one. I am heartily thankful to Mr. Sudhir sir (AGM-FCCU),
Mr.Dipesh.A.Modi sir (DGM-FCCU),Mr.Ravindiran Bisht sir for their co-operation
and proper guidance during my training.
I would like to thank my guide Mr. Dipesh Modi, DGM (FCCU) who has been
the guiding force behind the completion of this project. I am sincerely thankful to the
entire team of the FCC unit for their valuable help and guidance in the completion of
my training.
I am also thankful to Mr. Prashant Arya, Joint GM, HR for giving me an
opportunity to work with Essar Oil Limited. I would also like to thank Mrs. Pooja
Joshi and Mr.Ramesh Dhabi, who coordinated my training extremely well.
Finally, I am grateful for the joint support from the Essar Group as a whole for
the opportunity and assistance they provided me to do my training here.
Thanking You.
Himanshu Jain
3

4. PREFACE
Any amount of theoretical knowledge is incomplete without exposure to industrial
practice. Practical knowledge means visualization and application of knowledge
which we read in books. Theoretical studies cannot be perfect without practical
training. Hence, in-plant training is of great importance for an engineering student.
Teaching gives theoretical aspect of technology, but practical training gives
knowledge of industrial activities.
My aim for this industrial training was to optimize the regenerator temperature at
different feed conditions in the Fluidized Catalytic Cracking Unit. For optimizing the
regenerator temperature, I have used Artificial Neural Network in Matlab and
generated a function which will give the output value (here regenerator temperature)
at different feed conditions.
This project report presents a detailed summary of my enriching industrial
experience at the Vadinar refinery.
4

5. Table of Contents
Essar Group Profile
Basics of Refining
Crude Oil
Refinery Plant Overview
Safety
Cracking Process
Chemistry of the Fluid Catalytic Cracking Process
Fluidized Catalytic Cracking unit
Capacity & feedstock
Yield Pattern & Product Routing
Process Description
Project Work
Results-Analysis & Projections
Bibliography.
5

6. Essar Group-Profile
Introduction to Essar
The Essar Group is one of India’s largest corporate houses with interests spanning the
manufacturing and service sectors in both old and new economies: steel, power, shipping,
constructions, oil & gas and telecom. The Group has an asset of US$ 4.4 bn and a turnover
of over US$ 2.08 bn. It employs 20000 people in 50 locations worldwide. Strategic
investments made by the group over the past decade have resulted in the creation of
tangible and intangible assets that are at the heart of the Indian Economy.
The Group takes pride in being a high-performance multinational organization, providing
world class services and products. Manned by a highly efficient and dynamic team of
employees, the Group is growing stronger every day. A committed corporate citizen, the
group provides unwavering support to the community as well as initiates various social and
ecological drives that have a positive impact on society.
All the groups investments have been consolidate under Essar Global Ltd. with its six sectors
holding companies:
Essar steel holdings ltd.
Essar power holdings ltd.
Essar energy holdings ltd.
Essar communication holdings ltd.
Essar shipping & logistics ltd.
Essar projects (India) ltd.
Essar brand name includes:
Vodafone Essar
Algoma Steel
It is headed by Chairman Shashi Ruia & Vice Chairman Ravi Ruia.
Mission
To create enduring value for customers and stakeholders in core manufacturing and service
businesses, through world class operating standards, state-of-the-art technology and the
‘positive attitude’ of our people.
6

7. BASICS OF REFINING
Refining: The process of separating the components of crude oil, progressively
altering and re-blending them to produce fuels like LPG, Motor Gasoline, Kerosene,
Diesel, Fuel Oils , Residual Fuel Oils and Lubricants with maximum yields profitably
with removal of impurities.
Basic overview of a refinery:
The basic processes that take place in a refinery are,
• Separation of components by distillation, e.g.:
 Atmospheric
 Vacuum
 Hydro treating (usage of excess hydrogen)
• Decomposition of molecules to make lighter fractions from heavier products,
e.g.:
 Catalytic cracking
 Hydro cracking
• Unification of smaller molecules to a larger fraction, e.g.:
 Alkylation
 Polymerization
Alteration (Rearranging) of molecules,e.g:
 Isomerization
 Catalytic Reforming
7

8. CRUDE OIL
Crude : Is a mixture of hydrocarbons and impurities of inorganic salts and metals.It
is a complex mixture of Hydrocarbons.
• It is brownish black in color and colloidal in nature with impurities like sulfur,
nitrogen and metals.
• Physically crude oils can vary from light, mobile, strain colored liquids
containing large proportion of easily distillable material to highly viscous, semi
solid black substances with very little material that can be recovered by
distillation
Crude constitutes of:
 Petroleum fractions designated by boiling ranges :
Light gases (C3, C4 ….)
Naphtha
Distillates (Kerosene, diesel)
Gas Oils
Residual Oils
 Ordinary contaminants:
Salt, Water & Sediment.
Sulphur
Nitrogen
Iron, Nickel, Vanadium
Asphaltenes
 Infrequent contaminants:
Acids
Hydrogen sulphide
Mercaptan sulphur
8

9. Crude composition:
Paraffinic: Saturated aliphatic normal Chain compounds constituting
homologues series of general formula CnH2n+2 .
Naphthenic: Saturated compounds appear as a ring structures and also
known as close chain or cyclic saturated compounds.
Aromatic: Unsaturated cyclic hydrocarbons. General formula (CnH2n-6) &
(C2nH2n-12).
 Crude Oil assays are used to perform the above classification
Contents of Crude Assay:
1. Whole Crude data.
2 .Light Ends analysis.
3. Properties of straight run Naphthas (IBP-190 Deg C).
4. Hydrocarbon component analysis (IBP-150 Deg C cut).
5. Hydrocarbon type analysis (100 - 160 Deg C cut)
 Properties of: Kerosene & Jet fuels
 Middle distillates
 Gas oils
 Lube distillates
 Residue
 Asphalts
6. TBP distillation curve with API and Sulphur
1. TBP curve
9

10. Mid percent curves:
 Gasoline : Octane no., sulphur %, RVP
 Naphtha : Octane no., API, sulphur %.
 Kerosene : Smoke point, freeze point,
API, Aniline point, sulphur%
 Middle distillates/gas oils
: Cloud, Pour, cetane number
Refractive Index, CCR,
Sulphur %, nitrogen, Viscosity
 Residue : °API, Sulphur, Pour,
Viscosity
 Asphalt : Softening point, Penetration
Distinguishing features of crude oil:
Crude Oils are defined in terms of API(American Petroleum Institute) gravity.
A high API implies lighter cruse, characteristic of the C-n fraction (low n).
Crude oils with low carbon, high hydrogen anf a high API gravity are usually
rich in paraffins and tend to yield greater proportions of gasoline and light
petroleum products.
The other class of crude oil, with high carbon, low hydrogen and low API
gravities are rich in aromatics.
A Crude oil/oil feed with an appreciable amount of hydrogen sulfide or
reactive sulfur compounds is termed as a “sour feed” and that with less sulfur
content is called “sweet” or to be precise,
o Sweet-Sulfur<0.5%
o Sour- Sulfur~0.5-2%
o Tough-Sulfur>2%
Exceptions to the above rule:
Arabian High Sulphur crudes are despite a high sulfur content , not
considered sour, as the sulfur compounds are very reactive.
West Texas Crude are considered sour regardless of the H2S/sulfur content.
Types of crude:
 Marlim Light
 Cossack Blend
 Ras Gharib
 Deodorized Field Condensate
 Arab Extra Lt
10

11. REFINERY PLANT OVERVIEW
A refinery comprises of the following segments:
OSBL Outside Battery Limits
o Utilities
o Off sites
o ETP
o Interconnecting Lines
o Other facilities
COT Crude Oil Tankage
ISBL Inside Battery Limits
o Includes all Process units.
Refining Processes carried out, can be classified into two main types, namely:
Primary Processes
Secondary Processes
Primary Processes:
 Crude Distillation
Primary unit to separate different boiling point fractions such as LPG,
Naphtha, Kerosene, HSD, RCO etc.
Distillation conducted at slightly higher than atmospheric pressure.
Unit design for specific crude with flexibility to process a few other
crudes.
 Vacuum Distillation
Sub atmospheric distillation of atmospheric column bottoms for
production of fuels or lube stocks.
Fuels production: Metal content, CCR, Final boiling point etc. critical.
Lubes Production : More stringent fractionation requirements
Secondary Processes:
Further conversion of Vacuum Gas oils and residue required to maximize
production of more useful products
Such processes are called secondary or bottoms upgradation processes
11

12. Major classifications:
Catalytic hydro processes (hydro cracking)
Catalytic Cracking (FCC)
Thermal processes (Visbreaking, Coking)
Others (Partial Oxidation, Solvent de-asphalting etc)
 Hydro cracking
Catalytic cracking of vacuum gas oils in presence of hydrogen
High pressure and temperature
Can produce Fuels/Lubes
No further treatment required for Fuel products
 Catalytic cracking(Fcc)
Catalytic cracking of vacuum gas oils or residues at high temperature
Fluidized catalytic bed with continuous regeneration of catalyst
Cracked products contain unsaturates and hence need further
treatment
 Visbreaking (Thermal)
Thermal cracking of vacuum residue at high temperature
Provide residence time in coil (coil type) or outside in separate vessel
(soaker type)
Gas oil, naphtha are products.
 Delayed Coking
Coking occurs in the Reactor Drum
Coke removed by water jetting
Coke Drum operation in batches
Naphtha, gasoil are other products
 Solvent de-asphalting
Extraction of useful oil from Vacuum residue
Propane - Butane mixture used as solvent
12

