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  1. 1. Project Report On The Fluidized Catalytic Cracking Unit Essar Oil Limited, VadinarSubmitted By: Guided By:Himanshu Jain Mr. Dipesh A. ModiB.Tech (Chemical Engg) DGM (FCCU)IIIrd yearIT-BHU 1
  2. 2. ABSTRACTThis report is prepared at Essar Oil Ltd, Jamnagar as a part of the industrial trainingand 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 projectundertaken in the same unit as a part of practical training along with themethodology and the procedure adopted are also included in this report.Project guide,Mr.Dipesh.A.ModiDGM (FCCU) 2
  3. 3. ACKNOWLEDGEMENT It has been an immense pleasure and truly enriching experience doing myvocational training at Essar Oil Limited, Vadinar. I take this opportunity to thank all those people who have made thisexperience 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-operationand proper guidance during my training. I would like to thank my guide Mr. Dipesh Modi, DGM (FCCU) who has beenthe guiding force behind the completion of this project. I am sincerely thankful to theentire team of the FCC unit for their valuable help and guidance in the completion ofmy training. I am also thankful to Mr. Prashant Arya, Joint GM, HR for giving me anopportunity to work with Essar Oil Limited. I would also like to thank Mrs. PoojaJoshi 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 forthe opportunity and assistance they provided me to do my training here.Thanking You.Himanshu Jain 3
  4. 4. PREFACEAny amount of theoretical knowledge is incomplete without exposure to industrialpractice. Practical knowledge means visualization and application of knowledgewhich we read in books. Theoretical studies cannot be perfect without practicaltraining. Hence, in-plant training is of great importance for an engineering student.Teaching gives theoretical aspect of technology, but practical training givesknowledge of industrial activities.My aim for this industrial training was to optimize the regenerator temperature atdifferent feed conditions in the Fluidized Catalytic Cracking Unit. For optimizing theregenerator temperature, I have used Artificial Neural Network in Matlab andgenerated 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 industrialexperience at the Vadinar refinery. 4
  5. 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. 6. Essar Group-ProfileIntroduction to EssarThe Essar Group is one of India’s largest corporate houses with interests spanning themanufacturing 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 turnoverof over US$ 2.08 bn. It employs 20000 people in 50 locations worldwide. Strategicinvestments made by the group over the past decade have resulted in the creation oftangible and intangible assets that are at the heart of the Indian Economy.The Group takes pride in being a high-performance multinational organization, providingworld class services and products. Manned by a highly efficient and dynamic team ofemployees, the Group is growing stronger every day. A committed corporate citizen, thegroup provides unwavering support to the community as well as initiates various social andecological drives that have a positive impact on society.All the groups investments have been consolidate under Essar Global Ltd. with its six sectorsholding 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 SteelIt is headed by Chairman Shashi Ruia & Vice Chairman Ravi Ruia.MissionTo create enduring value for customers and stakeholders in core manufacturing and servicebusinesses, through world class operating standards, state-of-the-art technology and the‘positive attitude’ of our people. 6
  7. 7. BASICS OF REFININGRefining: The process of separating the components of crude oil, progressivelyaltering and re-blending them to produce fuels like LPG, Motor Gasoline, Kerosene,Diesel, Fuel Oils , Residual Fuel Oils and Lubricants with maximum yields profitablywith 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. 8. CRUDE OILCrude : Is a mixture of hydrocarbons and impurities of inorganic salts and metals.Itis 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 distillationCrude 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. 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 classificationContents 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  Asphalts6. TBP distillation curve with API and Sulphur 1. TBP curve 9
  10. 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, PenetrationDistinguishing 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. 11. REFINERY PLANT OVERVIEWA 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 ProcessesPrimary 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 requirementsSecondary 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. 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. 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 refineryMiscellaneous 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. 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 facilitiesThe 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
  16. 16. SAFETYSome of the common hazards that workers, visitors and the process in itself areprone 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 HazardsProcess 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 bewearing safety shoes, safety helmet, a pair of gloves, full sleeved cotton outfit, earplugs to avoid being affected by the afore mentioned hazards. 16
  17. 17. CRACKING PROCESSCracking is a phenomena by which large oil molecules are decomposed into smallerboiling molecules.Types Of Cracking:  Thermal Cracking:Dissociation of high molecular weight hydrocarbons in to smaller fragments throughheat 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 Catalyticcracking.  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. 18. CHEMISTRY OF THE FLUID CATALYTICCRACKING PROCESS:The theory of catalytic cracking is based on Carbonium ion formation andsubsequent H2 transfer reaction. From the basic organic chemistry it could beenvisaged that whenever a molecule breaks into two, two bonds become free. Inabsence of free hydrogen atoms in the vicinity, one of the new born molecules has todevelop a double bond. Alternately, coke is generated in the cracking reaction tomaintain Hydrogen balance. To control this coke formation or formation of very smallmolecules, the industrial cracking of heavy petroleum molecules are aided bycatalysts.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 ofCatalyst.Once the carbonium ion is formed by the catalyst it may proceed further asfollows:• 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 reactionHydrogen transfer reaction converts an olefin to paraffin. The source of the hydrogenisanother olefinic hydrocarbon on the catalyst which will progressively become morehydrogen deficient. This hydrogen deficient molecule will get adsorbed very stronglytothe catalyst & form the coke on the catalyst during reactionReactions: 18
