HMEL Report

A Summer Internship Report OVERVIEW OF REFINERY HPCL-MITTAL ENERGY LTD, BATHINDA, PUNJAB A report submitted in partial fulfilment for the award of degree of Bachelor of Technology in Petrochemical Engineering By PINDI VENKATA DORABABU 15021A2545 Under the Guidance and Supervision of Mr. VENUGOPAL UPADHYAYULU PROCESS ENGINEER, HMEL-R&D HPCL-MITTAL ENERGY LTD, BATHINDA. DEPARTMENT OF PETROLEUM ENGINEERING AND PETROCHEMICAL ENGINEERING UNIVERSITY COLLEGE OF ENGINEERING KAKINADA (A) JAWAHARLAL NEHRU TECHNOLOGICAL UNIVERSITY KAKINADA KAKINADA – 533003 2018 DECLARATION I, P.V. DORABABU, hereby declare that this summer internship report entitled “OVERVIEW OF REFINERY HPCL-MITTAL ENERGY LTD, BATHINDA, PUNJAB” is original and has not previously formed the basis for the award of any degree to similar work. Place: Kakinada Date:7-12-2018 Signature P.V. Dora Babu  ACKNOWLEDGEMENTS I would like to express my profound sense of gratitude to my guide and supervisor, Mr. Venugopal Upadhayulu, Process Engineer, HMEL-R&D, HPCL-MITTAL Energy Ltd, for his skilful guidance, timely suggestions and encouragement in completing this project. I use this acknowledgement to express sincere gratitude to Sri Mahesh (Head of Training) and Sri Rahul (Training Associate) who guided me a lot in making my industrial training a successful one. I also thank Sri. Charanjeet Singh (Assistant General Manager) for his ethical support in making my training a successful one. I acknowledge my sincere thanks and deep-felt gratitude to Prof. K.V. Rao, Programme Director, Petroleum Courses, Jawaharlal Nehru Technological University Kakinada for arranging the summer internship program. I take this opportunity to express my sincere thanks to Dr. K. Meera Saheb, Head of the Department, Department of Petroleum Engineering and Petrochemical Engineering for encouraging and motivating me to complete the internship and report successfully. Also, I express my special thanks to our beloved Principal, Dr. P. Subba Rao his enthusiastic support in our endeavours. Finally, I am very much grateful to my parents for their financial support and encouragement throughout the internship programme. P.V. DORA BABU (15021A2545) CONTENTS S.NO TITLE PAGE Declaration ii Certificate iii Acknowledgements iv Abstract vi List of Tables vii List of Figures vii 1 CHAPTER 1: OVERVIEW OF GGSR REFINERY 1 2 CHAPTER 2: VARIOUS UNITS AND THEIR CONFIGURATIONS 4 3 CHAPTER 3: FCC UNIT 16 4 CHAPTER 4: SULPHUR UNIT 31 5 CHAPTER 5: CONCLUSION 45 ABSTRACT An oil refinery is an industrial process plant where crude oil is processed and refined into more useful petroleum products like LPG, Petrol, Kerosene, Aviation Turbine Fuel, Diesel etc. Petroleum refining begins with Distillation, or fractionation, of crude oils into separate hydrocarbon groups. The resultant products are directly related to the characteristics of the crude oil being processed. Most of these products of distillation are further converted into more usable products by changing their physical and molecular structures through cracking, reforming and other conversion processes. These products are subsequently subjected to various treatment and separation processes such as extraction, hydrotreating and sweetening, in order to produce finished products. These processes are also affected by economic factors including crude costs, product values, availability of utilities and transportation. LIST OF TABLES Table Caption Page 1 Feed Characteristics of FCC 18 2 Product Characteristics of FCC 18 LIST OF FIGURES Figure Caption Page 1 Block diagram of HMEL Refinery 3 2 Flow diagram of FCC unit 21 3 FCC unit 21 4 Sulphur block 31 5 Major sections in SRU 33 6 BFD of SWS-1 39 7 BFD of SWS-2 39 8 BFD of ARU 40 9 BFD of Sulphur removal 43 10 PFD of Sulphur recovery 44   CHAPTER 1: OVER VIEW OF GGSR REFINERY ABOUT HMEL HPCL-Mittal Energy Limited (HMEL) is a joint venture between Hindustan Petroleum Corporation Limited (HPCL) and Mittal Energy Investment Pte Ltd, Singapore – a Lakshmi N Mittal Group Company. Both the JV partners hold a stake of 49% in the company, the rest of 2% will be held by financial institutions. The project was completed in 2011. The refinery will produce petroleum products complying with EURO IV emission norms with Crude Oil pipeline from Mundra (Gujarat) to Bathinda with Single Point Mooring (SPM) and Crude Oil terminal at Mundra. About JV Partners Hindustan Petroleum Corporation Ltd HPCL is a Fortune 500 company. HPCL operates 2 major refineries, producing a wide variety of petroleum fuels and specialities, one in Mumbai of 6.5 MMTPA capacity and the other in Visakhapatnam with a capacity of 7.5 MMTPA. Mittal Energy Investment Pte Ltd Mittal Energy Investment Pte Ltd is part of Arcerlor Mittal Group owned by Mr. Lakshmi Niwas Mittal. CORE VALUES OF HMEL Our values define and measure us. Our core values speak of our actions so ingrained to steer us towards success and act as a driving force. Our values are our philosophy and culture, helping to build a world-class Energy company. We are governed by six core values. Safety First. Team work. Continuous Improvement and Learning. Respect for people. High Ethical Standards. Achieve Targets and Meet Deadlines. ABOUT GURU GOBIND SINGH REFINERY (GGSR) Guru Gobind Singh Refinery (GGSR) is the single largest investment and first oil and gas industry to set up in the state of Punjab, India. Operates at 9.0 MMTPA crude processing level. 1012 Km 28” & 30” diameter Crude Oil pipeline from Mundra to Bathinda. Crude oil Terminal at Mundra. Single point Mooring and 17 Km 48” diameter offshore/onshore pipeline at Mundra. Total area is 2307 acres (Refinery block: 1600 acres; Water block: 400 acres; Green Belt area: 307 acres). State of Art safety & environmental features with world class technology. Flexibility to process a wide variety of crude oils including heavy, sour and other opportunity crudes. High value-added products: LPG, Naphtha, Petrol, Diesel, Aviation fuel, Polypropylene, Hexane, etc. Diesel/Petrol of Euro III & IV quality. Crude range of 26.5-32 deg API. Capability to process high sulphur crudes up to 3% wt. “S”. Capability to process acidic crudes up to TANS 0.5 mg KOH/g. High Nelson Complexity Index (10.7) for meeting indigenous demand. Fig 1. BLOCK DIAGRAM OF HMEL REFINERY CHAPTER 2: VARIOUS UNITS AND THEIR CONFIGURATIONS CDU/VDU plant details: Unit objective: To separate crude oil into different products by boiling point differences & prepare feed for secondary processing units. Feed input: Crude oil Products: LPG to LPG treater Stabilized naphtha to NHT/HGU/HRU Swing naphtha to naphtha pool Light kerosene to ATF merox/ kero pool/ DHDT Heavy kerosene to DHDT/ kero pool Light & heavy gas oils to DHDT Light & heavy vacuum gas oils to VGO-HDT Vacuum residue to DCU MS block details: MS- Block consists three units, Naphtha hydrotreating unit. Naphtha isomerization unit. Continuous catalytic regeneration reformer unit Naphtha Hydrotreating Unit details: Unit objective: The objective of the naphtha hydrotreating unit is to hydrotreat naphtha streams produced from crudes distillation and FCC & DHDT to produce treated naphtha containing less than 0.5 wt. ppm sulphur and less than 0.1wt. ppm nitrogen. Feed input: Naphtha streams from crude distillation, FCC & DHDT products. Products: Light naphtha to isomerization unit feed. Heavy naphtha to CCR unit feed. Isomerization unit details: Unit objective: The purpose of this unit is to increase the RON (research octane number) of the hydrotreated light naphtha cut from naphtha hydrotreating unit in order to meet the required target of gasoline pool production. Isomerate product is the blend of light and heavy isomerate from deisohexaniser column. Isomerization: It is the conversion of low octane straight chain compound to their high octane branched isomers. Example: Feed input: Hydrotreated light naphtha cut from naphtha hydrotreating unit Products: Isomerate An off-gas stream sent to CCR unit Continuous Catalytic Cracking Unit: Unit objective: The purpose of continuous catalytic reformer unit is to produce high octane aromatics from paraffin and naphthene’s for use as a high-octane blending component. Reforming: It involves conversion of low octane paraffinic & naphtha compounds to aromatics. Feed input: Hydrotreated heavy naphtha cut from naphtha hydrotreating unit. Off gas from isomerization unit. Products: Reformate LPG Diesel Hydrotreating Unit Details: Unit objective: The process objective is to maximize production of diesel to meet the euro IV specifications. Feed input: Mixture of LGO, HGO, vacuum diesel, LKO & HKO, Heavy naphtha from CDU/VDU. Coker naphtha, LCGO from DCU. LCO from FCC unit. DSO rich stream from the LPG treating unit Products: NAPHTHA (10%) to NHT and storage. ATF/MTO (6%) to final product blending. Diesel (83%) to final product blending. DCU plant details: Unit objective: Delayed coking unit is to convert low value residual products to lighter products of higher value and to produce a coke product. Feed input: Vacuum residue from VDU/VR tanks. VGO HDT back flush. FCCU slurry back wash. Slop oil from tank. Crude sludge for crude tanks. Sludge from ETP. Lean amine. Products: Fuel gas to RFG header. LPG to LPG treating unit. Rich amine to ATU. LCGO + Naphtha to DHT. Sour water to SWS. HCGO to VGO HT. Petroleum coke. DCU Salient Features: Converts vacuum residue in to fuel gas, LPG, Naphtha, Gas oil and petroleum coke. Satisfies refinery FG (fuel) requirement. Converts fuel oil to other valued products LPG, Naphtha, Coker, diesel, coke in refinery. No catalyst cost. Low chemical/additive cost. Coke as by-product- for power plant/ cement plant. Coker can process refinery slops. Sludge. VGO HDT plant details: Unit objective: The main objective of the unit is to produce hydro treated VGO having desired level of hydrogen, low sulphur and low nitrogen for the various design feed cases. The hydro treated VGO is feedstock for the FCC unit. Feed input: A mixture of straight run VGO from CDU/VDU. HCGO from DCU unit. Products: Sweet gas to PSA for H2. LPG to LPG treating units. Naphtha for blending. Diesel to DHDT. Hydrotreated VGO to FCC unit. FCCU plant details: Unit objective: The process objective of this unit is to convert heavy hydrocarbon to light hydrocarbon (propane, propylene, butane, and butylene etc.) product. Feed input: Mix of straight run VGO. HCGO from CDU/VDU and DCU. Products: Propylene to PPU. Fuel gas to FG treating unit. LPG to LPG treating unit. LCN/MCN naphtha to MS block. LCN/MCN to MS blending in offsites. HGU plant details: Unit objective: To generate hydrogen of high purity required for hydro-processing units of refinery (NHT, DHDT and VGO-HDT), ISOMER, PP & SRU TGT. Feed input: SR naphtha from NSU. DHDT Naphtha from DHDT. Product: Hydrogen for DHDT, VGO HDT, PPU, SRU, NHT, HRU. PPU plant details: Unit objective: Objective of polypropylene unit (PPU) is to produce polypropylene from propylene. Polypropylene: It is a long chain polymer made from propylene monomers. After exposing the propylene to both heat and pressure with an active catalyst, the propylene monomers combine to form a long chain polymer. Polypropylene is a thermoplastic polymer. Feed input: Propylene from propylene recovery unit of FCCU & propylene mounded bullets. Product: polypropylene polymer. SR & CR LPG treating plant details: Unit objective: The main objective of the unit is to remove H2S, mercaptans and carbonyl sulphate (COS) from straight run LPG (SR LPG) and cracked LPG (CR LPG) from CDU and DCU respectively. Feed input: SR LPG treating unit: SR LPG from CDU and VGO HDT. CR LPG treating unit: CR LPG from DCU. Products: LPG Auto-LPG SRU unit details: SRU block consists of the following units: Sour water stripper – I & II Amine regeneration unit Sulphur recovery unit – I & II SWS unit details: Unit objective: The process objective of SWS unit is to process sour water streams generated in refinery process unit’s CDU/VDU, DCU, flare KOD, ARU, SRU-TGTU, HGU and DCCU for single stage stripper. Sour water streams from VGOHDT and NHTU for two stage strippers for removal of H2S and NH3. Feed input: Sour water stripper-I (SWS-I) Sour water from CDU/VDU, DCU, flare KOD, ARU, TGTU, FFCU. Sour water stripper-II(SWS-II) Sour water from VGO HDT, DHDT, NHTU. Products: Stripped water to effluent treatment plant or water to CDU/VDU, FCCU and DCU. Stripped water to effluent treatment plant or water to VGO-DHT, DHDT, NHTU. ARU unit details: Unit objective: Recovering H2S from rich MDEA streams received from vacuum gas oil hydrotreater (VGO HDT) and diesel hydrotreater (DHDT), fuel gas ATU, LPG ATU and DCU. Feed input: Rich MDEA solution from fuel gas treating units, SR/CR LPG treating units, VGO HDT, DHDT & DCU. Product: Lean MDEA to refinery units. Acid H2S gas feed to SRU-I & SRU-II. SRU I & II-unit details: Unit objective: Main Objective of sulphur recovery unit is to convert H2S to elemental sulphur. Feed input: Acid gas(H2S) from amine regeneration unit. Sour gas(H2S) from sour water stripping unit. Products: Sulphur CPP plant details: Plant objective: The objective of captive power plant (CPP) is meet, besides internal requirements of the package, the total steam and power required by the refinery complex. Plant details: 2 NO. s gas turbine generators (GTG’s) along with heat recovery steam generators (HRSGs). 