13. Useful oil can be cracked further in FCC or Hydrocracker or can be
converted into Bright Stock (Lubes)
Asphalt byproduct can be converted into Bitumen
 Partial Oxidation
Partial oxidation of vacuum residue or asphalt
Produces Synthesis Gas or Hydrogen
Synthesis gas can be converted into power
Hydrogen consumed in refinery
Miscellaneous Processes:
 Catalytic reforming unit
Increases octane number of gasoline
Produces hydrogen
Semi regenerative (regeneration during shut downs) or
Continuous type
 Treating Units
MERICHEM / MEROX-Removes H2S, Mercaptans from LPG,
Gasoline, and Kerosene/ATF.
DESULPHURISATION-
 Catalytic Desulphurization of Naphtha, Diesel.
 Also improves Cetane number of Diesel.
 Lube Processing Units
Aromatics Extraction
De waxing
Hydro treating
Catalytic Processes
 Processes To Meet Environmental Regulations
Sulphur Recovery
Water Treatment
Flue Gas Desulphurization
13

14. Auxillary Operations and facilities Includes:
Steam And Power Generation
Flares and relief systems
Process and fire water systems
Furnaces and heaters, pumps and valves
Supply of steam,air,nitrogen and other plant gases
Alarms and sensors; noise and pollution control
Sampling, testing and inspecting;laboratory,control room, maintenance and
administrative facilities
The various units at Essar Oils_Vadinar for the production of petroleum are:
 CDU-Crude Distillation unit
 VDU-Vacuum distillation Unit
 FCCU-Fluid Catalytic Cracking Unit
 UGS-Gas Concentration Unit
 VBU-Vis Breaker Unit
 NHT-Naphtha Hydro Treater.
 CCR-Continuous Catalytic Reformer
 DHDS-Diesel Hydro Desulphurization
 SRU-Sulphur Recovery Unit
 PIT-Process Intermediate Tank
 COT-Crude Oil Tank
14

15. FG
LPG
SGU
OVHD NAPHTHA
NAPHTHA
NHT
OFFGAS
CCR MS
HY. NAPHTHA
H2
L KERO KEROSENE/
CRUDE ATF
CDU
H2S
SRU SULPHUR
FG
LPG
ATM. RESIDUE
GASOLINE
LVGO
LCO
HVGO FCC
VDU HHVGO UGS SLURRY OIL
DHDS
HSD
VBGO
VAC. RESIDUE
VBU
FO
2. Plant block diagram
15

16. SAFETY
Some of the common hazards that workers, visitors and the process in itself are
prone to in the refinery are cited below:
Physical Hazards:
• High Pressure/Temperature Steam
• Oil/Gas-Fired Furnaces
• Acoustic
• High Voltage (4160V, 480V, 13.2 kV)
• Falling Hazards
• Confined Space Hazards
• Cranes/Lifting Hazards
• Hot Work Hazards
• Acid Exposure
• Toxic Vapors
• Radiation
• Flammability Hazards
Process Hazards:
• Emergency Flare
• Atmospheric Pressure Relief
• High Temperature (up to 2000oF)
• Low Temperature (e.g., Brittle Fracture)
• High Pressure (up to 3000 psig)
• Low Pressure (e.g., vacuum)
Safety Practices: It is a compulsory practice that during plant visit, the trainee be
wearing safety shoes, safety helmet, a pair of gloves, full sleeved cotton outfit, ear
plugs to avoid being affected by the afore mentioned hazards.
16

17. CRACKING PROCESS
Cracking is a phenomena by which large oil molecules are decomposed into smaller
boiling molecules.
Types Of Cracking:
 Thermal Cracking:
Dissociation of high molecular weight hydrocarbons in to smaller fragments through
heat agency alone is termed as Thermal Cracking or Pyrolysis.
 Catalytic cracking:
Cracking can also be carried out in the presence of a catalyst, known as Catalytic
cracking.
 In thermal cracking, the product selectivity is low and lighter component
production (<C3) will be high.
 In catalytic cracking, high yield is obtained,more stable products are formed,
its less severe, there is lesser gas production and High Octane gasoline is
produced.
 Now catalytic cracking has almost superseded thermal cracking because of its
inherent advantage of low temperature and pressure operation.
 Also the catalytic cracking is rapid, being 1000 times as faster than thermal
cracking in the case of naphthenes at 500 oC.
Thermal Cracking Operations:
o
Temperature of cracking ( C) Nature Of Operation Products
425-460 Visbreaking Fuel Oil
460-520 Thermal Cracking Gas,Gasoline,Tar oils,
Circulating oils
520-600 Low temperature coking Gas,Gasoline,Soft coke
600-800 Gas Production Gas and Unsaturates
800-1000 High Temperature coking Gas, Heavy aromatics,
Pitch or Coke
Above 1000 Decomposition H2 gas, Carbon black
17

18. CHEMISTRY OF THE FLUID CATALYTIC
CRACKING PROCESS:
The theory of catalytic cracking is based on Carbonium ion formation and
subsequent H2 transfer reaction. From the basic organic chemistry it could be
envisaged that whenever a molecule breaks into two, two bonds become free. In
absence of free hydrogen atoms in the vicinity, one of the new born molecules has to
develop a double bond. Alternately, coke is generated in the cracking reaction to
maintain Hydrogen balance. To control this coke formation or formation of very small
molecules, the industrial cracking of heavy petroleum molecules are aided by
catalysts.
Step I Formation of carbonium ion from the feed stock.
Carbonium ion is readily formed from the olefins which take place on the acid site of
Catalyst.Once the carbonium ion is formed by the catalyst it may proceed further as
follows:
• Crack to form small olefin plus another carbonium ion
• React with another olefin to form a different carbonium ion
• Isomerise carbonium ion to a different form
• Stopping the chain reaction by donating the proton back.
Step II Hydrogen transfer reaction
Hydrogen transfer reaction converts an olefin to paraffin. The source of the hydrogen
is
another olefinic hydrocarbon on the catalyst which will progressively become more
hydrogen deficient. This hydrogen deficient molecule will get adsorbed very strongly
to
the catalyst & form the coke on the catalyst during reaction
Reactions:
18

19. (Chain breaking step)
Reactions a, b, c are indefinite
Dealkylation of the aromatics occur in the similar manner
Overall Reaction flow diagram
19

20. FCC CATALYST
FCC catalyst history:
Brief:The concept of FCC was developed during 1940’s with powdered fluidized
catalyst.A significant change came about when Y type Zeolites were being used
instead of the high alumina amorphous catalyst, which was used in 1950’s.The
reactor configuration was changed because of the high active and lower coke
forming tendency of Zeolite catalysts.In the mid 1960’s USY based catalysts were
introduced of high hydro thermal stability produce less coke and also increase the
octane number of the gasoline.During 1980’s large number of additives such as
nickel and vanadium passivators, CO combustion promoters and SO X emission
controllers and special additives for attrition resistance, octane improvement were
developed, to optimize the reaction.
Timeline:
Natural Clay Till 1930’S
Synthetic amorphous silica-alumina catalyst till 1960’S. Introduced in
1946,first
synthetic catalyst, 12%alumina- 88%silica was more active and caused less
erosion than clay catalyst.
Zeolite Catalyst Introduced in 1964,crystalline alumina silica with regular
cavities, X -zeolite Si/Al ratio = 1to1.3 Y - zeolite Si/Al ratio = 2to2.6 most
active of all catalyst, Good conversion and low recycle of heavy oil from MF,
high activity led to short contact time and all riser cracking concept.
Cat Additives like Ni passivator.
Fluidized catalyst_definiton:
 Fluid catalytic cracking catalyst is a fine porous powder composed of oxides
of silicones and aluminum. Other elements like sodium, calcium, magnesium
and members of rare earth family such as lanthanide and cerium are present
in very small amount.
 The source of the catalytic activity is on the acid site which is either Bronsted
or Lewis acid sites. The acid sites initiate and accelerate carbonium reaction
that causes molecular size reduction at FCCU reactor conditions.
 When aerated with gas, the powder attains a fluid like property that allows it to
behave like a liquid. This property permits the catalyst to be circulated
between Reactor and Regenerator, hence the name fluid cracking catalyst.
Cracking catalyst: There are three types of catalysts primarily:
 Acid treated natural alumino silicates.
 Amorphous synthetic silica-alumino combinations.
 Crystalline synthetic silica-alumina catalysts called zeolites.
20

