A guide of refinery process tài liệu hay tổng hợp tất cả các quá trình chế biến lọc hóa dầu

Refinery Process Executive Summary The refining process depends on the chemical processes of distillation (separating liquids by their different boiling points) and catalysis (which speeds up reaction rates), and uses the principles of chemical equilibria Chemical equilibrium exists when the reactants in a reaction are producing products, but those products are being recombined again into reactants By altering the reaction conditions the amount of either products or reactants can be increased Refining is carried out in three main steps Step - Separation The oil is separated into its constituents by distillation, and some of these components (such as the refinery gas) are further separated with chemical reactions and by using solvents which dissolve one component of a mixture significantly better than another Step - Conversion The various hydrocarbons produced are then chemically altered to make them more suitable for their intended purpose For example, naphthas are "reformed" from paraffins and naphthenes into aromatics These reactions often use catalysis, and so sulfur is removed from the hydrocarbons before they are reacted, as it would 'poison' the catalysts used The chemical equilibria are also manipulated to ensure a maximum yield of the desired product Step3 - Purification The hydrogen sulfide gas which was extracted from the refinery gas in Step is converted to sulfur, which is sold in liquid form to fertiliser manufacturers The refinery produces a range of petroleum products Petrol Petrol (motor gasoline) is made of cyclic compounds known as naphthas It is made in two grades: Regular (91 octane) and Super or Premium (96 octane), both for spark ignition engines These are later blended with other additives by the respective petrol companies Jet fuel/Dual purpose kerosene The bulk of the refinery produced kerosene is high quality aviation turbine fuel (Avtur) used by the jet engines of the domestic and international airlines Some kerosene is used for heating and cooking Diesel Oil This is less volatile than gasoline and is used mainly in compression ignition engines, in road vehicles, agricultural tractors, locomotives, small boats and stationary engines Some diesel oil (also known as gas oil) is used for domestic heating Fuel Oils A number of grades of fuel oil are produced from blending Lighter grades are used for the larger, lower speed compression engines (marine types) and heavier grades are for boilers and as power station fuel Bitumen This is best known as a covering on roads and airfield runways, but is also used in industry as a waterproofing material Sulfur Sulfur is removed from the crude during processing and used in liquid form in the manufacture of fertilisers Prepared By- Tendering Estimation Dept Essar Constructions India Ltd REFINERY PROCESS FLOW CHART ARU Amine Recovery Unit Fuel Gas Light Gas Refinery Fuel/Fuel Gas Sr SRU Sulphur Recover Unit H2S Gas Processing Sulphur Propane LPG Butane Merox Unit H2 Desalted Crude ISOM Light Naptha Isomerisation NHTU Naptha Hydrotreate Unit Heavy Naptha Naptha Gasolines Blending CCR Continuos Catalytic Reformer Super Premium Unleaded Premiun unleaded Unleaded Supporting Units H2S to SRU Kerosene Jet Fuel ATF HDTATF Hydrotreater Diesel Oil DHDT Diesel Hydrotreater ATF MEROX Aviation Turbine Fuel Merox Jet Fuel/ Kerosene Sour Water (From CDU, VDU, HDS, FCCu, Etc) H2S Diesel Diesel Fuel Stripped Water Gas Oil Propane Poly Unit Reduced Crude ETP Butane PRU Light Vaccume Gas Oil VGO-HDT Vaccume Gas Oil Hydotreater (FCCU) Fluid Catalytic Cracking Units Alkylation Unit CO2 Propylene Propylene C3/C4 To Hydrocracker & Hydrotreater Diesel Heavy Vaccume Gas Oil I Butane Hrdrocracker Gasoline Neddle Coke Unit Vaccume Residuel DCU- Delayed Coker Unit Coker Naptha to CCR PREPARED BY:- TENDERING ESTIMATION TEAM Natural Gas Steam Premier Coke PREPARED BY:- Coker Gas Oil to FCCU Petroleum Coke Bitumen Blowing H2 HMU- Hydrogen Manufacturing Unit (VDU) Vaccume Distillation Unit Heating Light Naptha (CDU)Crude Distillation Unit / Atmospheric Distillation Uni t Desalter H2 NHTU Naptha Hydrotreate Unit Units Name AGS- Air Generation System AGU- Acid Generation Unit ARU- Amine Recovery Unit ATF Merox- Aviation Turbine Fuel Merox ATF-HDT- Aviation Turbine Fuel Hydrotreater CCR- Continuous Catalytic Reformer CDU- Crude Distillation Unit DCU-Delayed Crocker Unit Desal/Demin Plant DHDT- Diesel Hydrotreating ETP- Effluent Treatment Plant FCCU- Fluid Catalytic Cracker Unit GMU- Gasoline Merox Unit HMU- Hydrogen Manufacturing