3 NO. s steam turbine generators (STGs)- 2 condensing type & 1 backpressure type. 4 NO. s utility boilers. -3w+1s. Pressure reducing de-superheaters- for generating HP, MP, LP steam. Deaerator & condensate storage buffer tank. CPP cooling tower. Chemical dosing systems. Total power generated: 164 MW (including internal consumption of CPP). Total steam generated: 900 TPH of steam. Feed/fuel: FG, light cycle oil (LCO), HSD for GTG’s & HRSG’s. FG, LCO for UBs. DM water from RO DM plant. CPU PLANT DETAILS: Plant objective: Condensate polishing unit (CPU) is a centralized facility for treating the suspect condensate in various process units, received from refinery complex, and meet the DM water quality parameters. CPU plant is integral part of RO DM plant. Major Steps involved: Feed condensate cooling- cooling of suspect condensate in a heat exchanger to reduce condensate temperature Adsorption – Removal of oil present in feed condensate by passing the condensate through activated carbon bed. Mixed bed polishing – MB unit has both strong acid cation resin and strong base anion resin mixed in a single vessel. Cations/anions are removed in mixed bed exchanger in order to achieve the required quality of treated condensate. Plant capacity: Three parallel and similar chains, each of net treatment capacity 75m3/hr. when two chains shall be under operation, the third chain shall be under regeneration/standby. Feed input: suspect condensate from refinery process units. RO DM plant: Plant objective: RO DM plant is a centralized facility for producing DM water for the refinery complex. DM water is required for following purposes. Boiler feed water makeup for generation of steam. Process water for dilution of chemicals, washing etc. RO DM plant: Pre-treatment stage: cooling of suspect condensate in a heat exchanger to reduce condensate temperature. Hardness removal unit: removal of oil present in feed condensate by passing the condensate through activated carbon bed. Degasification. High efficiency reverse osmosis skid. Mixed bed exchanger. DM water storage and pumping. Chemical handling and regeneration facilities. Sludge handling facilities. Waste disposal facilities. Plant capacity: 850m3/hr of DM water generation on continuous basis. Feed water: Cooling tower blowdown, treat effluent from ETP, boiler blow down & treated raw water. RWTP plant: Plant objective: Raw water treatment plant (RWTP) produce filtered and treated water to meet the requirements of: Cooling tower make-up. DM plant feed. Drinking water. Service water. Raw water reservoir-1100000m3 corresponds to 14 days of normal demand. Aeration tank. Rapid gravity sand filters. Filtered water reservoir. Pre-& post chlorination system. Cooling water make up, service water, drinking water pumps. Chemical handling and regeneration facilities. Sludge handling facilities. Waste disposal systems. Plant capacity: Total design capacity is 5400m3/hr. the plant comprises of two chains each of 2700m3/hr design capacity. Feed water: Raw water from raw water reservoir. ETP plant: Plant objective: Effluent treatment plant (ETP) treats effluent water received from various units in refinery and produce treated water for reuse in refinery. ETP plant details: Following treatment are done to the effluent water in ET: Physical treatment- API, CPI, DAF, clarifier, RO, UF, DMF, ACF, etc Chemical treatment- H2O2, cationic and anionic coagulant, flocculent & other polymers, acid, alkali, chlorine, biocides and its alternatives etc Biological treatment- activated sludge process, SBR, MBR. Spent caustic treatment. VOC treatment. Flare system: Flare system objective: The flare system is provided for safe disposal of combustible, toxic gases which are relieved from process plants and off sites during start-up, shutdown, normal operation or in case of an emergency such as: Cooling water failure. General power failure. External fire case. Any other operational failure. Blocked outlet. Reflux failure. Local power failure. Tube rupture. The refinery complex has two flare systems, one for hydrocarbon flare for process units & off-sites handling hydrocarbon and the other for the sulphur block handling sour flare. Flare system details: HC HP flare header- maximum allowable back pressure of 5.3 kg/cm2 at unit battery limit. HC LP flare header- maximum allowable back pressure of 1.4 kg/cm2 at unit battery limit. Sour flare header. Hydrocarbon flare knockout drum. Sour flare knockout drum. CHAPTER 3: FCC unit AN INTRODUCTION TO FCC UNIT The first commercial use of catalytic cracking occurred in 1915 when Almer M. McAfee of Gulf refining company developed a batch process using aluminium chloride to catalytically crack heavy petroleum oils. In earlier 1940’s, concept of FCC with powdered catalyst is introduced. FCC is one of the most important conversion processes used in petroleum refineries. It is widely used to convert the high-boiling, high-molecular weight hydrocarbon fractions of petroleum crude oils into more valuable gasoline and other products. Cracking was originally done by thermal cracking, which has been almost completely replaced by catalytic cracking because it produces more gasoline with a higher-octane rating. Zeolites are used instead of high alumina amorphous catalyst because of its extremely high active and lower coke forming tendency. In FCC, one can get high yield of lighter products and less heavier components. In FCC, high temperature yields more conversion. i.e. Conversion increases 0.2-0.5% per 5 deg. C of temperature. DCC converts hydrotreated VGO into lower boiling high value products, propylene. In DCC, conversion from naphtha into LPG is significant and if the conversion heavier than naphtha is insignificant. In DCC, on increasing the temperature, the aromatic content of gasoline raises. In DCC, lower space velocity increases the conversion and coke yield and reduce the yield of LPG. Also, in DCC, lower the hydrocarbon partial pressure (HCPP), greater the yield of propylene. FCC BASIC OVERVIEW Unit Objective: The Fluidized Catalytic Cracking Unit Petrochemical Complex is a Deep Catalytic Cracking Unit. The main objective of this units is to produce feeds to various units like PPU, MS Block and Offsite. Licensor: Stone & Webster. Detailed Engineering: Engineers India Limited. Design Capacity: 2.22 MMTPA. Feed Input: Mix of straight run VGO and HCGO from CDU/VDU and DCU. FCCU Product Details: Propylene to PPU. Fuel Gas to FG Treating Unit. LPG to LPG Treating Unit. LCN/MCN Naphtha to MS Block. LCN/MCN to MS Blending in Offsites. Catalyst: Conventional Zeolite + Pentasil (ZSM-5). Capacity & Turn around ratio: The DCC complex will be designed to process 2.22 MMTPA of unconverted oil from the VGO HDT Unit. The unit capacity and severity are determined by the light olefins’ productions. Stream factor: 8000 hours per calendar year. Run Length: Minimum 3 years between turn arounds. Turn down: 50% turndown of 110% capacity while meeting all product specifications. Table 1. Feed Characteristics of FCC Feed Unconverted Oil from VGO-HDT Unit Design flow 277500 kg/hr Specific gravity 0.893 Sulphur, ppmw <200 Total Nitrogen, ppmw <200 Basic Nitrogen, ppmw <70 Ni + V <0.1 CCR wt.% 0.05 Hydrogen Content, wt.