21. Zeolite catalyst:
Zeolites are molecular sieves that are incorporated into the catla;yst. The chemical
composition basically the same as the earlier type of catalyst, but the structure is
radically different. The main components are Zeolite, Clay,Matrix (Silica or Alumina
gel) and binder. A Zeolite is a crystalline alumina-silicacompound with a frame work
structure. This regular structure differentiates the Zeolite from the previous catalysts,
which were amorphous having sponge- like structure. The Zeolite has regular
cavities which can be occupied by large ions or water. These ions may be
exchanged for others as long as electrical neutrality is maintained.
Advantages:
The first commercial catalyst was made with 8 - 10 % zeolites and showed an
activity 1.5 -2 times the amorphous catalyst. This higher activity proved to be an
advantage for gasoline oriented operations but for middle distillate operations, the
amorphous type catalyst is still used. To utilize this higher activity, then came the
concept of short contact time in the riser. This short contact time minimizes
undesirable over cracking, while good conversion was maintained because of high
catalyst activity. Because of this the recycle quantity of the heavy oil from MF has got
reduced. This in-turn has allowed to increase the fresh feed rate.
Comparison of Amorphous and Zeolite catalyst:
Property Amorphous Zeolite
Coke wt5 4 4
Conversion vol% 55 65
C-5 gasoline, vol% 1.38 51
C3-gas,wt% 7 6
C4,vol% 17 16
Catalyst for the processing of resids in specially designed FCCU has to be designed
with a range of pore size distribution to handle the large molecules(>30A o) present
and also smaller pores to give higher activities.Large liquid catching pores (>100Ao)
with large activity to control coke and gas make
Meso pores(30-100 Ao)
Small pores(_20 Ao)
21

22. Ultra Stable Y catalyst:
The catalyst used is of low active rare earth stabilized ultra stable Y catalyst
(USReHY).
• The presence of rare earth will increase the hydro thermal stability and increase H2
transfer activity.
• Gasoline RON & MON reduces with increase in unit cell size.
• Activity of Unit cell increases with Unit cell size but selectivity of C3 will reduce.
Research Octane number(RON):
RON & MON:
Octane Number.
A measurement of gasoline quality, the octane number is an indication of the
gasoline
tendency to pre ignite or “pring” under compression. The reported octane no. is
actually
the percentage of isooctane in isooctane/normal heptanes blend that has the same
tendency to ping as the gasoline tested .the tests are conducted in special engine.
The Octane Number of iso-octane equals to 100 and of the n-Heptane equals to zero
by definition.
RON:– The Research Octane Number of octane number determination correlates
with full-scale spark-ignited engine antiknock performance at low speed -600 RPM.
The test method utilizes a single cylinder, four stroke and adjustable cylinder height
engine and requires critical adjustment of fuel / air ratio and compression ratio to
produce a standard knock intensity condition. RON correlates the commercial
automotive spare ignition engine antiknock performance under mild condition of the
operation
MON: The Motor Octane Number correlates with full scale spark ignited engine
antiknock performance at higher speed – 900 RPM with mixture heater temperature
and variable spark angle. It provides a means of defining the quality of motor
gasoline for use in vehicles on the road. MON correlates the commercial automotive
spare ignition engine antiknock performance under severe condition of the operation.
The difference in the methods is as follows:
Property Research Motor
Rpm 600 900
Spark advance 13 o btdc Variable
Mixture heating No Yes
22

23. Catalyst-Physical Properties:
Property Characteristic
Appearance White powder and free flowing
Main Component Silica/Alumina
Quartz content Below detection
Bulk Density 700-800 g/l
Flash Point Not flammable
Solubility Insoluble
Respirability 0.1-0.2 wt%
Problem Dust formation and water absorption
Catalyst features:
• Binder is the material used in the FCC catalyst to bind the matrix and zeolite
components into a single homogeneous particle.
• Matrix is a substitute in which the zeolite is imbedded in the cracking catalyst used
as a term for active, non-zeolitic component of the FCC catalyst
• Zeolite is a synthetic Alumina-Silicate material used in the manufacturing of FCC
catalyst.
• Hydrogen transfer is the secondary reaction that converts olefins (predominantly
iso-olefins)
into paraffin’s while extracting hydrogen from larger molecules.
23

24. The presence of Zeolite in the catalyst will
1. Increase conversion
2. Increase delta coke formation
3. Reduce the gasoline selectivity and increase LPG selectivity
4. Increase RON, MON of gasoline
The presence of Rare earth in the catalyst will
1. Increase conversion
2. Increase delta coke formation
3. Increase the gasoline selectivity
4. Decrease RON and increase / decrease MON of gasoline
The presence of Matrix activity in the catalyst will
1. Increase / Decrease conversion
2. Increase delta coke formation
3. Increase the gasoline selectivity
4. Increase RON and MON of gasoline
Important charecteristics of Catalyst
 Activity
Activity is the conversion produced by a catalyst when tested on a specified feed at
specified conditions. This is normally done in a bench scale test unit.
 Conversion
Conversion = Gas + LPG + Gasoline + Coke in vol % or wt %.
 Selectivity
H - Factor: Measure of metal activity for the H2 transfer.
Coke factor: Measure of E-cat contribution to the delta coke including metal activity
24

25.  Surface Area
It is a measure of catalyst activity when comparing with the same type of catalyst.
It is determined by N2 adsorption, assuming a complete mono-molecular layer of
Nitrogen on the surface.
Density of FCC catalyst:
Skeletal Density (SD) = 2.1 * SiO2 + 3.4 * Al2O3 /100
Particle Density (PD): 1/PD = 1/SD + PV
PV = Pore Volume: The volume of pores or voids in the catalyst particles
(Mainly used for cyclone design purpose)
Compacted Bulk density (CBD): a / CBD = 1/SD + PV, where a = Packing factor
(For dense packing)
Apparent Bulk Density (ABD) -Density of a catalyst sample that has been allowed
to settle undisturbed.
: b/ABD = 1/SD + PV b = Packing factor
(For Hopper inventory)
APS (Average particle size).-The weight average particle size of a catalyst sample.
In many cases however the reported average particle size is in fact the medium
particle diameter.
NOTE: SD > PD > CBD > ABD.
Effect/Increase Conversion Activity Coke Make up at Losses
Of formation constant
conversion
Nickel Decreases -- Increases Increases --
Sodium + Decreases Decreases Increases Increases --
Vanadium
Attrition index Increases Increases -- Increases Increases
ABD -- -- -- -- Decreases
APS Decreases Decreases -- Increases Decreases
25

26. Fluidized Catalytic Cracking (FCC) Unit:
3. Fcc_unit
Introduction to FCC:
Objective:
 To upgrade Gas oil of the refinery
 To maximize LPG yield
Process Technologists:
 Process licensor/design of FCC and UGS units carried out by M/s-Stone
&Webster (Mauritius) Limited.
 Process detailed Engineering by M/s.ABB Lummus Crest (Mauritius`) limited.
Process used at Essar:
 Stone & WEBSTER process for Fluidized Catalytic cracking
Other processes used for FCC:
 Universal Oil product (UOP) process
26

27. Advantages of FCC:
The high octane number which has become an important factor for gasoline quality
can only be achieved by FCC. Though investment cost of FCC unit is high, the
increased yield of high quality products from FCC unit justifies for the installation of
FCC unit.
Selection of the process:
The process used at ESSAR, Jamnagar is provided by SWEML(Stone & WEBSTER
Engineering(Mauritius) Limited) as:
It incorporates a 2-staged regenerator system; a unique fed injection system and a
proprietary catalyst disengager.
Advantages of the 2-staged FCCU regenerator:
 Earlier in FCC, it was only a single stage catalyst regeneration system and
later this has been changed to two stage regeneration system for reducing the
catalyst deactivation rate and effective catalyst regeneration.
 In single stage regenerators catalyst will get deactivated very fast due to
higher regenerator temperatures and presence of water vapour.
 In two stage regeneration system approximately 60 - 70 % of the coke is burnt
at mild conditions in the first stage regenerator and the second stage
regenerator completes the coke removal in an oxygen rich, higher
temperature environment.
 Most of the hydrogen-in-coke is removed in the first stage itself at mild (low
temperature) conditions.
 Also the single stage regenerator is limited in regard to cracking residues
because of metallurgical limits within the regenerator vessel.
FCC unit can be subdivided into :
FCCU-Fluid Catalytic Cracking Unit
UGSU-Unsaturated Gas Separation Unit
FDS-Flue Gas Desulphurization Unit.
Objective of the FCC units:
FCCU (unit No.3400): It has a main objective of maximizing LPG production by
catalytically cracking the feed mixture of vacuum gas oils from the Vacuum and
Visbreaker units.
UGSU (Unit No.3500): The UGS unit has an objective of separating the distillate
and LPG from the overhead outlet of FCC.The ultimatum is to maximize the recovery
of C3’s and C4’s from the unsaturated gas (Minimum 95%).
FGD-Flue Gas Desulphurization(Unit No.4500): The FGD unit has an objective of
removing sulphur and catalyst fine dust particles from the flue gas outlets of the
FCCU regenerator section through the usage of caustic alkali solution.
27

28.  Sulphur removal: A spray tower column is used for the absorption of SO2
into a scrubbing liquid via intensive liquid/gas contacting. The purge liquid of
the spray tower unit is sent to A Purge treatment Unit (PTU) to be treated
before its release to the environment. The spray tower also removes the main
catalyst dust particles. The fine particles are however removed using filtering
modules.
 Purge Treatment Unit(PTU): The purge liquor is treated to neutralize the PH,
remove suspended particles (catalyst) and reduce the Chemical Oxygen
Demand (COD).
Fluid Catalytic Cracking Unit has the following
systems:
 Main Air blower (MAB) system
 Reactor/regenerator system
 Regenerator air heaters and Feed heater System
 Flue Gas Handling and energy recovery system
 Catalyst handling system
 Main fractionators System
 Wet Gas compressor System.
 Stripper/Absorber system
 Debutanizer system
 Gasoline splitter System.
 LPG liquid contactor system
 Absorber gas Contactor system
28