  19. 19. (Chain breaking step)Reactions a, b, c are indefiniteDealkylation of the aromatics occur in the similar manner Overall Reaction flow diagram 19
  20. 20. FCC CATALYSTFCC catalyst history:Brief:The concept of FCC was developed during 1940’s with powdered fluidizedcatalyst.A significant change came about when Y type Zeolites were being usedinstead of the high alumina amorphous catalyst, which was used in 1950’s.Thereactor configuration was changed because of the high active and lower cokeforming tendency of Zeolite catalysts.In the mid 1960’s USY based catalysts wereintroduced of high hydro thermal stability produce less coke and also increase theoctane number of the gasoline.During 1980’s large number of additives such asnickel and vanadium passivators, CO combustion promoters and SO X emissioncontrollers and special additives for attrition resistance, octane improvement weredeveloped, 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. 21. Zeolite catalyst:Zeolites are molecular sieves that are incorporated into the catla;yst. The chemicalcomposition basically the same as the earlier type of catalyst, but the structure isradically different. The main components are Zeolite, Clay,Matrix (Silica or Aluminagel) and binder. A Zeolite is a crystalline alumina-silicacompound with a frame workstructure. This regular structure differentiates the Zeolite from the previous catalysts,which were amorphous having sponge- like structure. The Zeolite has regularcavities which can be occupied by large ions or water. These ions may beexchanged for others as long as electrical neutrality is maintained. Advantages:The first commercial catalyst was made with 8 - 10 % zeolites and showed anactivity 1.5 -2 times the amorphous catalyst. This higher activity proved to be anadvantage for gasoline oriented operations but for middle distillate operations, theamorphous type catalyst is still used. To utilize this higher activity, then came theconcept of short contact time in the riser. This short contact time minimizesundesirable over cracking, while good conversion was maintained because of highcatalyst activity. Because of this the recycle quantity of the heavy oil from MF has gotreduced. 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 16Catalyst for the processing of resids in specially designed FCCU has to be designedwith a range of pore size distribution to handle the large molecules(>30A o) presentand 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. 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 H2transfer 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 thegasolinetendency to pre ignite or “pring” under compression. The reported octane no. isactuallythe percentage of isooctane in isooctane/normal heptanes blend that has the sametendency 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 zeroby definition.RON:– The Research Octane Number of octane number determination correlateswith full-scale spark-ignited engine antiknock performance at low speed -600 RPM.The test method utilizes a single cylinder, four stroke and adjustable cylinder heightengine and requires critical adjustment of fuel / air ratio and compression ratio toproduce a standard knock intensity condition. RON correlates the commercialautomotive spare ignition engine antiknock performance under mild condition of theoperationMON: The Motor Octane Number correlates with full scale spark ignited engineantiknock performance at higher speed – 900 RPM with mixture heater temperatureand variable spark angle. It provides a means of defining the quality of motorgasoline for use in vehicles on the road. MON correlates the commercial automotivespare 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. 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 absorptionCatalyst features:• Binder is the material used in the FCC catalyst to bind the matrix and zeolitecomponents into a single homogeneous particle.• Matrix is a substitute in which the zeolite is imbedded in the cracking catalyst usedas a term for active, non-zeolitic component of the FCC catalyst• Zeolite is a synthetic Alumina-Silicate material used in the manufacturing of FCCcatalyst.• Hydrogen transfer is the secondary reaction that converts olefins (predominantlyiso-olefins)into paraffin’s while extracting hydrogen from larger molecules. 23
  24. 24. The presence of Zeolite in the catalyst will1. Increase conversion2. Increase delta coke formation3. Reduce the gasoline selectivity and increase LPG selectivity4. Increase RON, MON of gasolineThe presence of Rare earth in the catalyst will1. Increase conversion2. Increase delta coke formation3. Increase the gasoline selectivity4. Decrease RON and increase / decrease MON of gasolineThe presence of Matrix activity in the catalyst will1. Increase / Decrease conversion2. Increase delta coke formation3. Increase the gasoline selectivity4. Increase RON and MON of gasolineImportant charecteristics of Catalyst  ActivityActivity is the conversion produced by a catalyst when tested on a specified feed atspecified conditions. This is normally done in a bench scale test unit.  ConversionConversion = Gas + LPG + Gasoline + Coke in vol % or wt %.  SelectivityH - 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. 25.  Surface AreaIt 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 ofNitrogen on the surface.Density of FCC catalyst:Skeletal Density (SD) = 2.1 * SiO2 + 3.4 * Al2O3 /100Particle Density (PD): 1/PD = 1/SD + PVPV = 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 allowedto 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 mediumparticle 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 -- VanadiumAttrition index Increases Increases -- Increases Increases ABD -- -- -- -- Decreases APS Decreases Decreases -- Increases Decreases 25