% 12.8 Asphaltenes, ppmw <500 Table 2. Product characteristics of FCC Product Mass flow rate (kg/hr) Yield (%) Sour Fuel Gas 35431 10.8 Polymer Grade Propylene 61371 22.1 LGP 59073 21.1 LCN 14240 5 MCN 21506 8 LCO + HCN 74464 26.85 REACTION CHEMISTRY A complex series of reactions takes place when a large Gas Oil molecule comes in contact with a 650 0C to 760 0C FCC catalyst. The distribution of products depends on nature and strength of catalyst acid sites Major reactions in FCC: There is general agreement that the reaction mechanism for catalytic cracking of hydrocarbon involves the formation of intermediate positively charged organic species, called carbocations. In 1940’s, this idea was applied to cracking reactions over amorphous silica-alumina catalysts and more recently to Zeolite catalyst. The original theory, often called the “Carbonium ion theory” has been further refined and differentiation is now made between Carbonium ions and Carbenium ions. Carbenium ion: It is a tri coordinated ion. It is formed by the addition of proton(H+) to an olefin (or) the removal hydride ion (H-) from paraffins. Proton donors on the cracking catalyst provide the protons and Lewis acid sites remove the hydride ion. Three basic steps are involved in formation of Carbenium ion: Initiation. Propagation. Termination. In the termination step, Beta scission is takes place for the formation of Carbenium ion and an olefin. The reaction ends when, Carbenium ion loses a proton to the catalyst and is converted to an olefin. The Carbenium ion picks up a hydride ion from a donor and converts to paraffin. Carbonium ion: It is a Penta coordinated ion. A monomolecular reaction for paraffin cracking has been proposed where an intermediate carbonium ion s formed before it is converted to a Carbenium ion and a paraffin or hydrogen and a Carbenium ion. The reaction is favoured by temperature over 500 0C, low conversion, low hydrocarbon partial pressure. OPERATING VARIABLES Variable in many processes can be documented by changing one variable at a time then noting its effect on the yields, operation and product quality. The key parameters for DCC operation: Feed stock H-content. Reactor temperature. Space velocity. Hydrocarbon partial pressure. Naphtha/C4 recycle. Pentasil zeolite content. There are two types of variables: independent and dependent. Dependent Variables: Regenerator temperature. Catalyst circulation rate. Conversion/yield. Air requirement. Independent Variables: Reactor temperature. Feed pre heat temperature. Recycle rate. Fresh catalyst activity/selection. Fresh feed rate and its quality. Reactor level. As in FCC, higher temperature increases the conversion, coke and decreases the Gasoline substantially. In DCC, the effect of higher temperature on propylene yield is more pronounced thanks to the dense bed, higher temperature rises the aromatic content of Gasoline at the expense of paraffins and olefins resulting in higher octanes. Fig 2. Flow diagram of FCC unit Fig 3. FCC unit PROCESS DESCRIPTION The Shaw DCC incorporates a one-stage catalyst regeneration system, a unique combustion air distribution system, an innovative feed injection system, an efficient riser termination, and proprietary catalyst stripping technology. This proven process eliminates or greatly reduces many constraints of other configurations and offers maximum flexibility for converting reduced crudes, and mixtures of gas oils and vacuum resids. The Shaw DCC process unit consists of a feed injection system, one reactor-riser, a mushroom-type distributor as the riser termination device, reactor / stripper vessel, one catalyst regenerator, catalyst transfer lines, and control systems. Reaction System One reactor-riser is utilized in this design. The reactor-riser has several levels of feed and recycle injection in order to optimize the process for propylene production. At the base of the riser, a C4-Recycle distributor serves the dual purpose of injecting mixed C4 recycle and helping the lift/fluidize the catalyst in the riser. Also, at the base of the injector is a single Light Cat Naphtha (LCN) recycle injector. Along the riser are six fresh oil feed injectors, two LCN recycle injectors, two mixed C4 recycle injectors, eight riser steam injectors, two slurries recycle injectors, and one mushroom type termination device for effective catalyst/product vapor distribution. Control systems on the reactor-riser will allow control of the reactor temperature. The reactor-riser is designed to rapidly and intimately mix the hot regenerated catalyst with liquid feedstocks. At the base of the riser, recycle injection points are available for LCN and mixed C4 recycles. There is operational flexibility to send the recycles to the bottom of the riser, to the feed injection zone, or any combination of the two. This will allow online optimization of the production of propylene as well as other valuable liquid products. If no recycle is sent to the LCN injector, it will be purged with steam. If no mixed C4 recycle is sent to the base of the riser, the distributor will be fed steam in accordance with the rates given in the Operating Guidelines. Main feed is pumped to the feed zone of the reactor-riser and divided equally between six Shaw patented feed injectors. This feed has been preheated by hot slurry pump around in the gas plant and a feed preheating furnace to a temperature of 332°C. Once preheated, the feed is finely atomized and mixed with dispersion steam in the feed injectors and introduced into the reactor-riser. Small droplets of feed contact hot regenerated catalyst and vaporize immediately. The vaporized oil intimately mixes with the catalyst particles and cracks into lighter, more valuable products along with slurry oil, coke, and gas. In addition to the main feed, recycled LCN and mixed C4 recycle from the USGP can be sprayed into the reactor-riser at the same elevation as the fresh feed injection. Product vapours, dispersion steam, and small amounts of regenerator inert gases travel up the reactor-riser carrying the catalyst with it. Residence time in the reactor-riser is approximately two seconds at design conditions. The specially designed feed injection systems ensure the reaction is carried out efficiently. Fresh Feed Preheat Feed to the DCC unit is a combination of straight run VGO and HCGO. Feed is and slurry pump around as discussed in section of this document. The feed is then further preheated to a temperature of 332°C in the Fresh Feed Preheater before entering the reactor-riser. The feed temperature is adjusted by controlling the firing rate of the fired heater. Reaction System - Feed The reactor-riser injection systems for this project consist of fresh feed, mixed C4 recycle, light cat naphtha (LCN) recycle, and slurry recycle oil. Superheated medium pressure steam at 10 kg/cm²g and 250ºC is used as dispersion steam and to purge the injectors when no oil is flowing. Preheat temperature and regenerated catalyst temperatures are used to optimize the catalyst to oil ratio. A flow controller regulates the total feed to the unit with flow to each feed injector adjusted by hand-controlled globe valves. The feed should be split evenly between the feed injectors as observed by individual flow indicators. Pressures at each feed injector should be monitored as a verification of flow and an indication of injector condition. Dispersion steam is supplied to each feed injector to promote atomization and vaporization of the feed. The total dispersion steam is flow controlled while hand-controlled globe valves are used to balance the flow between each injector. Upon emergency shutdown, the dispersion steam and riser steam flows will clear the reactor-riser of oil and catalyst, preventing catalyst slumping in the reactor-riser. During low feed rate operations (less than 60% of design rates), the oil feed should be taken out of two opposing feed injectors and operation continued with the four remaining injectors. This action ensures adequate atomization at lower charge rates. Purge steam flow is required in the idle feed injectors at all times to keep them clear. LCN at a rate of 10 wt.