29. Capacity and Feed Stock:
The FCC unit is designed for processing 2.93 MMTPA of feed obtained from
processing of 70/30 Arab light/Arab heavy crude oil mix in 8000 hours of operation .
FCC and UGS sections are designed for a turn down of 50% of design case1.
Unit Capacity:
Present operating case is Phase 1 Case 3:
S.No Case
3 1 2
1 Processing 13.68 WT% 14.05 %C3/ C4 14.02% C3/ C4
Objective C3/ C4 LPG LPG LPG
2 Phase Phase 1 Phase 2 Phase 3
3 Capacity 2.93 MMTPA Maximum Maximum
attainable attainable with
without case 1
changing
4 Crude Source 70/30 Arab 50/50 Arab 50/50 Arab
light/Arab light/Arab Light/Arab
Heavy Heavy Heavy
5 CCR in feed 1.3 WT% 1.1 WT% 4 WT% CCR
stock CCR CCR
Table.1
Characteristic Properties:
 API Gravity.
An expanded density scale based on specific gravity. API gravity is expressed in API
and is calculated by the following formula:
API= (141.5/specific Gravity)-131.5.
 Conradson Carbon (Concarbon):The residue left behind following pyrolisis of the oil
sample under specified testing condition. This measurement is used to estimate the
fraction of FCC feed that cannot be vaporized.
 Flash Point: is the lowest temperature at which application of the test flame
causes the vapour above the sample to ignite. Important in terms of storage
and handling.
29

30.  Pour Point:It is the lowest temperature expressed in multiples of 3oC at which
the oil ceases to flow when cooled and examined under prescribed condition.
 TBP cut:It is the true boiling point cut temperature of a fluid.

Reid Vapour Pressure:It is an indication of volatility and significant for
materials whose boiling points are low, that they cannot be distilled at
atmospheric conditions without serious losses.The test is important with
respect to safety in transport,vapour lock in gasoline feed systems,types of
storage tank and starting characteristics of motor fuels.RVP is recorded in
terms of KPa or Kg/cm2.
Feed stock properties:
 The feed is Crude Source Arab Light/Arab Heavy(70/30) ratio.
Component LVGO HVGO HHVGO VGO(VBU) Composite
Feed
TBP cut (oC) 380-425 425-565 565-580 350-490 ---
Specific Gravity 0.9074 0.9377 0.9866 0.9368 0.932
API Gravity 24.44 19.4 11.92 19.55 20.32
Watson k factor 11.81 11.90 11.82 11.44 11.84
Sulphur % 2.48 2.94 3.03 4.33 2.92
Nitrogen ppm wt 400 1100 1500 1500 968
Nickel ppm wt 0 0.5 13.0 5.0 1.3
Vanadium ppm wt 0 1.4 32 15 3.5
Conradson 0.1 1.2 7.0 2.0 1.3
carbon wt %
Viscosity 50 oC 17 71 348 45 50
cst
Flow Rate MT/SD 2265 5480 443 610 8798
Table.2
30

31. Feed for unit:
S.No Feed % of Total Flow Rate
Component
Case 3 Case 3 Case 3
Phase 1 Phase 1 Phase 1
1 LVGO(VDU) 25.75 25.24 17.05
2 HVGO(VDU) 62.29 61.87 43.06
3 HHVGO(VDU) 5.03 ---- ----
4 VGO(VBU) 6.93 5.26 4.28
5 DAO(VBU) ---- 7.63 35.61
6 Total Feed 100 100 100
Table.3
31

32. Yield Pattern and Product Routing:
Feed Stock: 25.75% LVGO, 62.29 % HVGO, 5.03 % HHVGO and 6.93 % VVGO
mixture from 70 / 30 AL / AH crude mix
Product Yield
Wt% Vol% API
H2s 1.46
Off-gas 3.49
Cracked LPG 13.68 22.63
Gasoline(C5-125oc) 23.08 30.61 69.9
TCO(125oc-380oc) 42.17 44.03 27
Decant 10/74 9.22 -1.2
Oil(380oc+TBP)
Coke 5.38
125oc TBP 47.09 46.75
conversion
Table.4
Product routing:
Description Routed to
Unsaturated LPG UMU
Light Gasoline GMU/NHT
Medium gasoline GMU/NHT
Heavy Gasoline DHDS
LCO DHDS
Slurry oil DCU
Off-gas FG Header
Table.5
32

33. Product characteristics:
Following are the products obtained from FCC & UGS:
1. Unsaturated LPG
2. Cracked Gasoline ( Light + Medium ), Heavy Gasoline
3. Light Cycle Oil
4. Slurry Oil
5. Coke
6. Off Gas
Total cycle oil (TCO) is a mixture of Heavy Gasoline & Light Cycle Oil
Unsaturated LPG
Vapour pressure @ 65 oC 16.87 kg/cm2g
H2S content wt ppm 15(max)
Evaporation temperature for 95 vol % at 2 oC (max)
760 mm Hg.
Table.6
Total Gasoline (Light + Medium) and also for heavy gasoline
TBP cut point,(oC) C5 -- 125
C4 content wt % 0.5(max)
API gravity 70
Sulphur wt % 0.15
RONC 92.0 min
Reid Vapour Pressure kg/cm2g 0.7 max
Table.7
Light Cycle Oil
TBP cut point,(oC) 183-380
API gravity 25.6
Sulphur wt % 1.44
Cetane index 28.7
Flash point (Abel) oC 60 (min)
Table.8
33

34. Total Cycle Oil (Heavy Gasoline + Light Cycle oil)
TBP cut point,(oC) 125-380
ASTM d86 90% 360(max)
Gasoline/TCO 5-95%GAP oC 0 min
Pour point, oC 6 (max)
Water content, vol % 0.005%
Flash point (Abel) oC 38 (min)
Table.9
Slurry Oil
TBP cut point,(oC) 380+
LCO/slurry 5-95% overlap, oC 10 max
Sulphur wt % 4.29
BSW wt % 0.05(max)
Flash point, oC 66(min)
Table.10
Coke
Sulphur wt % 4.96
H2 wt % 7
Table.11
Off-gas
H2S volume ppm 100 (max)
Table.12
34

35. Process Description
The FCCU consists of the following sections:
Fresh Feed System
Convertor Section
Flue Gas Energy Recovery
Main Fractionation Section
Fresh Feed System
Three hot feed streams (LVGO, HVGO and HHVGO) from VDU, one hot stream VVGO
from VBU and one cold feed from storage are brought in from battery limits and fed
to the Feed Surge Drum. The combined hot feed and the cold feed are controlled by
the Feed Surge Drum level controller. Hot feed level controls are located in the
Vacuum Unit while cold feed flow control is located in the UGSS. A water boot on the
drum allows for draining of any water which may accumulate during start-up or
upset conditions. The feed drum pressure is maintained by fuel gas through a
pressure controller. A vent line is provided to release drum vapor to the flare in case
of high pressure.
Fresh feed is pumped on flow control from the Feed Surge Drum to the feed preheat
exchangers to recover heat from the process. The fresh feed is heated against heavy
gasoline, LCO pump around, LCO product, and slurry pump around. A feed heater is
provided for further heating the feed to the required temperature. Since the
operation uses a feed heater, the temperature control remains at the Slurry/Feed
Exchangers. Some shells of the Slurry/Feed Exchangers may have to be bypassed
during this special operation.
Oil feed to the riser is preheated to 279.4 deg C before entering the reaction system.
This preheat temperature along with regenerated catalyst temperature is controlled
to result in the required catalyst to oil ratio. Injection of a metal passivator through
package into the fresh feed just before the feed injectors inhibits the undesirable
effects of nickel present in the feed. Nickel will deposit on the cracking catalyst and
acts as dehydrogenating catalyst. Metal passivation is to be considered when the
nickel content of the equilibrium catalyst is greater than 1000 ppm. Pressure on each
feed injector should be monitored as a verification of flow and an indication of
35

36. nozzle condition. Dispersion steam is supplied to each fresh feed injector to promote
fresh feed atomization and vaporization. The total dispersion steam is flow
controlled with flow to each injector adjusted by hand controlled globe valves.
Steam flow is required in the idle injectors to keep them clear.
1300 ID Lining
1500 ID Shell Slurry Back flush
(1 Nozzle)
Reactor Riser (34V-101) EL. 20100
Legends:
P = Purging with Steam TI
N = Purging with Nitrogen
S = Sample point Slurry Recycle
(2 Nozzles)
All Dimensions are in mm EL. 13500
1150 ID Lining
1400 ID Shell
TI
Fresh Feed
(6 Nozzles)
EL. 7850
P
45o
P EL. 6250
S
P Gasoline Recycle
(1 Nozzles)
Sh g
Stab. Steam
n
l
ni
el
P
Li
(3 Nozzles)
ID
ID
5
TI
87
25
950 ID Lining
11
1200 ID Shell EL. 2900
N
36