  26. 26. Fluidized Catalytic Cracking (FCC) Unit: 3. Fcc_unit Introduction to FCC:Objective:  To upgrade Gas oil of the refinery  To maximize LPG yieldProcess 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 crackingOther processes used for FCC:  Universal Oil product (UOP) process 26
  27. 27. Advantages of FCC:The high octane number which has become an important factor for gasoline qualitycan only be achieved by FCC. Though investment cost of FCC unit is high, theincreased yield of high quality products from FCC unit justifies for the installation ofFCC unit.Selection of the process:The process used at ESSAR, Jamnagar is provided by SWEML(Stone & WEBSTEREngineering(Mauritius) Limited) as:It incorporates a 2-staged regenerator system; a unique fed injection system and aproprietary 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 bycatalytically cracking the feed mixture of vacuum gas oils from the Vacuum andVisbreaker units.UGSU (Unit No.3500): The UGS unit has an objective of separating the distillateand LPG from the overhead outlet of FCC.The ultimatum is to maximize the recoveryof C3’s and C4’s from the unsaturated gas (Minimum 95%).FGD-Flue Gas Desulphurization(Unit No.4500): The FGD unit has an objective ofremoving sulphur and catalyst fine dust particles from the flue gas outlets of theFCCU regenerator section through the usage of caustic alkali solution. 27
  28. 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 followingsystems:  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. 29. Capacity and Feed Stock: The FCC unit is designed for processing 2.93 MMTPA of feed obtained fromprocessing 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.1Characteristic 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. 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 2.92Nitrogen ppm wt 400 1100 1500 1500 968 Nickel ppm wt 0 0.5 13.0 5.0 1.3Vanadium 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 cstFlow Rate MT/SD 2265 5480 443 610 8798 Table.2 30
  31. 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. 32. Yield Pattern and Product Routing:Feed Stock: 25.75% LVGO, 62.29 % HVGO, 5.03 % HHVGO and 6.93 % VVGOmixture from 70 / 30 AL / AH crude mix Product Yield Wt% Vol% API H2s 1.46 Off-gas 3.49 Cracked LPG 13.68 22.63Gasoline(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.4Product 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. 33. Product characteristics:Following are the products obtained from FCC & UGS:1. Unsaturated LPG2. Cracked Gasoline ( Light + Medium ), Heavy Gasoline3. Light Cycle Oil4. Slurry Oil5. Coke6. Off GasTotal cycle oil (TCO) is a mixture of Heavy Gasoline & Light Cycle OilUnsaturated LPGVapour pressure @ 65 oC 16.87 kg/cm2gH2S content wt ppm 15(max)Evaporation temperature for 95 vol % at 2 oC (max)760 mm Hg. Table.6Total Gasoline (Light + Medium) and also for heavy gasolineTBP cut point,(oC) C5 -- 125C4 content wt % 0.5(max)API gravity 70Sulphur wt % 0.15RONC 92.0 minReid Vapour Pressure kg/cm2g 0.7 max Table.7Light 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. 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.9Slurry 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.10Coke Sulphur wt % 4.96 H2 wt % 7 Table.11Off-gas H2S volume ppm 100 (max) Table.12 34
  35. 35. Process DescriptionThe 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. 36. nozzle condition. Dispersion steam is supplied to each fresh feed injector to promotefresh feed atomization and vaporization. The total dispersion steam is flowcontrolled 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. 20100Legends:P = Purging with Steam TIN = Purging with NitrogenS = 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. 37. Convertor SectionThe converter section of the S&W Fluid Catalytic Cracking Unit (FCCU) describedherein consists of the following major equipment: Riser Reactor & Catalyst Stripper First Stage Regenerator Second Stage Regenerator Air BlowerThe function of the unit is catalytic cracking of mixtures of vacuum tower gas oils,vacuum tower bottoms, hydrocracker bottoms and visbreaker gas oils. Thesefeedstocks 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 OperationThe FCCU utilizes a riser/reactor, catalyst stripper, a first stage regeneration vessel, asecond stage regeneration vessel, a catalyst withdrawal well, and catalyst transferlines.Riser/ Reactor SystemThe riser is designed to rapidly and intimately mix the hot regenerated catalyst withliquid feedstocks. Fine atomization of the fresh feed is accomplished by six S&W oilinjectors utilizing medium pressure steam for dispersion. Two additional S&W oilinjectors are installed further up the riser to allow the unit to recycle oil as necessaryto maximize distillate product. In addition to these oil injectors, steam injectors areprovided at various locations along the riser to ensure a stable and homogeneouscatalyst circulation.The reactor design begins at the base of the riser or the reverse seal section. Thebottom wye section causes turbulence and potentially uneven catalyst flow patterns.Therefore, a high density zone is provided to absorb shocks and stabilize the catalystflow. For proper travel of the catalysts, eight (8) fluidization steam nozzles areprovided at 3 different locations of the wye section. Three down-flow stabilizationsteam injectors promote smooth and homogeneous catalyst flow as the catalystmoves upward toward the fresh feed injectors. These steam injectors are locatedmidway between the riser bottom and the fresh feed injectors. Fluidization steam inthe 45 degree wye section and the stabilization steam in the reverse seal sectionensure even catalyst flow as the catalyst reaches the feed injection section. Theminimum steam flow is 50 kg/hr when catalyst is circulating and the design flow is941 kg/hr. The steam flow should provide a velocity within reverse seal at 1.5 m/sec. 37