% of fresh feed is recycled to the converter section from the naphtha splitter in the USGP and is injected into the riser through two non-proprietary injection nozzles and/or into the bottom of the riser through one non-proprietary injector. Mixed C4recycle at a rate of 5 wt.% of fresh feed is injected through two non-proprietary injection nozzles along the riser and/or one non-proprietary distributor at the base of the riser. At any time recycle is not being sent to these injectors/distributors, they should be purged with steam. Light naphtha and mixed C4 injection to the riser is required to maximize production of propylene without significantly increasing dry gas yield. The light naphtha and mixed C4 recycle are cracked to propylene and other products similar to those of the cracked feed. The injected recycle streams also increase the cat-to-oil ratio which promotes deeper cracking of the feed into light hydrocarbon products. LCN and mixed C4 recycles can be injected at the same elevation as the feed, resulting in selective conversion, as the hot regenerated catalyst density is optimal for contact with the fresh feed. No atomizing steam is required in the LCN or mixed C4 recycles injectors. A small steam purge is provided continuously as a precaution against catalyst backflow upon discontinuation of recycle flow to any of the injectors. Riser steam is injected between the fresh feed and slurry recycle injection zones through eight steam injection nozzles at two separate elevations (four injectors per location). This DCC Converter design requires steam rate of 25 wt.% of the total feed. At these steam rates and normal reactor operating pressures around 0.8 kg/cm²g, optimal hydrocarbon partial pressures are achieved for propylene production. Riser steam supplements feed dispersion steam, stripping steam, and other reactor/riser steam to provide the required total steam amounts. Slurry recycle is required, at a rate of 10 wt.% of fresh feed, to maintain an optimal converter heat balance. Because coke is major slurry recycle product, slurry recycle is used to increase the unit coke. Slurry recycle is injected just at the top of the riser through two non-proprietary injection nozzles. Dispersion steam is also injected at approximately 1 wt.% of slurry. A continuous small steam purge to each slurry injector is provided as a precaution against catalyst backflow if slurry flow is discontinued. There is also an option to recycle this slurry directly to the reactor/stripper. When there is no oil flow to any of these injectors, they are to be purged with medium pressure steam. Reaction System - Riser/Reactor The sensible heat, heat of vaporization, and heat of reaction required by the feed are supplied by the hot regenerated catalyst. Reactor temperature is regulated by controlling the amount of regenerated catalyst admitted to the riser through the Regenerated Catalyst Slide Valve (RCSV). The regenerated catalyst at the bottom wye section may cause turbulence and uneven catalyst flow patterns. Therefore, a high-density zone is provided to absorb shocks and stabilize the catalyst flow during the transition to upward flow. The straight section below the feed injectors serves as a reverse seal preventing oil flow reversal. Mixed C4 and LCN recycles to the bottom of the riser serve the dual purpose of introducing recycles where the catalyst is hottest as well as helping transition the catalyst flow up the riser. This, combined with fluidization steam in the 45-degree wye section, provides even catalyst flow as the catalyst reaches the feed injection section. The cracking reactions start during the two second contact time in the reactor-riser as the reaction mixture accelerates towards the riser termination device. Catalyst and hydrocarbon/steam vapor are dispersed using a mushroom distributor at the top of the reactor-riser. Efficient dispersion is necessary to encourage the continuation of reactions in the fluidized reactor bed which yield large amounts of olefins (propylene) at the expense of gasoline. The vapours and entrained catalyst pass through fifteen (15) high efficiency two-stage cyclones for separation of catalyst from products, thus minimizing the amount of catalyst lost to the main fractionator. Inertial effects force the catalyst particles to the cyclone wall and downward toward the cyclone dip leg. The cracked hydrocarbons and steam along with small amounts of entrained catalyst leave the cyclones through the gas tube where ducting directs flow into the reactor overhead lines. The small amount of catalyst contained in the product vapours is carried away from the fractionator in the bottom slurry oil which is then recycled to extinction back to the riser. The primary and secondary cyclone dip legs terminate below the catalyst bed level and have partially shrouded trickle valves to ensure a positive seal. Proper reactor bed level is essential for smooth operation of the unit and for maintaining the desired conversion. Reactor pressure "floats on" the main fractionator pressure and is not directly controlled at the converter section. A pressure control at the suction of the wet gas compressor provides for steady operating pressure of the reaction system. Differential pressure of the reactor and regenerator is controlled by the Flue Gas Slide Valve (FGSV) at the outlet of the regenerator. Superheated MP steam is introduced in the dome of the reactor through a steam ring to prevent stagnant reactor vapours in the top of the vessel. The dome steam ring displaces the volume of stagnant vapor and encourages vapor flow to the inlet of the cyclones. To prevent coke formation as a result of wet steam and hydrocarbon condensation, the steam is superheated to the reaction temperature by hot vapours in the reactor. This is accomplished by heat transfer through a steam pipe inside the reactor. Reaction System - Stripper The spent catalyst is steam stripped using a two-phase approach. The hot spent catalyst entering the reactor / stripper vessel from the reactor is contacted counter-currently with stripping steam, efficiently stripping the volatile hydrocarbon material. Without sufficient stripping, this valuable hydrocarbon between the catalyst particles is burned in the regenerator. The main stripping section consists of a vessel utilizing structured packing. Below the packing, the main steam ring, on flow control, fluidizes the catalyst bed, displaces the entrained hydrocarbons, and strips the adsorbed hydrocarbons from the catalyst before it enters the regeneration system. Coke remaining on the catalyst is burned off in the regenerator. A second steam distributor, a fluffing steam ring, is located in the bottom head of the stripper. This ring ensures proper catalyst fluidization as the catalyst enters the spent catalyst standpipe (SCSP). Based on the packed stripper design with proper residence time and steam to catalyst ratio, the hydrogen on coke leaving the stripper will be approximately 6 wt.