37. Convertor Section
The converter section of the S&W Fluid Catalytic Cracking Unit (FCCU) described
herein consists of the following major equipment:
Riser Reactor & Catalyst Stripper
First Stage Regenerator
Second Stage Regenerator
Air Blower
The function of the unit is catalytic cracking of mixtures of vacuum tower gas oils,
vacuum tower bottoms, hydrocracker bottoms and visbreaker gas oils. These
feedstocks crack into lower boiling, high value products, primarily light cycle oil, C3-
C4 LPG, and gasoline. The unit also produces fuel gas and slurry oil.
FCCU Process Flow and Operation
The FCCU utilizes a riser/reactor, catalyst stripper, a first stage regeneration vessel, a
second stage regeneration vessel, a catalyst withdrawal well, and catalyst transfer
lines.
Riser/ Reactor System
The riser is designed to rapidly and intimately mix the hot regenerated catalyst with
liquid feedstocks. Fine atomization of the fresh feed is accomplished by six S&W oil
injectors utilizing medium pressure steam for dispersion. Two additional S&W oil
injectors are installed further up the riser to allow the unit to recycle oil as necessary
to maximize distillate product. In addition to these oil injectors, steam injectors are
provided at various locations along the riser to ensure a stable and homogeneous
catalyst circulation.
The reactor design begins at the base of the riser or the reverse seal section. The
bottom wye section causes turbulence and potentially uneven catalyst flow patterns.
Therefore, a high density zone is provided to absorb shocks and stabilize the catalyst
flow. For proper travel of the catalysts, eight (8) fluidization steam nozzles are
provided at 3 different locations of the wye section. Three down-flow stabilization
steam injectors promote smooth and homogeneous catalyst flow as the catalyst
moves upward toward the fresh feed injectors. These steam injectors are located
midway between the riser bottom and the fresh feed injectors. Fluidization steam in
the 45 degree wye section and the stabilization steam in the reverse seal section
ensure even catalyst flow as the catalyst reaches the feed injection section. The
minimum steam flow is 50 kg/hr when catalyst is circulating and the design flow is
941 kg/hr. The steam flow should provide a velocity within reverse seal at 1.5 m/sec.
37

38. This straight vertical section below the fresh feed injectors also serves as a reverse
seal providing protection against oil flow reversal.
At the same elevation as the stabilization steam injectors, an injector has been
located to provide for recycling medium gasoline to the riser at the client’s option. In
order to increase the gasoline octane, the medium gasoline fraction may be recycled
intermittently. The Heat and Material Balances do not include this recycle stream.
Fresh feed is finely atomized, mixed with dispersion steam, and injected into the
riser through the S&W patented feed injectors. A total of six fresh feed injectors are
specified in this design. The Design oil flow rate per feed injector is 61097 kg/hr and
dispersion steam flow rate per injector is 2138 kg/hr. The small droplets of feed
contact the freshly regenerated hot catalyst and instantaneously vaporize. The oil
molecules intimately mix with the catalyst particles and crack to lighter more
valuable products: LPG, distillate, and gasoline. Additional byproducts produced
from the FCCU are slurry oil, fuel gas, and coke. Since the cracking reaction involves
the breaking of large molecule into smaller molecules, there is a molar expansion
and thus an increase in the volume of gas over the riser length. In order to maintain
the design velocity across the riser length, diameter needs to be increased. Here we
have 1.15 m at the bottom and 1.3 m at the riser top excluding the refractory lining.
The outlet velocity of the vapor-catalysts mixture is 21 m/sec. The specially designed
feed injection system ensures maximum conversion of the oil to lighter products
while minimizing delta coke on the catalyst below a maximum of 1.2 wt%.
Commercial cracking reactions appear to be second order thus most of the reaction
takes place in the lower section of the riser. A generally used rule of thumb is the
one-third / two thirds rule. This states that two-thirds of the conversion will take
place in the first one-third of the riser volume. The regenerated catalyst slide valve
controls the riser outlet temperature by regulating the amount of hot regenerated
catalyst entering the riser. Riser residence time for the design case is approximately
1.6 seconds.
Injection of a metal passivator into the fresh feed reduces hydrogen production and
improves yields of the valuable products when processing vacuum tower bottoms.
Nickel, typically present in residual feedstocks, will deposit on the cracking catalyst
and acts as a dehydrogenating catalyst. Metal passivation should be considered
when the nickel content on the equilibrium catalyst is greater than 1000 ppmw.
Optionally, catalyst with built-in nickel traps should be considered as another
method of controlling feed metals.
The recycle oil injection nozzles are located approximately 5.6 meters above the
fresh feed injectors. These S&W patented recycle oil injectors are designed to
maximize distillate production. Two recycle oil injectors are required in this design.
Also, another injector located 1.6 meters below the feed injectors is provided for
38

39. recycling medium gasoline. As this project basis focuses on LPG production, the
recycle injectors will normally not be in use.
Placed further up along the riser approximately 12.2 meters above the fresh feed
injectors is the slurry filtration backwash injector. This injector is designed for
handling an oil/catalyst mixture. This injector serves to return catalyst filtered out of
the slurry product stream.
Inertial Separator
After the reaction mixture travels up the riser, the catalyst, steam, and hydrocarbon
product mixture passes through an inertial separator. This separator or riser
termination device (RTD) quickly disengages the catalyst from the vapor mixture to
minimize over cracking of valuable products. At the top of the riser, the catalyst and
vapor mixture divides into two parallel streams. Each stream begins a circular
rotation around a center tube which is outfitted with a vapor outlet slot. Inertial
effects force the catalyst particles to the cylinder wall where the catalyst exits
downward into the inertial separator’s dipleg. The cracked hydrocarbon and steam
vapor with entrained catalyst leave the separator through the center tube where
ducting directs flow up near the cyclone inlets. The gas outlet ducts are open-ended
and direct the vapor/catalyst mixture upward toward the reactor cyclone inlet
windows. This rapid separation and ducting minimizes the vapor residence time
thereby reducing secondary thermal reactions in the disengaging vessel. The vapors
and entrained catalyst pass through four single stage high efficiency cyclones. The
cyclone diplegs have partially shrouded trickle cheek valves to ensure a positive seal
and terminate in the dilute phase at the same elevation as the RTD diplegs. Reactor
cyclones further separate the product vapors from the entrained catalyst, returning
the catalyst to the stripper. Reactor products, inerts, steam, and a minute amount of
catalyst flows from the reactor overhead into the base of the main fractionator. The
primary concerns in riser operations are:
(1) The choke velocity of the riser
(2) The riser pressure drop
(3) The catalyst hold up in the riser
The minimum velocity below which the catalyst / vapor mixture in the riser will not
remain in dilute phase transport but drops into a dense phase is called the Choke
Velocity.
39

40. Stripper section
The stripper portion of this vessel utilizes five disk and do-nut baffle stages. These
baffles are angled downward at 45 degrees. Two steam rings are present in the stripper:
Main steam ring and Fluffing steam ring. The main steam ring fluidizes the catalyst bed,
displaces the entrained hydrocarbons, and strips the adsorbed hydrocarbons from
the catalyst before it enters the regeneration system. The steam fluffing ring, located
in the bottom head of the stripper, keeps the catalyst properly fluidized and ensures
smooth catalyst flow into the spent catalyst transfer line.
Total stripping steam requirement: For gas oil, 3 kg/Ton of catalysts circulation and for
residue 5 kg/Ton of catalysts. The design flow of steam through this ring is 7800 kg/hr with
50 % turndown. 55 nozzles are provided in the ring. The nozzle ID is 21 mm and the RO ID is
13 mm. The ring radius is 1.49 m.
Stripper
Baffles
Reactor Riser
3550 ID Lining
3750 ID Steel
Main Steam Ring
EL. 26670
Spent Catalyst
Stand Pipe
EL. 23850
Fluffing Steam Ring
40

41. Spent Catalyst Transfer
Stripped catalyst leaves the stripper through the 45 degree slanted withdrawal
nozzle and then enters a vertical standpipe. The spent catalyst flows down through
this standpipe and into a second 45 degree lateral section that extends into the first
stage regenerator. The spent catalyst slide valve is located near the bottom of the
vertical section of the standpipe and controls the catalyst bed level in the stripper.
Allowable pressure drop for the spent catalyst slide valve (SCSV) is 0.38 kg/cm2.
Catalyst flow rate through SCSV is 509 kg/sec and catalysts density is 670 kg/m3. The
max port opening area is 145 mm2. Careful aeration of the catalyst standpipe
ensures proper head buildup and smooth catalyst flow. The flow rates from the
aeration taps are adjustable to maintain a stable standpipe density for different
catalyst circulation rates or different catalyst types. The catalyst, containing roughly
1.0 -1.5 wt % coke, enters the first stage regenerator through a catalyst distributor
which disperses the catalyst onto the bed surface.
Reactor Details:
Riser Length (m) 38.9
Riser Operating Conditions Wye Section Riser Line
Temperature (NOR/MAX), oC 707/735 491/519
Pressure (NOR/MAX), kg/cm2 g 2.63/4.04 2.63/4.04
Riser Design Conditions Wye Section Riser Line
Temperature (Metal/Int.), oC 343/816 343/566
Pressure, kg/cm2 g 6.8 6.8
Reactor / Cyclone MOC CS (SA516 Gr. 70)
Reactor Diameter (Steel/Lining), m 6.6 / 6.4
Reactor Length, m 2.50
Reactor Operating Conditions
Temperature (NOR/MAX), oC 491/519
Pressure (NOR/MAX), kg/cm2 g 2.10/3.52
Reactor Design Conditions
Temperature (Metal/Int.), oC 343/566
Pressure, kg/cm2 g 5
41