  38. 38. This straight vertical section below the fresh feed injectors also serves as a reverseseal providing protection against oil flow reversal.At the same elevation as the stabilization steam injectors, an injector has beenlocated to provide for recycling medium gasoline to the riser at the client’s option. Inorder to increase the gasoline octane, the medium gasoline fraction may be recycledintermittently. The Heat and Material Balances do not include this recycle stream.Fresh feed is finely atomized, mixed with dispersion steam, and injected into theriser through the S&W patented feed injectors. A total of six fresh feed injectors arespecified in this design. The Design oil flow rate per feed injector is 61097 kg/hr anddispersion steam flow rate per injector is 2138 kg/hr. The small droplets of feedcontact the freshly regenerated hot catalyst and instantaneously vaporize. The oilmolecules intimately mix with the catalyst particles and crack to lighter morevaluable products: LPG, distillate, and gasoline. Additional byproducts producedfrom the FCCU are slurry oil, fuel gas, and coke. Since the cracking reaction involvesthe breaking of large molecule into smaller molecules, there is a molar expansionand thus an increase in the volume of gas over the riser length. In order to maintainthe design velocity across the riser length, diameter needs to be increased. Here wehave 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 designedfeed injection system ensures maximum conversion of the oil to lighter productswhile 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 reactiontakes place in the lower section of the riser. A generally used rule of thumb is theone-third / two thirds rule. This states that two-thirds of the conversion will takeplace in the first one-third of the riser volume. The regenerated catalyst slide valvecontrols the riser outlet temperature by regulating the amount of hot regeneratedcatalyst entering the riser. Riser residence time for the design case is approximately1.6 seconds.Injection of a metal passivator into the fresh feed reduces hydrogen production andimproves yields of the valuable products when processing vacuum tower bottoms.Nickel, typically present in residual feedstocks, will deposit on the cracking catalystand acts as a dehydrogenating catalyst. Metal passivation should be consideredwhen the nickel content on the equilibrium catalyst is greater than 1000 ppmw.Optionally, catalyst with built-in nickel traps should be considered as anothermethod of controlling feed metals.The recycle oil injection nozzles are located approximately 5.6 meters above thefresh feed injectors. These S&W patented recycle oil injectors are designed tomaximize 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. 39. recycling medium gasoline. As this project basis focuses on LPG production, therecycle injectors will normally not be in use.Placed further up along the riser approximately 12.2 meters above the fresh feedinjectors is the slurry filtration backwash injector. This injector is designed forhandling an oil/catalyst mixture. This injector serves to return catalyst filtered out ofthe slurry product stream.Inertial SeparatorAfter the reaction mixture travels up the riser, the catalyst, steam, and hydrocarbonproduct mixture passes through an inertial separator. This separator or risertermination device (RTD) quickly disengages the catalyst from the vapor mixture tominimize over cracking of valuable products. At the top of the riser, the catalyst andvapor mixture divides into two parallel streams. Each stream begins a circularrotation around a center tube which is outfitted with a vapor outlet slot. Inertialeffects force the catalyst particles to the cylinder wall where the catalyst exitsdownward into the inertial separator’s dipleg. The cracked hydrocarbon and steamvapor with entrained catalyst leave the separator through the center tube whereducting directs flow up near the cyclone inlets. The gas outlet ducts are open-endedand direct the vapor/catalyst mixture upward toward the reactor cyclone inletwindows. This rapid separation and ducting minimizes the vapor residence timethereby reducing secondary thermal reactions in the disengaging vessel. The vaporsand entrained catalyst pass through four single stage high efficiency cyclones. Thecyclone diplegs have partially shrouded trickle cheek valves to ensure a positive sealand terminate in the dilute phase at the same elevation as the RTD diplegs. Reactorcyclones further separate the product vapors from the entrained catalyst, returningthe catalyst to the stripper. Reactor products, inerts, steam, and a minute amount ofcatalyst flows from the reactor overhead into the base of the main fractionator. Theprimary concerns in riser operations are:(1) The choke velocity of the riser(2) The riser pressure drop(3) The catalyst hold up in the riserThe minimum velocity below which the catalyst / vapor mixture in the riser will notremain in dilute phase transport but drops into a dense phase is called the ChokeVelocity. 39
  40. 40. Stripper sectionThe stripper portion of this vessel utilizes five disk and do-nut baffle stages. Thesebaffles 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 fromthe catalyst before it enters the regeneration system. The steam fluffing ring, locatedin the bottom head of the stripper, keeps the catalyst properly fluidized and ensuressmooth catalyst flow into the spent catalyst transfer line.Total stripping steam requirement: For gas oil, 3 kg/Ton of catalysts circulation and forresidue 5 kg/Ton of catalysts. The design flow of steam through this ring is 7800 kg/hr with50 % turndown. 55 nozzles are provided in the ring. The nozzle ID is 21 mm and the RO ID is13 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. 41. Spent Catalyst TransferStripped catalyst leaves the stripper through the 45 degree slanted withdrawalnozzle and then enters a vertical standpipe. The spent catalyst flows down throughthis standpipe and into a second 45 degree lateral section that extends into the firststage regenerator. The spent catalyst slide valve is located near the bottom of thevertical 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. Themax port opening area is 145 mm2. Careful aeration of the catalyst standpipeensures proper head buildup and smooth catalyst flow. The flow rates from theaeration taps are adjustable to maintain a stable standpipe density for differentcatalyst circulation rates or different catalyst types. The catalyst, containing roughly1.0 -1.5 wt % coke, enters the first stage regenerator through a catalyst distributorwhich disperses the catalyst onto the bed surface.Reactor Details:Riser Length (m) 38.9Riser Operating Conditions Wye Section Riser LineTemperature (NOR/MAX), oC 707/735 491/519Pressure (NOR/MAX), kg/cm2 g 2.63/4.04 2.63/4.04Riser Design Conditions Wye Section Riser LineTemperature (Metal/Int.), oC 343/816 343/566Pressure, kg/cm2 g 6.8 6.8Reactor / Cyclone MOC CS (SA516 Gr. 70)Reactor Diameter (Steel/Lining), m 6.6 / 6.4Reactor Length, m 2.50Reactor Operating ConditionsTemperature (NOR/MAX), oC 491/519Pressure (NOR/MAX), kg/cm2 g 2.10/3.52Reactor Design ConditionsTemperature (Metal/Int.), oC 343/566Pressure, kg/cm2 g 5 41