%. The split of steam between the main stripping ring and the fluffing steam ring is shown on the PFD and associated Stream Summary. Typical stripping steam ring is 2.0 kg of steam per tonne of circulating catalyst. Reaction System - Spent Catalyst Transfer The steam stripped catalyst flows down the slanted spent catalyst standpipe and through the Spent Catalyst Slide Valve (SCSV). Aeration steam is added to the standpipe to maintain proper density and fluid characteristics of the spent catalyst. The SCSV controls the level in the stripper by regulating the flow of spent catalyst from the stripper. Spent catalyst flows to the Regenerator with the aid of fluidization air introduced along the bottom of the standpipe. Careful operation of the standpipes ensures proper head build-up and smooth catalyst flow. Shaw's spent catalyst distributor at the exit of the standpipe is a bathtub design that ensures the entering coke-laden catalyst is evenly spread across the regenerator dense phase over the combustion air rings. CATALYST REGENERATION SECTION The regenerator operates in a full combustion mode with approximately 2% excess oxygen. The heat of combustion released by the burning coke heats the catalyst and will supply the heat required for the reactor system. Regeneration System - Air Blower and Air Heater Combustion air for the process is supplied by an axial air blower driven by a high pressure superheated condensing steam turbine. The primary control of an axial blower is rotational speed of the turbine. The steam supply to the turbine can be throttled for air flow control/compressor speed and is exhausted through the turbine. Atmospheric air is introduced to the air blower through an intake filter. The blower air is distributed to a header system serving combustion air to the regenerator rings, spent catalyst distributor, and auxiliary air to the catalyst hopper area as required. A low pressure drop check valve in the blower discharge line prevents back-flow of catalyst upon blower shut-down. Blower surging is prevented by venting air using a sophisticated anti-surge controller. Combustion air to the regenerator is flow-controlled. Low air flow to the regenerator will trigger the emergency shutdown circuit during blower failure. Combustion air to the regenerator is split between three air rings with the flow to each ring adjusted by manual control of butterfly valves. The outer, middle, and inner air rings are designed to handle approximately 48%, 38%, and 14 wt.% of the combustion air to the regenerator, respectively. Since the air blower discharge pressure is set by the inner air rings, pressure drop is minimized in these lines. Hand valves are throttled slightly to balance flow to the rings. A direct gas fired air heater is located in the combustion air lines to the outer and middle combustion air rings. The air heater is used only during start-up to heat the catalyst and DCC equipment. Instrumentation is provided to prevent equipment overheating during air heater operation and a flame-safety package is included to prevent unsafe conditions during burner operation. Torch oil (fresh feed) is used to further heat the process during start-up activities to its operating temperatures. Torch oil (on flow control) is pumped to four injectors which spray into the air-preheated catalyst bed in the regenerator. Regeneration System - Regenerator Spent catalyst containing coke flows out of the standpipe and into the bathtub distributor. The distributor deposits the catalyst evenly across the top of the regenerator catalyst bed. The combustion air rings fluidize the dense phase of the regenerator while homogeneously dispersing the air throughout the bottom of the catalyst bed. The coke is burned by combustion air from the air rings. The regenerator operates in a counter-current mode (air enters at the bottom while spent catalyst enters from the top). Excess oxygen is maintained by flow controlling the combustion air for efficient and complete combustion. Eighteen (18) sets of two-stage cyclones separate entrained catalyst from the flue gas exiting the regenerator. The primary cyclone dip legs terminate below the catalyst bed level and have splash plates. The secondary cyclone dip legs also terminate below the bed level and have partially shrouded trickle valves to ensure a positive seal. The flue gas also passes through a tertiary separation system, followed by a double-disc slide valve and orifice chamber system to reduce the pressure. Differential reactor / regenerator pressure is modulated by controlling the double disc flue gas valve upstream of the orifice chamber. The level in the regenerator is not directly controlled but depends on the catalyst inventory required to supply the RCSP. Periodic catalyst withdrawals (or additions) are necessary to maintain the level in the normal operating region. Regeneration System - Regenerated Catalyst Transfer The hot regenerated catalyst flows from the regenerator into a catalyst standpipe and then into a catalyst slide valve. At the bottom of the Regenerated Catalyst Standpipe (RCSP), the Regenerated Catalyst Slide Valve (RCSV) controls the flow of hot catalyst. The reactor temperature sets the position of the RCSV which regulates the flow of catalyst. Catalyst continues moving down the 45-degree slanted wye section to the riser base where the catalyst transition begins the upward flow toward the fresh feed injectors. Fluidization steam taps are located along the lateral wye section to aid catalyst movement into the reactor-riser. Prior to the fresh feed injectors, a high catalyst density zone must be provided to absorb shocks and stabilize the catalyst flow. The straight section below the feed injectors serves as a reverse seal preventing oil flow reversal. Mixed C4 and LCN recycles to the bottom of the riser serve the dual purpose of introducing recycles where the catalyst is hottest as well as helping transition the catalyst flow up the riser. This, combined with fluidization steam in the 45-degree wye section, provides even catalyst flow as the catalyst reaches the feed injection section. REGENERATOR FLUE GAS SECTION The regenerator flue gas passes through the tertiary separator to further remove