42. First Stage Regenerator
The operational severity of the first stage regeneration is intentionally mild due to
the partial combustion operational mode. Essentially all the hydrogen on the coke is
burned off the coke in the low temperature first stage regenerator. This mild
temperature along with partial combustion minimizes hydrothermal deactivation of
the catalyst and controls the conversion of CO to CO2. As a result, catalyst surface
area and activity levels are maintained higher than single stage regeneration units.
Approximately 66 percent of the coke is burned off the catalyst in the first stage
regenerator. Typical residual operations require burning of 60 to 70 percent of the
coke in the first stage regenerator. This ability to vary the coke burn split between
regenerators provides the FCCU with operating flexibility for different feedstocks.
First stage regenerator temperature is limited up to 678 oC.
The reactions, which take place in the regenerator, are:
C + 1/2O2 CO H = + 2200 Kcal/kg oC
CO + 1/2O2 CO2 H = + 5600 Kcal/kg oC
C + O2 CO2 H = + 7820 Kcal/kg oC
H2 + 1/2O2 H2O H = + 28900 Kcal/kg oC
S + xO SOX H = + 2209 Kcal/kg oC
N + xO NOX
C + CO2 2CO
42

43. The diameter of the first stage regenerator vessel is carefully determined on the
basis of superficial gas velocity. Coke on the catalyst is burned in the regenerator’s
lower dense phase zone where higher superficial velocity aids catalyst mixing.
However, the vessel superficial velocity is optimized at a low enough value to inhibit
catalyst entrainment to the cyclones in the upper dilute phase.
Combustion air is split between two rings in the first stage regenerator. These rings
provide even air distribution across the catalyst bed resulting in proper fluidization
and combustion. The rings are designed to split the flow approximately 70 percent
and 30 percent to the outer ring and inner ring, respectively. The carbon monoxide
rich flue gases pass through four sets of two-stage cyclones before leaving the
regenerator.
The catalyst level in the 1st stage is controlled by the hollow stemmed plug valve at
the bottom of the lift line. The normal bed level of the catalyst in the 1 st stage is
3600 mm above the tangent line. The max. bed level is 900 mm above the normal
bed level. The minimum bed level maintains a seal of 300 mm on the secondary
cyclone dip leg.
Four set of two stage cyclones are mounted internally to the regenerator to separate
the catalysts from the flue gas. The design gas flow rate through these cyclones is
15714 kg/hr and superficial velocity of 0.65 m/sec. The cyclone inlet pressure is 2.68
kg/cm2 g and temperature is 628 oC. Max. inlet velocity for both cyclones is 20
m/sec. The secondary cyclones are provided with partially shrouded Trickle valve.
Plug Valve
Partially regenerated catalyst flows downward in the first stage regeneration vessel
to the lift line entrance. Careful fluidization with a fluffing air ring in this area allows
the catalyst to pass smoothly into the lift line. The air flows into the lift line through
the hollow stem plug valve. This air pneumatically lifts the catalyst in dilute phase to
the second stage regeneration vessel. The minimum air velocity for acceptable lift is
7.5 m/sec based on lift line operating conditions. The velocity should not exceed 21
m/sec to avoid erosion problems. Combustion air used to raise the catalyst can vary
between 30 and 40 percent of the total air to the second stage regenerator. For the
design case, 30 percent of the combustion air is used. The plug valve controls the
bed level in the first stage regenerator.
Second Stage Regenerator
As the catalyst enters the second stage regeneration vessel, below the combustion
air ring, the mushroom grid distributes the catalyst evenly across the bottom head.
This grid distributor on the top of the lift line ensures uniform distribution of air and
catalyst. In the second stage regenerator, the remaining carbon, less than .05%, on
43

44. the catalyst is completely burned with excess oxygen, resulting in a higher
temperature compared to the first stage regenerator. One air ring in this regenerator
distributes a portion of the combustion air, while the lift air provides the remainder
of the air. With most of the hydrogen burned in the first stage, moisture content of
the second stage regenerator flue gases is minimized. This allows higher
temperatures in the second stage regenerator without causing hydrothermal
catalyst deactivation. Regenerator temperatures are not directly controlled.
Regenerator temperatures are directly dependent on the coke burning process.
The second stage regenerator design includes two zones that have different
superficial gas velocities. Coke remaining on the catalyst is burned in the
regenerator’s lower dense phase zone where the higher superficial velocity aids
catalyst mixing. The larger diameter upper dilute phase zone reduces entrainment to
the cyclones. This vessel has minimum internals which helps eliminate temperature
limitations under any current or possible future operating condition. The catalysts
bed level in the 2nd stage is not directly controlled but depends on the catalyst
inventory. Periodic withdrawals are made from the 2nd stage to maintain the level in
normal operating range. The withdrawal nozzle location is such that it always
ensures minimum level in the regenerator. Max bed level is 1850 mm above the min.
level and set to provide approx. 3 min. residence time for the catalysts.
Flue gas leaving the regenerator passes through three sets of two-stage external,
refractory-lined cyclones for catalyst removal. The cyclone inlet pressure is 1.65
kg/cm2g and temperature is 707 oC. Max. inlet for primary cyclones is 20 m/sec and
for secondary cyclones is 24 m/sec. The secondary cyclones are provided with
partially shrouded Trickle valve.
There are three nos. of torch oil nozzles provided in the regenerator for initializing
the combustion reactions during the start up. The nozzles are designed for an oil
flow rate of 1949 kg/hr each and oil inlet temperature of 140 oC. Dispersion steam of
59 kg/hr/nozzle is used for atomizing the torch oil.
Located at the bottom of the regenerated catalyst standpipe, Regenerated catalyst
slide valve (RCSV) controls the flow of hot catalyst to reactor-riser, based on reactor
outlet temperature set point. Allowable pressure drop for the RCSV is 0.37 kg/cm 2.
Catalyst flow rate through RCSV is 509 kg/sec and catalysts density is 600 kg/m 3. The
max port opening area is 155 mm2. Nitrogen purging is provided at stem and guide.
The recovered catalyst is returned to the regenerator via diplegs and the flue gas
flows to the energy recovery section.
44

45. Withdrawal Well
The hot, regenerated catalyst flows into a withdrawal well from the second stage
regenerator. The withdrawal well allows the catalyst to properly deaerate to
standpipe density before entering the vertical regenerated catalyst standpipe. This
design ensures smooth and even catalyst flow down the standpipe. Aeration taps,
located stepwise down the standpipe, serve to reaerate the catalyst and replaces gas
volume lost due to compression. Each aeration tap has adjustable flow rates to
maintain desirable standpipe density as catalyst circulation rates and/or catalyst
types vary. The catalyst passes through the regenerated catalyst slide valve,
designed for high temperature catalyst. Catalyst continues flowing down the 45
degree slanted wye section to the riser base where the catalyst begins an upward
flow toward the fresh feed injectors. Fluidization steam is used in the wye section to
ensure stable catalyst flow in the 45 degree lateral transfer.
45

46. Regenerator Details
Regen. 2 Regen. 1
Regenerator Diameter (Shell/Lining), mm 7700 / 7500 8000 / 7800
Regenerator Operating Conditions:
Temperature (NOR/MAX), oC 707 / 735 628/678
Pressure (NOR/MAX), kg/cm2 g 1.62 / 3.88 2.65/3.88
Regenerator Design Conditions:
Temperature (Metal/Internal), oC 343 / 816 343/760
Pressure, kg/cm2 g 5.90 5.90
Air Blower and Air Heater
Two air heaters provide hot air to each the first and second stage regenerators
during start-up. The downstream side of the air heaters will operate around 650 °C
during start-up operations. Total combustion air to the first stage regenerator splits
upstream of the air heater. Since the inner ring flow is a small fraction of the total
flow, the air heater only heats the air to the outer ring, All flow elements and control
valves in the air piping is placed upstream of the air heaters. One air blower driven
by a condensing steam turbine provides combustion air for both regenerators and
for the catalyst lift line.
Flue Gas Energy Recovery
The carbon monoxide rich flue gas from the first stage regenerator exits the orifice
chamber and enters the CO Incinerator to convert the CO to CO2 for complying with
the environmental requirements. This CO Incinerator burns auxiliary fuel oil or fuel
gas required to heat the incoming CO rich flue gas. At this temperature the CO reacts
with the oxygen in the auxiliary air and converts to CO2. Pressure on the first stage
regenerator is modulated by controlling the flue gas slide valve at the upstream of
Orifice chamber. By controlling the flue gas slide valve, the differential pressure
between the first and second stage regenerators is adjusted.
The flue gas from second stage regenerator combines with the first stage
regenerator flue gas coming from CO-Oxidizer and passes through a heat recovery
system consisting of HP steam, MP steam Super heaters and a Boiler feed water pre-
heater. The flue gas gets cooled but the actual temperature should not be less than
sulphur dew point temperature and also should be more than the Boiler feed water
temperature. Boiler feed water injection facility is provided at the outlet of CO-
Oxidizer for taking care of very high temperature.
46