  42. 42. First Stage RegeneratorThe operational severity of the first stage regeneration is intentionally mild due tothe partial combustion operational mode. Essentially all the hydrogen on the coke isburned off the coke in the low temperature first stage regenerator. This mildtemperature along with partial combustion minimizes hydrothermal deactivation ofthe catalyst and controls the conversion of CO to CO2. As a result, catalyst surfacearea 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 stageregenerator. Typical residual operations require burning of 60 to 70 percent of thecoke in the first stage regenerator. This ability to vary the coke burn split betweenregenerators 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 oCCO + 1/2O2 CO2 H = + 5600 Kcal/kg oCC + O2 CO2 H = + 7820 Kcal/kg oCH2 + 1/2O2 H2O H = + 28900 Kcal/kg oCS + xO SOX H = + 2209 Kcal/kg oCN + xO NOXC + CO2 2CO 42
  43. 43. The diameter of the first stage regenerator vessel is carefully determined on thebasis of superficial gas velocity. Coke on the catalyst is burned in the regenerator’slower dense phase zone where higher superficial velocity aids catalyst mixing.However, the vessel superficial velocity is optimized at a low enough value to inhibitcatalyst entrainment to the cyclones in the upper dilute phase.Combustion air is split between two rings in the first stage regenerator. These ringsprovide even air distribution across the catalyst bed resulting in proper fluidizationand combustion. The rings are designed to split the flow approximately 70 percentand 30 percent to the outer ring and inner ring, respectively. The carbon monoxiderich flue gases pass through four sets of two-stage cyclones before leaving theregenerator.The catalyst level in the 1st stage is controlled by the hollow stemmed plug valve atthe bottom of the lift line. The normal bed level of the catalyst in the 1 st stage is3600 mm above the tangent line. The max. bed level is 900 mm above the normalbed level. The minimum bed level maintains a seal of 300 mm on the secondarycyclone dip leg.Four set of two stage cyclones are mounted internally to the regenerator to separatethe catalysts from the flue gas. The design gas flow rate through these cyclones is15714 kg/hr and superficial velocity of 0.65 m/sec. The cyclone inlet pressure is 2.68kg/cm2 g and temperature is 628 oC. Max. inlet velocity for both cyclones is 20m/sec. The secondary cyclones are provided with partially shrouded Trickle valve.Plug ValvePartially regenerated catalyst flows downward in the first stage regeneration vesselto the lift line entrance. Careful fluidization with a fluffing air ring in this area allowsthe catalyst to pass smoothly into the lift line. The air flows into the lift line throughthe hollow stem plug valve. This air pneumatically lifts the catalyst in dilute phase tothe second stage regeneration vessel. The minimum air velocity for acceptable lift is7.5 m/sec based on lift line operating conditions. The velocity should not exceed 21m/sec to avoid erosion problems. Combustion air used to raise the catalyst can varybetween 30 and 40 percent of the total air to the second stage regenerator. For thedesign case, 30 percent of the combustion air is used. The plug valve controls thebed level in the first stage regenerator.Second Stage RegeneratorAs the catalyst enters the second stage regeneration vessel, below the combustionair 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 andcatalyst. In the second stage regenerator, the remaining carbon, less than .05%, on 43
  44. 44. the catalyst is completely burned with excess oxygen, resulting in a highertemperature compared to the first stage regenerator. One air ring in this regeneratordistributes a portion of the combustion air, while the lift air provides the remainderof the air. With most of the hydrogen burned in the first stage, moisture content ofthe second stage regenerator flue gases is minimized. This allows highertemperatures in the second stage regenerator without causing hydrothermalcatalyst 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 differentsuperficial gas velocities. Coke remaining on the catalyst is burned in theregenerator’s lower dense phase zone where the higher superficial velocity aidscatalyst mixing. The larger diameter upper dilute phase zone reduces entrainment tothe cyclones. This vessel has minimum internals which helps eliminate temperaturelimitations under any current or possible future operating condition. The catalystsbed level in the 2nd stage is not directly controlled but depends on the catalystinventory. Periodic withdrawals are made from the 2nd stage to maintain the level innormal operating range. The withdrawal nozzle location is such that it alwaysensures 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 1.65kg/cm2g and temperature is 707 oC. Max. inlet for primary cyclones is 20 m/sec andfor secondary cyclones is 24 m/sec. The secondary cyclones are provided withpartially shrouded Trickle valve.There are three nos. of torch oil nozzles provided in the regenerator for initializingthe combustion reactions during the start up. The nozzles are designed for an oilflow rate of 1949 kg/hr each and oil inlet temperature of 140 oC. Dispersion steam of59 kg/hr/nozzle is used for atomizing the torch oil.Located at the bottom of the regenerated catalyst standpipe, Regenerated catalystslide valve (RCSV) controls the flow of hot catalyst to reactor-riser, based on reactoroutlet 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. Themax 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 gasflows to the energy recovery section. 44