catalyst fines achieving a catalyst concentration of less than 50mg/Nm³. The flue gas then flows to a double disc flue gas slide valve (FGSV) and multi-plate Flue Gas Orifice Chamber for pressure let-down which allows control of the reactor/regenerator differential pressure. The slide valve and orifice chamber system are designed to reduce the flue gas pressure. This orifice chamber is refractory lined to allow a design using carbon steel shell construction. The first and second orifice plates are also refractory lined. As the flue gas passes through each plate, the pressure is gradually reduced to the desired outlet pressure. Since the orifice chamber's pressure reduction is directly affected by the flue gas volumetric flow rate, the slide valve must have a wide pressure reduction ability. A small portion of the regenerator flue gases exit the third stage separator with the recovered catalyst fines via the under-flow line. The catalyst rich flue gas stream flows to the fourth stage separator. The gases from the fourth stage separator blend in with the main flue gas downstream of the orifice chamber. Catalyst fines are recovered from the fourth stage separator in an unloading vessel before disposal. The flue gas then passes through the Flue Gas Cooler where the flue gas thermal energy is recovered by generating high pressure superheated steam. The flue gas is cooled comfortably above the sulphur dew point in the flue gas stream to prevent condensation of the sulphur. For this design, the temperature approach for the high temperature boiler feed water sets the outlet flue gas temperature. The level in the steam drum is maintained by controlling the flow of preheated boiler feed water from the USGP to the economizer. These cooled flue gases are directed downstream to the stack. Maximum particulates in the flue gases released to the atmosphere are 50 mg/Nm³. CHAPTER 4: Sulphur Unit Fig 4. Sulphur block Sulphur Recovery Unit (SRU) Block Objective: To Convert Sulphur Species, present in Feed gas streams i.e. Acid gas from ARU (522), Sour Gas from SWS Unit (521) and Sour Gases from Degassing section of VGOHDT Unit (509) to recover it as Elemental Sulphur Product. Detailed Engineering: Engineers India Limited. Licensor: Prosernat. So, total Sulphur block in GGSR refinery can be divided to three parts Sour water stripper units. Amine regeneration unit. Sulphur recovery unit. Brief Process Chemistry: What is Claus Reaction? “When two moles of Hydrogen Sulphide (H2S) react with one mole of Sulphur Dioxide (SO2) to give Elemental Sulphur in presence of Alumina Catalyst, the reaction is called Claus Reaction” H2S + 3/2O2 SO2+ H2O 1/3rd of total H2S in feed gas is burned to SO2, this SO2 reacts with remaining H2S to give elemental Sulphur in Claus Reactor 2H2S + SO2 3/2 S2 + 2H2O Overall Reaction H2S + 1/2 O2 1/n Sn + H2O Side Reactions: CS2 & COS Hydrolysis Reactions: COS + H2O = H2S + CO2 CS2 + 2H2O = 2H2S + CO2 The ammonia contained in the acid gases is oxidised completely in the thermal reactor and decomposed at high temperature according to the following reaction 2NH3 + 3/2 O2 N2 + 3H2O Fig 5. Major sections in SRU Claus Section: Thermal & Catalytic Stage H2S in feed is converted to Sulphur and sent for degasification Sultimate Section: Hydrogenation, Quench & Absorption Stage “S” species in Tail gas from Claus Section are hydrogenated and absorbed in lean Solvent Regeneration Section Solvent is regenerated and H2S rich gas is recycled to Claus Section Incineration Section Tail Gas from Sultimate absorber are incinerated Degasification Section Dissolved H2S is removed, Product “S” is transferred to Sulphur Yard Claus Section: Thermal Stage The thermal stage consists of the main burner, reaction furnace, waste heat boiler and first sulfur condenser. In the main burner the sour gas feed is burnt sub-stoichiometrically (shortage of oxygen) with air. Thereby, the following main reaction takes place: H2S + 1½ O2 = SO2 + H2O + heat One-third of the H2S present in the sour gas feed is combusted in this way, whereas the several feed gas impurities such as ammonia and hydrocarbons, are burnt completely to carbon dioxide, nitrogen and water. The major part of the remaining two-thirds of H2S is thermally converted into sulfur by the reaction with SO2 according to: 2 H2S + SO2 = 1½ S2 + 2 H2O – heat Claus Section: Catalytic Stage In the two downstream catalytic reaction stages the Claus equilibrium reaction is continued at lower temperature by means of a special catalyst:  2 H2S + SO2 = 3/x Sx + 2 H2O + heat Catalytic Hydrogenation Stage In the SCOT reactor virtually, all sulfur compounds present in the non-incinerated Claus tail gas are converted to H2S by hydrogen (H2) over a cobalt/molybdenum catalyst (on alumina support) at a reactor inlet temperature of 220 - 240°C. For sulfur dioxide (SO2) and elementary sulfur (S8) the respective reactions are: SO2 + 3H2 = H2S + 2H2O + heat S8 + 8H2 = 8H2S + heat Quench stage The process gas leaving the SCOT reactor is cooled to 42°C by direct contact cooling with a counter-current flow of water in quench column. To prevent corrosion (when the pH is less than 6) provisions are available for NH3 injection into the circulating water stream. The overhead gas from the quench column is routed to SCOT absorber. Absorption Stage The process gas is contacted counter-currently with a lean 30%wt MDEA solution supplied to the top of the column by means of flow control. The lean solvent is supplied from CRU. Virtually all H2S is removed from the gas. The treated gas ex absorber (so-called SCOT off-gas) is sent to the existing incinerator of Base SRU. Regeneration stage The loaded MDEA (rich solvent) is routed to the regeneration section, in which the H2S and CO2 are stripped from the solvent by increasing the temperature. Acid gas from the top of the Regenerator is sent back to Claus Section of Base SRU. Lean Solvent from the bottom of the Regenerator is sent to Sultimate section Absorbers. Incineration section The tail gas resulting from the SCOT section (or in case of SCOT bypass, Claus tail gas) and vent gas from the sulfur degassing still contain traces of sulfur compounds. These sulfur compounds are oxidized in the incinerator at elevated temperatures. The main reactions are: H2S + 3/2 O2 SO2 + H2O 1/x Sx + O2 SO2 Degassing section The sulfur produced in the SRU contains about 300 ppm wt. H2S, partly chemically bound as polysulfides (H2Sx) and partly physically dissolved. Degassing process reduces the H2S content to less than 10 ppm wt. Degassing is obtained by injecting air via sparges in the liquid sulfur, thereby partly stripping the dissolved H2S from the sulfur and partly oxidizing it to elemental sulfur. Furthermore, the removal of H2S from the sulfur promotes the decomposition of the polysulfides into H2S and sulfur. H2Sx H2S + Sx-1 H2S + ½ O2 1/x Sx + H2O SWS Unit-Process Description Sour water streams which are loaded with high quantities of ammonia and H2S (say from Hydro