Unit NCU-Needle Coke Unit NHT- Naptha Hydrotreater PRU- Propylene Recovery Unit SGU-Saturated Gas Unit SRU- Sulphur Recoveru Unit SS&H- Sulphur Storage & Handling SWS- Sour Water Stripper UGS- Unsaturated Gas Seperation Unit VBS- Visbreaker Unit VDU- Vaccume Distillation Unit VGO-HDT- Vaccume Gas Hydrotreater sws- Sour Water Stripper Crude Oil Storage Tank 10 11 12 13 14 16 17 18 19 20 21 22 23 24 25 26 TENDERING & ESTIMATION TEAM ESSAR CONSTRUCTIONS INDIA LTD KURLA, MUMBAI BITUMEN (Road, Roofing, waterproofing) ESSAR CONSTRUCTIONS INDIA LTD MUMBAI Crude Oil Storage Crude Oil Storage In almost all cases, crude oils have no inherent value without petroleum refining processes to convert them into marketable products Crude oil is a complex mixture of hydrocarbons that also contains sulfur, nitrogen, heavy metals and salts Most of these contaminants must be removed in part or total during the refining process The hydrocarbons that make up crude oil have boiling points from less than 60˚F to greater than 1200˚F (60-650˚C) Crude oil varies in sulfur content Higher sulfur crude oil is more corrosive than lower sulfur crude oils In order to process higher sulfur crude oils, equipment must be built from more expensive alloys to provide higher corrosion resistance Many refineries are not able to process crude oils with high sulfur The American Petroleum Institute (API) has developed a characterization for the density of crude oils: ˚API = (141.5/Specific Gravity@60˚F) -131.5 When comparing crude oils, the crude oil with the higher API will be easier to refine than one with a lower API Crude oil is delivered to a refinery by marine tanker, barge, pipeline, trucks and rail The level of BS&W (bituminous sediment and water) is monitored to avoid high levels of water and solids Water separates from crude oil as it sits in tanks waiting to be refined This water is generally drained to waste water treatment just prior to processing Process Chart Desalting All crude oil contains salt, predominantly chlorides Chloride salts can combine with water to form hydrochloric acid in atmospheric distillation unit overhead systems causing significant equipment damage and processing upsets Chlorides and other salts will also deposit on heat exchanger surfaces reducing energy efficiency and increasing equipment repairs and cleaning Salt must be removed from crude oil prior to processing Crude oil is pumped from storage tanks and preheated by exchanging heat with atmospheric distillation product streams to approximately 250˚F (120˚C) Inorganic salts are removed by emulsifying crude oil with water and separating them in a desalter Salts are dissolved in water and brine is removed using an electrostatic field and sent to the waste water treatment Process Chart Atmosheric Distillation Unit/ Crude Distillation Unit CDU Initial crude oil separation is accomplished by creating a temperature and pressure profile across a tower to enable different composition throughout the tower Desalted crude oil is preheated to a temperature of 500-550˚F (260-290˚C) through heat exchange with distillation products, internal recycle streams and tower bottoms liquid Finally, the crude oil is heated to approximately 750˚F (400˚C) in a fired heater and fed to the atmospheric distillation tower Distillation concentrates lower boiling point material in the top of the distillation tower and higher boiling point material in the bottom Progressively higher boiling point material is present between the top and bottom of the tower Heat is added to the bottom of the tower using a reboiler that vaporizes part of the tower bottom liquid and returns it to the tower Heat is removed from the top of the tower through an overhead condenser A portion of the condensed liquid is returned to the tower as reflux The continuous vaporization and condensation of material on each tray of the fractionation tower is what creates the separation of petroleum products within the tower The most common products of atmospheric distillation are fuel gas, naphtha, kerosene (including jet fuel), diesel fuel, gas oil and resid Atmospheric distillation units run at a pressure slightly above atmospheric in the overhead accumulator Temperatures above approximately 750˚F (400˚C) are avoided to prevent thermal cracking of crude oil into light gases and coke With the exception of Coker units, the presence of coke in process units is undesirable because coke deposit fouls refining equipment and severely reduces process performance Vaccum Distillation Units Atmospheric resid is further fractionated in a Vacuum Distillation tower Products that