  45. 45. Withdrawal WellThe hot, regenerated catalyst flows into a withdrawal well from the second stageregenerator. The withdrawal well allows the catalyst to properly deaerate tostandpipe density before entering the vertical regenerated catalyst standpipe. Thisdesign ensures smooth and even catalyst flow down the standpipe. Aeration taps,located stepwise down the standpipe, serve to reaerate the catalyst and replaces gasvolume lost due to compression. Each aeration tap has adjustable flow rates tomaintain desirable standpipe density as catalyst circulation rates and/or catalysttypes vary. The catalyst passes through the regenerated catalyst slide valve,designed for high temperature catalyst. Catalyst continues flowing down the 45degree slanted wye section to the riser base where the catalyst begins an upwardflow toward the fresh feed injectors. Fluidization steam is used in the wye section toensure stable catalyst flow in the 45 degree lateral transfer. 45
  46. 46. Regenerator Details Regen. 2 Regen. 1Regenerator Diameter (Shell/Lining), mm 7700 / 7500 8000 / 7800Regenerator Operating Conditions:Temperature (NOR/MAX), oC 707 / 735 628/678Pressure (NOR/MAX), kg/cm2 g 1.62 / 3.88 2.65/3.88Regenerator Design Conditions:Temperature (Metal/Internal), oC 343 / 816 343/760Pressure, kg/cm2 g 5.90 5.90Air Blower and Air HeaterTwo air heaters provide hot air to each the first and second stage regeneratorsduring start-up. The downstream side of the air heaters will operate around 650 °Cduring start-up operations. Total combustion air to the first stage regenerator splitsupstream of the air heater. Since the inner ring flow is a small fraction of the totalflow, the air heater only heats the air to the outer ring, All flow elements and controlvalves in the air piping is placed upstream of the air heaters. One air blower drivenby a condensing steam turbine provides combustion air for both regenerators andfor the catalyst lift line.Flue Gas Energy RecoveryThe carbon monoxide rich flue gas from the first stage regenerator exits the orificechamber and enters the CO Incinerator to convert the CO to CO2 for complying withthe environmental requirements. This CO Incinerator burns auxiliary fuel oil or fuelgas required to heat the incoming CO rich flue gas. At this temperature the CO reactswith the oxygen in the auxiliary air and converts to CO2. Pressure on the first stageregenerator is modulated by controlling the flue gas slide valve at the upstream ofOrifice chamber. By controlling the flue gas slide valve, the differential pressurebetween the first and second stage regenerators is adjusted.The flue gas from second stage regenerator combines with the first stageregenerator flue gas coming from CO-Oxidizer and passes through a heat recoverysystem 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 thansulphur dew point temperature and also should be more than the Boiler feed watertemperature. Boiler feed water injection facility is provided at the outlet of CO-Oxidizer for taking care of very high temperature. 46
  47. 47. Flue Gas Desulphurization (FGD):The flue gases are finally routed to The Flue Gas Desulphurization Unit, where thesulphur in the flue gas is brought down to environmentally acceptable limits beforeventing to atmosphere through stack. Particulate matter in the flue gas is alsobrought down to acceptable levels in FGD.Main Fractionation SectionThe function of a gas recovery process is to separate and recover the lighthydrocarbon vapors and hydrocarbon liquid stream produced by the crackingreactions 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 oilHeavy 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 thefractionator the superheated cracked vapors and inerts are cooled and the bottomproduct is condensed.The small amount of entrained catalyst in the cracked vapors is scrubbed out anddrops to the bottom with the condensed product. The slurry pumparound, slurry oilproduct and the slurry recycle, if present, are withdrawn from the bottom of thefractionator and pumped through the fresh feed preheat exchangers, slurry MPsteam generators and the boiler feed water preheaters. In addition,a portion of theslurry from the slurry pumparound pumps bypasses all of the slurry pumparoundexchanger and returns to the top of the shed decks together with the slurrypumparound return flow. This bypassed flow rate is controlled such that the totalslurry rate returning to the MF shed decks is equal to 120% of the FCCU fresh feed 47
  48. 48. rate. The additional slurry recycle flow to the shed decks provides extra liquid tokeep the decks wet and minimize coking problems on decks.Depending on the fresh feed preheat requirement, the duties of these exchangerswill vary. One shell of the slurry/feed exchangers or one shells of the slurry/MPsteam generators can actually be shut down during different operating cases. Slurrypupmaround return temperature control on the water bypass.The cooled slurry pumparound stream is returned on flow control to the top of theshed decks in the quench section. The slurry oil product is drawn from the returningslurry pumparound stream on flow control reset by fractionator bottoms levelcontrol. Entrained catalyst is removed from the slurry oil product and slurry recyclein the slurry oil filter on flow control back to the FCC unit reactor riser. The slurry oilproduct is cooled by the Slurry Air Cooler to the required battery limit temperaturebefore being sent from the unit. Backwash from the slurry oil filters carries catalystfines 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 hightemperature and long residence time. To maintain the fractionators bottomstemperature at 360 C, a cold quench stream from the slurry pumparound system isdirectly mixed, under temperature control at the slurry pump discharge, with thefractionator bottom liquid. Also, steam is injected into the bottom liquid tocounteract 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 totaldraw chimney tray. The reflux is pumped back to the wash trays below the HCOchimney trayon flow control reset by the chimney tray level controller. The HCOpumparound is utilised to reboil the LCO stripper, reboil the gasoline splitter,preheat the fresh feed and preheat the boiler feed water before beinf returnedthree trays above its drawoff chimney tray on flow control. The pumparound returntemperature is controlled by bypassing fresh feed around the HCO PA/ feedexchanger. In the fractionator, the HCO PA is used to further cool the cracked vaporsfrom the slurry section, condense the HCO recycle and control the internal refluxabove the HCO section.The HCO recycle flows to the HCO stripper on stripper level control where it isstripped of light components by the use of steam. The stripped HCo recycle is onflow control and cooled in the HCO recycle/MP strem generator. The HCO recycletemperature to the riser is controlled by manually bypassing HCO recycle around theexchanger. The cooled HCO is sent to the riser. 48