47. Flue Gas Desulphurization (FGD):
The flue gases are finally routed to The Flue Gas Desulphurization Unit, where the
sulphur in the flue gas is brought down to environmentally acceptable limits before
venting to atmosphere through stack. Particulate matter in the flue gas is also
brought down to acceptable levels in FGD.
Main Fractionation Section
The function of a gas recovery process is to separate and recover the light
hydrocarbon vapors and hydrocarbon liquid stream produced by the cracking
reactions in fluid catalytic cracking reactions in a FCC reactor. These products are:
Absorber gas
LPG (liquid C3/C4 product)
Light gasoline
Medium gasoline
Heavy gasoline
Light cycle oil(LCO)
Heavy cycle oil(HCO)
Slurry oil
Heavy gasoline and LCO are combined to produce a Total Cycle Oil (TCO) product.
MAIN FRACTIONATOR:
The fractionator consists of 30 valve trays, 3 chimney trays and 8 rows of shed decks.
The reactor effluent, comprised of cracked hydrocarbon vapors, steam and inert gas,
enters the fractionators at the bottom of the quench section. In this section of the
fractionator the superheated cracked vapors and inerts are cooled and the bottom
product is condensed.
The small amount of entrained catalyst in the cracked vapors is scrubbed out and
drops to the bottom with the condensed product. The slurry pumparound, slurry oil
product and the slurry recycle, if present, are withdrawn from the bottom of the
fractionator and pumped through the fresh feed preheat exchangers, slurry MP
steam generators and the boiler feed water preheaters. In addition,a portion of the
slurry from the slurry pumparound pumps bypasses all of the slurry pumparound
exchanger and returns to the top of the shed decks together with the slurry
pumparound return flow. This bypassed flow rate is controlled such that the total
slurry rate returning to the MF shed decks is equal to 120% of the FCCU fresh feed
47

48. rate. The additional slurry recycle flow to the shed decks provides extra liquid to
keep the decks wet and minimize coking problems on decks.
Depending on the fresh feed preheat requirement, the duties of these exchangers
will vary. One shell of the slurry/feed exchangers or one shells of the slurry/MP
steam generators can actually be shut down during different operating cases. Slurry
pupmaround return temperature control on the water bypass.
The cooled slurry pumparound stream is returned on flow control to the top of the
shed decks in the quench section. The slurry oil product is drawn from the returning
slurry pumparound stream on flow control reset by fractionator bottoms level
control. Entrained catalyst is removed from the slurry oil product and slurry recycle
in the slurry oil filter on flow control back to the FCC unit reactor riser. The slurry oil
product is cooled by the Slurry Air Cooler to the required battery limit temperature
before being sent from the unit. Backwash from the slurry oil filters carries catalyst
fines removed from the slurry oil and slurry recycle back to the reactor riser.
The MF bottom liquid has a tendency for coking. Coking is promoted by high
temperature and long residence time. To maintain the fractionators bottoms
temperature at 360 C, a cold quench stream from the slurry pumparound system is
directly mixed, under temperature control at the slurry pump discharge, with the
fractionator bottom liquid. Also, steam is injected into the bottom liquid to
counteract coke formation and to maintain catalyst and coke particles in suspension.
The fluffing steam rate is manually regulated by a globe valve.
Heavy Cycle Oil pumparound (HCO PA), recycle and reflux are withdrawn from a total
draw chimney tray. The reflux is pumped back to the wash trays below the HCO
chimney trayon flow control reset by the chimney tray level controller. The HCO
pumparound is utilised to reboil the LCO stripper, reboil the gasoline splitter,
preheat the fresh feed and preheat the boiler feed water before beinf returned
three trays above its drawoff chimney tray on flow control. The pumparound return
temperature is controlled by bypassing fresh feed around the HCO PA/ feed
exchanger. In the fractionator, the HCO PA is used to further cool the cracked vapors
from the slurry section, condense the HCO recycle and control the internal reflux
above the HCO section.
The HCO recycle flows to the HCO stripper on stripper level control where it is
stripped of light components by the use of steam. The stripped HCo recycle is on
flow control and cooled in the HCO recycle/MP strem generator. The HCO recycle
temperature to the riser is controlled by manually bypassing HCO recycle around the
exchanger. The cooled HCO is sent to the riser.
48

49. The LCO PA and product are withdrawn from a partial drawoff chimney tray. The LCO
PA is returned back to the MF by providing the heat input to the stripper reboiler,
preheating the fresh feed. The LCO product flows to the LCO stripper where it is
stripped of lighter components and LCO water by LCO stripper reboiler. The stripped
LCO is first cooled in the medium Gasoline splitter. Reboiler. The LCO stream is then
cooled against fresh feed, BW and air. The LCO is then sent for Hydrotreating unit or
storage.
Sponge absorber lean oil is drawn off the MF from a partial draw off chimney tray
and is used in Lean oil sponge absorber. The rich oil from the bottom of the sponge
absorber is returned to the MF to recover the light ends absorbed in sponge
absorber.
The total overhead MF vapors consist of gasoline components and lighter
hydrocarbons together with steam and inert gas from the reactor plus MF top reflux.
The net HC liquid plus the top reflux and most of the steam is condensed in the
fractionator’s overhead condensers and separated from the non condensed vapors
in the overhead receiver. The condensed steam with impurities is also separated
from liquid HC in this receiver. The vapors from the receiver flow to the Wet Gas
Compressor. Knock out Drum in the recovery section. The net HC is pumped to the
recovery section.
Product recovery section:
The wet gas from the MF overhead receiver is compressed to approx. 16.9 kg/cm2
by a two stage centrifugal compressor. The hot gases discharged from the first stage
mix with wash water from the HP separator and are then partially condensed against
cooling water before entering compressor interstage drum. The uncondensed
vapors, the medium pressure distillate, and the sour water are separated in this
drum. The uncondensed vapors are compressed by a second stage compressor. This
stream is then mixed with rich oil from absorber and the top vapors from the
stripper before being further condensed. The uncondensed vapors are routed to the
absorber and the top vapors from the stripper before being further condensed
against cooling water and entering HPS.
The absorber is a 30 tray (plus 1 chimney tray) tower designed to recover 95% of the
C3/C4 LPG in the reactor effluent. The lean oil is taken from MF. The low pressure
distillate from the MF overhead receiver is delivered to the top tray of the absorber.
The unabsorbed vapors and supplemented lean oil are separated in a Absorber
Reflux Drum. The unabsorbed vapors are routed to sponge absorber. The rich oil is is
sent to HP separator.
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50. Sponge absorber is a 20 tray tower where essentially all the C4 and C5 entrained in
the absorber gas from the low pressure distillate are recovered. The lean oil used for
absorption is heavy naptha from MF. The rich sponge oil leaves from the bottom and
is sent back to MF. The offgas flows to the Acid Gas Removal system.
The Stripper is a 30 tray (plus 1 chimney tray) tower designed to remove the inerts,
C2’s and lighter hydrocarbons from the liquefied C3+ hydrocarbon stream to control
the vapor pressure of the LPG product recovered downstream. The Stripper is
reboiled on temperature control by using LCO pumparound as the heating medium.
The Stripper overhead vapors leave the tower at the top and are recontacted with
the Wet Gas Compressor second stage effluent, the compressor interstage
condensate, and the rich oil from the Absorber. Any water that may be carried over
from the High Pressure Separator as a result of operational upset, can be withdrawn
from the chimney tray below tray 3 of the Stripper. The water is collected in an
outside water separator drum and routed back to the Wet Gas Compressor first
stage discharge.
The Stripper bottoms stream flows by differential pressure on flow control reset by
Stripper bottoms level to the Debutanizer tower. This stream is heated against
Debutanizer bottoms before entering the Debutanizer partially vaporl2ed.
The Debutanizer is a 41 tray tower designed to produce a totally condensed
overhead mixed, IC LPG product and a bottoms C 5+ product. The Debutanizer is
reboiled on temperature control that resets the saturated high pressure steam flow
controller.
The Debutanizer overhead product is totally condensed by an air condenser and a
cooling water condenser. A hot vapor bypass around the condensers provides a
balance line which equalizes the pressures of the tower and the reflux drum. The
tower pressure is controlled by varying the condensing rate of the overhead vapor.
The water condenser outlet control valve is used to adjust the flooding condition in
the water condenser thus regulating the vapor condensing rate. Reflux from the
drum is pumped on flow control to the top tray of the Debutanizer. LPG product is
pumped by a product pump to amine treating on flow control reset by reflux drum
level control after being cooled against cooling water.
The total Debutanizer bottoms stream, comprised of the net naphtha product and
supplemental lean oil recycle, is cooled by exchanging heat against the Debutanizer
feed. The cooled naphtha stream is then split into the net naphtha product and the
supplemental lean oil recycle. The naphtha product is fed to the Gasoline Splitter by
pressure differential on flow control reset by Debutanizer bottoms level control. A
booster pump is used to increase the supplemental lean oil pressure to the
50