exist as a liquid at atmospheric pressure will boil at a lower temperature when pressure is significantly reduced Absolute operating pressure in a Vacuum Tower can be reduced to 20 mm of mercury or less (atmospheric pressure is 760 mm Hg) In addition, superheated steam is injected with the feed and in the tower bottom to reduce hydrocarbon partial pressure to 10 mm of mercury or less Atmospheric resid is heated to approximately 750˚F (400˚C) in a fired heater and fed to the Vacuum Distillation tower where it is fractionated into light gas oil, heavy gas oil and vacuum resid Typical products and their true boiling points (TBP) from crude oil distillation (i.e., both atmospheric and vacuum tower products) are: Naptha HDS/ Hydrotreater Most catalytic reforming catalysts contain platinum as the active material Sulfur and nitrogen compounds will deactivate the catalyst and must be removed prior to catalytic reforming The Naphtha HDS unit uses a cobalt-molybdenum catalyst to remove sulfur by converting it to hydrogen sulfide that is removed with unreacted hydrogen Reactor conditions are relatively mild for Naphtha HDS at 400-500˚F (205-260˚C) and relatively moderate pressure 350-650 psi (25-45 bar) As coke deposits on the catalyst, reactor temperature must be raised Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement If required, the boiling range of the Catalytic Reforming charge stock can be changed by redistilling in the Naphtha HDS Often pentanes, hexanes and light naphtha are removed and sent directly to gasoline blending or pretreated in an Isomerization Unit prior to gasoline blending Kerosene HDS/ Hydrotreater Hydrotreating is a catalytic process to stabilize products and remove objectionable elements like sulfur, nitrogen and aromatics by reacting them with hydrogen Cobalt-molybdenum catalysts are used for desulphurization When nitrogen removal is required in addition to sulfur, nickel-molybdenum catalysts are used In some instances, aromatics saturation is pursued during the hydrotreating process in order to improve diesel fuel performance Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at moderately high pressures 500-1500 psi (35-100 bar) As coke deposits on the catalyst, reactor temperature must be raised Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement Hydrogen is combined with feed either before or after it has been heated to reaction temperature The combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where it flows downward over a bed of metal-oxide catalyst Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free metals Metals remain on the catalyst and other products leave with the oil-hydrogen steam Hydrogen is separated from oil in a product separator Hydrogen sulfide and light ends are stripped from the desulfurized product Hydrogen sulfide is sent to sour gas processing and water removed from the process is sent to sour water stripping prior to use as desalter water or discharge Diesel HDS/Hydrotreater Hydrotreating is a catalytic process to stabilize products and remove objectionable elements like sulfur, nitrogen and aromatics by reacting them with hydrogen Cobalt-molybdenum catalysts are used for desulphurization When nitrogen removal is required in addition to sulfur, nickel-molybdenum catalysts are used In some instances, aromatics saturation is pursued during the hydrotreating process in order to improve diesel fuel performance Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at moderately high pressures 500-1500 psi (35-100 bar) As coke deposits on the catalyst, reactor temperature must be raised Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement Hydrogen is combined with feed either before or after it has been heated to reaction temperature The combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where it flows downward over a bed of metal-oxide catalyst Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free metals Metals remain on the catalyst and other products leave with the oil-hydrogen steam Hydrogen is separated from oil in a product separator Hydrogen sulfide and light ends are stripped from the desulfurized product Hydrogen sulfide is sent to sour gas processing and water removed from the process is sent to sour water stripping prior to use as desalter water or discharge Gas Oil HDS Hydrotreating is a catalytic process to stabilize products and remove objectionable elements, particularly sulfur and nitrogen, by reacting them with hydrogen prior to feed to the FCC Unit Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at relatively high pressures up to 2000 psi (138 bar) depending