  49. 49. The LCO PA and product are withdrawn from a partial drawoff chimney tray. The LCOPA 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 isstripped of lighter components and LCO water by LCO stripper reboiler. The strippedLCO is first cooled in the medium Gasoline splitter. Reboiler. The LCO stream is thencooled against fresh feed, BW and air. The LCO is then sent for Hydrotreating unit orstorage.Sponge absorber lean oil is drawn off the MF from a partial draw off chimney trayand is used in Lean oil sponge absorber. The rich oil from the bottom of the spongeabsorber is returned to the MF to recover the light ends absorbed in spongeabsorber.The total overhead MF vapors consist of gasoline components and lighterhydrocarbons 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 thefractionator’s overhead condensers and separated from the non condensed vaporsin the overhead receiver. The condensed steam with impurities is also separatedfrom liquid HC in this receiver. The vapors from the receiver flow to the Wet GasCompressor. Knock out Drum in the recovery section. The net HC is pumped to therecovery section.Product recovery section:The wet gas from the MF overhead receiver is compressed to approx. 16.9 kg/cm2by a two stage centrifugal compressor. The hot gases discharged from the first stagemix with wash water from the HP separator and are then partially condensed againstcooling water before entering compressor interstage drum. The uncondensedvapors, the medium pressure distillate, and the sour water are separated in thisdrum. The uncondensed vapors are compressed by a second stage compressor. Thisstream is then mixed with rich oil from absorber and the top vapors from thestripper before being further condensed. The uncondensed vapors are routed to theabsorber and the top vapors from the stripper before being further condensedagainst cooling water and entering HPS.The absorber is a 30 tray (plus 1 chimney tray) tower designed to recover 95% of theC3/C4 LPG in the reactor effluent. The lean oil is taken from MF. The low pressuredistillate 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 AbsorberReflux Drum. The unabsorbed vapors are routed to sponge absorber. The rich oil is issent to HP separator. 49
  50. 50. Sponge absorber is a 20 tray tower where essentially all the C4 and C5 entrained inthe absorber gas from the low pressure distillate are recovered. The lean oil used forabsorption is heavy naptha from MF. The rich sponge oil leaves from the bottom andis 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 controlthe vapor pressure of the LPG product recovered downstream. The Stripper isreboiled on temperature control by using LCO pumparound as the heating medium.The Stripper overhead vapors leave the tower at the top and are recontacted withthe Wet Gas Compressor second stage effluent, the compressor interstagecondensate, and the rich oil from the Absorber. Any water that may be carried overfrom the High Pressure Separator as a result of operational upset, can be withdrawnfrom the chimney tray below tray 3 of the Stripper. The water is collected in anoutside water separator drum and routed back to the Wet Gas Compressor firststage discharge.The Stripper bottoms stream flows by differential pressure on flow control reset byStripper bottoms level to the Debutanizer tower. This stream is heated againstDebutanizer bottoms before entering the Debutanizer partially vaporl2ed.The Debutanizer is a 41 tray tower designed to produce a totally condensedoverhead mixed, IC LPG product and a bottoms C 5+ product. The Debutanizer isreboiled on temperature control that resets the saturated high pressure steam flowcontroller.The Debutanizer overhead product is totally condensed by an air condenser and acooling water condenser. A hot vapor bypass around the condensers provides abalance line which equalizes the pressures of the tower and the reflux drum. Thetower 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 inthe water condenser thus regulating the vapor condensing rate. Reflux from thedrum is pumped on flow control to the top tray of the Debutanizer. LPG product ispumped by a product pump to amine treating on flow control reset by reflux drumlevel control after being cooled against cooling water.The total Debutanizer bottoms stream, comprised of the net naphtha product andsupplemental lean oil recycle, is cooled by exchanging heat against the Debutanizerfeed. The cooled naphtha stream is then split into the net naphtha product and thesupplemental lean oil recycle. The naphtha product is fed to the Gasoline Splitter bypressure differential on flow control reset by Debutanizer bottoms level control. Abooster pump is used to increase the supplemental lean oil pressure to the 50
  51. 51. Absorber-Stripper pressure level before being further cooled against air andcombined with the Absorber overhead vapors on flow control. The supplementallean oil can also be routed to the MF Overhead Condenser for C3 /C absorption.The Debutanizer bottoms product flashes before entering the Gasoline Splittertower. This is a 27 tray tower designed to separate the net naphtha product in thetotal feed into a light gasoline product recovered overhead, a medium gasolineproduct as a middle draw product and a heavy gasoline product. The heavy gasolineproduct leaves the splitter bottom and is pumped on flow control reset by splitterbottom level control after being cooled against fresh feed. The heavy gasolineproduct is cooled against cooling water before being sent to battery limits. The LCOproduct from the Main Fractionator area can also combine with the heavy gasolineproduct upstream of the cooling water exchanger to produce a net TCO productbefore 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 thetotal HCO PA flow requirement, flow is bypassed around the reboiler on differentialpressure