51. Absorber-Stripper pressure level before being further cooled against air and
combined with the Absorber overhead vapors on flow control. The supplemental
lean oil can also be routed to the MF Overhead Condenser for C3 /C absorption.
The Debutanizer bottoms product flashes before entering the Gasoline Splitter
tower. This is a 27 tray tower designed to separate the net naphtha product in the
total feed into a light gasoline product recovered overhead, a medium gasoline
product as a middle draw product and a heavy gasoline product. The heavy gasoline
product leaves the splitter bottom and is pumped on flow control reset by splitter
bottom level control after being cooled against fresh feed. The heavy gasoline
product is cooled against cooling water before being sent to battery limits. The LCO
product from the Main Fractionator area can also combine with the heavy gasoline
product upstream of the cooling water exchanger to produce a net TCO product
before being sent to battery limits.
HCO pumparound is utilized as the heating medium in the Gasoline Splitter reboiler.
The HCO PA stream is on flow control reset by tower temperature. To maintain the
total HCO PA flow requirement, flow is bypassed around the reboiler on differential
pressure control.
The light gasoline overhead product is totally condensed against air and fed to the
reflux drum where pressure is maintained by a split range pressure controller.
Nitrogen is used as blanketing gas for the reflux drum. Reflux is pumped on flow
control reset by tower overhead temperature to the top tray of the splitter. Light
gasoline product is cooled against cooling water and sent to the Gasoline Treating
Unit on flow control reset by reflux drum level control. In addition, a flow controlled
light gasoline stream is sent to the Naphtha Hydrotreater Unit after blending with
the medium gasoline product.
A side draw from tray 7 of the Gasoline Splitter feeds the Medium Gasoline Stripper
on stripper bottom level control. LCO product is used in the reboiler as the heating
medium with a manual bypass around the reboiler to control the reboiler stripping
duty. Vapor from the stripper overhead returns to the Gasoline Splitter while the
bottom medium gasoline product is pumped to the Naphtha Hydrotreater Unit after
being cooled against cooling water and combined with the light gasoline product.
The controller of this combined light/medium gasoline stream is located outside the
battery limits. Part of the medium gasoline is also sent on flow control to the
Gasoline Treating Unit. A separate line is provided to recycle a portion of the
medium gasoline product on flow control to the reactor riser when needed.
51

52. Acid Gas Removal System
The C3/C 4 LPG overhead product from the Debutanizer contains hydrogen sulfide (H
2S) and mercaptans which need to be removed before it is treated in the LPG
Treating Unit.
The absorber gas from the Sponge Absorber contains the majority of the hydrogen
sulfide (H $) resulting from the cracking reaction plus all the carbon dioxide (CO 2)
entrained in the regenerated catalyst as inerts. These two acid gases are removed
from the absorber gas before it is sent to the refinery fuel gas pool.
The removal of the hydrogen sulfide from the LPG and the acid components from
the absorber gas is done by contacting each of these streams with a 40 wt % solution
of methyl-diethanol-amine (MDEA) in separate towers designed for the
corresponding service.
The LPG mix product enters the bottom of the LPG Liquid Contactor where it is
contacted counter currently through two packed beds of 1 1/2” pall rings with the
MDEA solution. The lean MDEA solution enters near the top of the contactor on flow
control. The treated LPG stream leaves the top of the contactor and process water is
injected into the stream for final amine washing. The washed LPG enters the LPG
Liquid Separator where any entrained MDEA and water settle out before being
cooled against cooling water and routed to battery limits. Amine solution is collected
in the separator boot where it is removed by boot level control to the Absorber Gas
Contactor bottom. The H rich amine is pumped to battery limits from the bottom of
the contactor on interface level control which is located near the top of the
contactor.
The Sponge Absorber sour gas is further cooled against cooling water before
entering the Absorber Gas K.O. Drum to separate any entrained oil.
Condensed/entrained hydrocarbon liquid is routed back to the MF on drum level
control. The sour gas then flows into the Absorber Gas Contactor where it is
contacted with the MDEA solution to remove the H 2S and CO2 from the gas. The
lean MDEA solution feeds to tray 3 of the contactor on flow control. A small amount
of wash water is sent to the top tray of the contactor to further remove any
entrained amine solution in the treated gas. The sweet gas leaves the top of the
absorber, flows through the Absorber Gas Contactor K.O. Drum and then is routed to
battery limits on back pressure control. The operating pressure of the Sponge
Absorber and the Absorber/Stripper system is also controlled by this pressure
controller.
52

53. Condensed hydrocarbon liquid from the contactor K.O. drum is also routed to the
Absorber Gas Contactor bottom on drum level control. H 2S rich amine solution is
pumped to battery limits from the bottom of the contactor by bottom level control.
Boiler feed water is used as wash water for the two contactors. The hot BFW is first
cooled in a cooling water exchanger before being routed to the two contactors. A
pressure controller is used to reduce the pressure of the BFW to the LPG Liquid
Contactor operating pressure.
.
BIBLIOGRAPHY:
The following folders at Essar Oil Ltd, Vadinar
 Essar Docs // Operating Manuals
 ELC Vadinar//Presentations
 www.wikipedia.com
 Perry’s Chemical engineering Handbook
 Mccabe, Smith & Harriot, 3rd edition.
53

54. PROJECT
ARTIFICIAL NEURAL NETWORKING
Objective: To optimize the regenerator temperature by the use of Artificial Neural Network
(ANN) at the given feed conditions.
Theory of Artificial Neural Network:
Introduction:
An Artificial Neural Network (ANN), usually called neural network (NN), is a mathematical
tool or computational model that is inspired by the structure and/or functional aspects of
biological neural networks. A neural network consists of an interconnected group of artificial
neurons, and it processes information using a connectionist approach to computation. In most
cases an ANN is an adaptive system that changes its structure based on external or internal
information that flows through the network during the learning phase. Modern neural
networks are non-linear statistical data modeling tools. They are usually used to model
complex relationships between inputs and outputs or to find patterns in data.
54

55. In an artificial neural network, simple artificial nodes, variously called neurons, neurodes,
processing elements (PEs) or units are connected together to form a network of nodes
mimicking the biological neural networks—hence the term artificial neural network.
Although computing these days is truly advanced, there are certain tasks that a program made
for a common microprocessor is unable to perform; even so a software implementation of a
neural network can be made with their advantages and disadvantages.
Advantages:
A neural network can perform tasks that a linear program cannot.
When an element of the neural network fails, it can continue without any problem by
their parallel nature.
A neural network learns and does not need to be reprogrammed.
It can be implemented in any application.
It can be implemented without any problem.
Disadvantages:
The neural network needs training to operate.
The architecture of a neural network is different from the architecture of
microprocessors therefore needs to be emulated.
Requires high processing time for large neural networks.
In the world of engineering, neural networks have two main functions: Pattern classifiers and
as non linear adaptive filters. As its biological predecessor, an artificial neural network is an
adaptive system. By adaptive, it means that each parameter is changed during its operation
and it is deployed for solving the problem in matter. This is called the training phase.
Working of ANN
An artificial neural network is developed with a systematic step-by-step procedure which
optimizes a criterion commonly known as the learning rule. The input/output training data is
fundamental for these networks as it conveys the information which is necessary to discover
the optimal operating point. In addition, a non linear nature makes neural network processing
elements a very flexible system.
Basically, an artificial neural network is a system. A system is a structure that receives an
input, process the data, and provides an output. Commonly, the input consists in a data array
which can be anything such as data from an image file, a WAVE sound or any kind of data
that can be represented in an array. Once an input is presented to the neural network, and a
corresponding desired or target response is set at the output, an error is composed from the
difference of the desired response and the real system output.
The error information is fed back to the system which makes all adjustments to their
parameters in a systematic fashion (commonly known as the learning rule). This process is
repeated until the desired output is acceptable. It is important to notice that the performance
hinges heavily on the data.
55

56. The word network in the term 'artificial neural network' refers to the inter–connections
between the neurons in the different layers of each system. An example system has three
layers. The first layer has input neurons, which send data via synapses to the second layer of
neurons, and then via more synapses to the third layer of output neurons. More complex
systems will have more layers of neurons with some having increased layers of input neurons
and output neurons. The synapses store parameters called "weights" that manipulate the data
in the calculations.
An ANN is typically defined by three types of parameters:
1. The interconnection pattern between different layers of neurons.
2. The learning process for updating the weights of the interconnections.
3. The activation function that converts a neuron's weighted input to its output
activation.
Mathematical Model for ANN
Once modeling an artificial functional model from the biological neuron, we must take into
account three basic components. The synapses of the biological neuron are modeled as
weights. These synapses are the one which interconnects the neural network and gives the
strength of the connection. For an artificial neuron, the weight is a number, and represents the
synapse. A negative weight reflects an inhibitory connection, while positive values designate
excitatory connections. The following components of the model represent the actual activity
of the neuron cell. All inputs are summed altogether and modified by the weights. This
activity is referred as a linear combination. Finally, an activation function controls the
amplitude of the output. For example, an acceptable range of output is usually between 0 and
1, or it could be -1 and 1.
Mathematically, this process is described in the figure
56