treater) are normally treated in a two-stage stripper unit i.e. H2S and ammonia are recovered in two separate columns. Sour water which are lean in H2S and NH3 are treated in single stage stripper unit. Steam reboiler stripping is most widely accepted industry practice. Sour water storage tank at a capacity of 5000 m3 is provided to get continuous feed to stripper. Sour water from Various refinery units will be received in the surge drum V-101, this surge drum is a three-phase separator (V-L-L), hydrocarbons are flashed and routed to acid gas flare. Sour water from surge drum is sent to storage tank by pressure diff, from there it is pumped to Sour water stripper via Feed/Bottom Exchanger. In Feed bottom Exchanger preheats the sour water and sent to SWS stripper. In stripper Temperature is maintained by applying MP steam to Kettle type reboiler. Pump around is provided in order to minimize water vapor escape from Overhead gas to SRU. Stripper top pressure maintains at 0.9 and kg/cm2. Stripped water containing H2S and NH3 less than 50 ppmw is pumped under level control. A water-cooled exchanger is provided to cool the stripped water to the required battery limit temperature. Major equipment: Sour Water Surge Drum Purpose: Removal of flashed gases (i.e. lighter hydrocarbons, H2S and ammonia) Removal of Liquid Hydrocarbons from sour water. Feed bottoms exchanger Purpose: Heat recovery. Increased feed temperature. Reduction in reboiler duty. Decrease in stripped water cooler duty. Stripper Purpose: Stripping of H2S & NH3 from sour water Single stage column contains 40 trays In Two stage column-1st stage column contains 40 trays and 2nd Stage contains 38 trays, Type of trays is Valve Tray. Product Specification-SWS I & II Stripped water from SWS I & II shall not contain more than 50 ppmw for H2S and 50 ppmw for NH3 Sour gas quality from SWS-1 shall be consistent with stripped water quality Sour gas (H2S rich) from 1st stripper of SWS-II shall contain most of the H2S coming with feed sour water, but not less than 93.0wt% of the total H2S present in the feed. Ammonia content of 1st stripper shall be less than 1000 ppmw Sour gas NH3 rich from 2nd stripper shall be consistent with stripped water quality A. Sour water stripper units SWS Unit -Objective: The process objective of SWS Unit is to process Sour water streams generated in refinery process units CDU/VDU, DCU, Flare KOD, ARU, SRU-TGTU, HGU and DCCU for Single Stage Stripper. Sour Water streams from VGOHDT and NHTU for Two stage stripper for removal of H2S and NH3. Licensor: Engineers India Ltd. Detailed Engineering Contractor: Toyo Engineering India Limited. Capacity: Train -1: Unit No-520 Single Stage- Capacity 294 TPH Train -2: Unit No-521 Two Stage - Capacity 104 TPH Fig 6. BFD of SWS-1 Fig 7. BFD of SWS-2 B. Amine regeneration unit ARU Objective: To Regenerate the Rich Amine streams received from Vacuum Gas Oil Hydrotreater and Diesel Hydrotreater (VGOHDT), Fuel Gas ATU, LPG ATU and DCU. Lean amine, which is obtained after stripping H2S from rich amine, is used to absorb H2S in Off-Gas from various plants. Block flow diagram of ARU: Fig 8. BFD of ARU Chemicals used in Amine Regeneration Unit Methyl Di Ethanolamine -MDEA 40% wt. Granular Carbon. Antifoam. Corrosion Inhibitor. ARU Process description: Rich Amine Flash Drum (RAFD) RAFD is meant for separating lighter and Heavier Hydrocarbons from Rich Amine. Hydrocarbon free rich amine then flows to regenerator for regeneration. Light Hydrocarbons that are flashed in RAFD sent to Acid gas flare header. Flash Drum pressure is controlled at 0.8 kg/cm2. Heavier Hydrocarbons are separated as slop oil and sent in OWS. Amine Regenerator Rich amine is pumped from RAFD to Regenerator at 20th tray via Lean/Rich exchanger, where it exchanges heat with Lean amine coming from bottom of the regenerator. Reflux water enters at 24th tray and descends down, basically to prevent MDEA losses into the overhead and ensures complete removal of H2S. Kettle type reboiler is provided to supply vapor to the regenerator, by applying MP steam via De-super heater. The vapor and Rich amine contacts counter currently to strip H2S. Amine Regenerator operates at top pressure 0.9 kg/cm2 and bottom. Temperature maintained at 1270C. Lean Amine from bottom passes through Lean/Rich exchanger cooled to 840c and further cooled to 400c by Lean air coolers. Lean amine from both trains combinedly send to Storage tank From there it is pumped to Lean amine Absorbers of DCU, VGOHDT, DHDT, FGATU and LPG ATU. Sulphur recovery unit Why do we need a Sulphur Recovery Unit? Increasing demand for environment friendly fuels (low Sulphur). Use of High Sulphur and heavier Crudes in future. Tightening of emission standards by Govt./regulatory bodies. Objective of a Sulphur Recovery Unit “Objective of Sulphur Recovery Unit is to convert H2S to elemental Sulphur” General Description How does the feed for SRU generate? During initial stages of high-Sulphur crude oil processing, process and fuel gases that contain significant amounts of H2S are treated in a lean amine solution to absorb the Sulphide components. The H2S is subsequently stripped to provide a feed gas to a Sulphur recovery Unit Similarly, H2S is stripped out from sour water generated in the various units of refinery and makes another part of feed to Sulphur Recovery Unit. Amine Acid Gas (AAG): 92-96% H2S Sour Water Stripping (SWS) Gas: 45-55% H2S Fig 9. BFD of Sulphur removal The Sulphur Recovery Unit includes Claus, Degassing, Tail Gas Treatment and Incineration facilities. A portion of the H2S in the feed gas is oxidized to Sulphur dioxide (SO2) and water in a reaction furnace with air. After quenching the hot gases to generate steam in Waste Heat Boiler, the cooler gases are passed through a Sulphur condenser to recover liquid Sulphur and the gases are reheated. The remaining non-combusted fraction of the feed gas H2S reacts with SO2 in catalytic converters (e.g., using Alumina or Titanium Catalyst) to form elemental Sulphur, water and heat. Since each catalytic stage in the Claus plant recovers only a portion of the incoming Sulphur, normally two or more stages are used to achieve up to 97% overall Sulphur recovery. Tail gas from the final unit contains a variety of Sulphur compounds and normally requires further tail gas cleanup to obtain higher recovery. Process flow diagram: Fig 10. PFD of Sulphur recovery CONCLUSION Overall, this internship was a useful experience. I have gained new knowledge, skills and met many new people. I achieved several of my learning goals, however for some the conditions did not permit. The internship was also good to find out what my strengths and weaknesses are. This helped me to define what skills and knowledge I must improve in the coming time. It would also be better if I can present and express myself more confidently. At last, this internship has given me new insights, wonderful memories and motivation to pursue a career in Chemical Engineering. 7 2