control.The light gasoline overhead product is totally condensed against air and fed to thereflux 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 flowcontrol reset by tower overhead temperature to the top tray of the splitter. Lightgasoline product is cooled against cooling water and sent to the Gasoline TreatingUnit on flow control reset by reflux drum level control. In addition, a flow controlledlight gasoline stream is sent to the Naphtha Hydrotreater Unit after blending withthe medium gasoline product.A side draw from tray 7 of the Gasoline Splitter feeds the Medium Gasoline Stripperon stripper bottom level control. LCO product is used in the reboiler as the heatingmedium with a manual bypass around the reboiler to control the reboiler strippingduty. Vapor from the stripper overhead returns to the Gasoline Splitter while thebottom medium gasoline product is pumped to the Naphtha Hydrotreater Unit afterbeing cooled against cooling water and combined with the light gasoline product.The controller of this combined light/medium gasoline stream is located outside thebattery limits. Part of the medium gasoline is also sent on flow control to theGasoline Treating Unit. A separate line is provided to recycle a portion of themedium gasoline product on flow control to the reactor riser when needed. 51
  52. 52. Acid Gas Removal SystemThe C3/C 4 LPG overhead product from the Debutanizer contains hydrogen sulfide (H2S) and mercaptans which need to be removed before it is treated in the LPGTreating Unit.The absorber gas from the Sponge Absorber contains the majority of the hydrogensulfide (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 removedfrom 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 fromthe absorber gas is done by contacting each of these streams with a 40 wt % solutionof methyl-diethanol-amine (MDEA) in separate towers designed for thecorresponding service.The LPG mix product enters the bottom of the LPG Liquid Contactor where it iscontacted counter currently through two packed beds of 1 1/2” pall rings with theMDEA solution. The lean MDEA solution enters near the top of the contactor on flowcontrol. The treated LPG stream leaves the top of the contactor and process water isinjected into the stream for final amine washing. The washed LPG enters the LPGLiquid Separator where any entrained MDEA and water settle out before beingcooled against cooling water and routed to battery limits. Amine solution is collectedin the separator boot where it is removed by boot level control to the Absorber GasContactor bottom. The H rich amine is pumped to battery limits from the bottom ofthe contactor on interface level control which is located near the top of thecontactor.The Sponge Absorber sour gas is further cooled against cooling water beforeentering the Absorber Gas K.O. Drum to separate any entrained oil.Condensed/entrained hydrocarbon liquid is routed back to the MF on drum levelcontrol. The sour gas then flows into the Absorber Gas Contactor where it iscontacted with the MDEA solution to remove the H 2S and CO2 from the gas. Thelean MDEA solution feeds to tray 3 of the contactor on flow control. A small amountof wash water is sent to the top tray of the contactor to further remove anyentrained amine solution in the treated gas. The sweet gas leaves the top of theabsorber, flows through the Absorber Gas Contactor K.O. Drum and then is routed tobattery limits on back pressure control. The operating pressure of the SpongeAbsorber and the Absorber/Stripper system is also controlled by this pressurecontroller. 52
  53. 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   Perry’s Chemical engineering Handbook  Mccabe, Smith & Harriot, 3rd edition. 53
  54. 54. PROJECT ARTIFICIAL NEURAL NETWORKINGObjective: 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 mathematicaltool or computational model that is inspired by the structure and/or functional aspects ofbiological neural networks. A neural network consists of an interconnected group of artificialneurons, and it processes information using a connectionist approach to computation. In mostcases an ANN is an adaptive system that changes its structure based on external or internalinformation that flows through the network during the learning phase. Modern neuralnetworks are non-linear statistical data modeling tools. They are usually used to modelcomplex relationships between inputs and outputs or to find patterns in data. 54
  55. 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 nodesmimicking the biological neural networks—hence the term artificial neural network.Although computing these days is truly advanced, there are certain tasks that a program madefor a common microprocessor is unable to perform; even so a software implementation of aneural 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 andas non linear adaptive filters. As its biological predecessor, an artificial neural network is anadaptive system. By adaptive, it means that each parameter is changed during its operationand it is deployed for solving the problem in matter. This is called the training phase.Working of ANNAn artificial neural network is developed with a systematic step-by-step procedure whichoptimizes a criterion commonly known as the learning rule. The input/output training data isfundamental for these networks as it conveys the information which is necessary to discoverthe optimal operating point. In addition, a non linear nature makes neural network processingelements a very flexible system.Basically, an artificial neural network is a system. A system is a structure that receives aninput, process the data, and provides an output. Commonly, the input consists in a data arraywhich can be anything such as data from an image file, a WAVE sound or any kind of datathat can be represented in an array. Once an input is presented to the neural network, and acorresponding desired or target response is set at the output, an error is composed from thedifference of the desired response and the real system output.The error information is fed back to the system which makes all adjustments to theirparameters in a systematic fashion (commonly known as the learning rule). This process isrepeated until the desired output is acceptable. It is important to notice that the performancehinges heavily on the data. 55