on the level of reaction severity needed to meet product specification and the composition of the feedstock Hydrogen is combined with feed either before or after it has been heated to reaction temperature The combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where it flows downward over a bed of metal-oxide catalyst For desulphurization, the most common catalysts are cobaltmolybdenum When hydrodenitrofication (HDN) is desired in addition to desulfurization, nickelmolybdenum catalysts are recommended Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free metals Metals remain on the catalyst and other products leave with the oil-hydrogen steam Hydrogen is separated from oil and hydrogen sulfide and light end are stripped from the desulfurized product Hydrogen sulfide is sent to sour gas processing and water removed from the process is sent to sour water stripping prior to use as desalter water or discharge Isomerization Catalytic reforming has little effect on Light Straight Run gasoline (LSR), which is material in the C5 - 165˚F (74˚C) boiling range This fraction is removed from reformer feed Its octane number may be significantly improved by converting normal paraffins into their isomers in the Isomerization Unit Isomerization can result in a significant octane increase since n-pentane has a research octane number (RON) of 62 and iso-pentane has a RON of 92 Once through isomerization can increase LSR gasoline octane from 70 to around 82 RON Isomerization catalysts contain platinum and, like reforming, must have all sulfur removed Additionally, some catalysts require continuous additions of small amounts of organic chlorides to maintain activity Organic chlorides are converted to hydrochloric acid; therefore, Isomerization feed must be free of water to avoid serious corrosion problems Other catalysts use a molecular sieve base and are reported to tolerate water better Isomerization uses reaction temperatures of 300-400˚F (150-200˚C) at pressures of 250-400 psi (17-27 bar) For refineries that not have hydrocracking facilities to supply iso-butane for alkylation feed, iso-butane can be made from n-butane using isomerization Propylene Recovery Unit Alkylation Alkylation is a refining process that provides an economic outlet for very light olefins produced at the FCC and Coker Alkylation is the opposite of cracking The process takes small molecules and combines them into larger molecules with high octane and low vapor pressure characteristics In the Alkylation Unit, propylene, butylenes and sometimes pentylenes (also known as amylenes) are combined with iso-butane in the presence of a strong acid catalyst (either hydrofluoric (HF) or sulfuric acid) to form branched, saturated molecules Alkylate has an octane around 95 (R+M)/2 and low vapor pressure making it a valuable gasoline blending component particularly for premium grade products It contains no olefins, aromatics or sulfur Sulfuric Acid Alkylation runs at 35-60˚F (2-15˚C) to minimize polymerization reactions while HF Alkylation, which is less sensitive to polymerization reactions, runs at 70-100˚F (20-38˚C) Chilling or refrigeration is required to remove heat of reaction Alkylation products are distilled to remove propane, iso-butane and alkylate Sulfuric acid sludge must be removed and regenerated HF is neutralized with KOH, which may be regenerated and returned to the process Merox Treatment Technical Profile Merox is a process to sweeten products by extracting and/or converting mercaptan sulfur to less objectionable disulfides It is often used to treat products such as liquefied petroleum gases, naphtha, gasoline, kerosene, jet fuel and heating oils Hydrogen sulfide free feed is contacted with caustic in a counter-current extraction column Sweet product exits the column overhead and caustic/extracted mercaptans exit the column bottom as extract Air and possibly catalyst are mixed with extract and sent to an oxidation reactor where caustic is regenerated and mercaptans are converted to disulfides Disulfides are insoluble in water and can be removed in a product separator that vents excess air and gas for disposal or destruction and separates sulfide oil, which may be returned to the refining process, from regenerated caustic, which is returned to the extraction column Over time caustic will become spent and must be wasted to other refinery uses or to spent caustic destruction When removal of mercaptan sulfur is not required, "sweetening" may be applied to improve odor where mercaptan sulfur is converted to disulfide and carried out with the petroleum product For sweetening, dilute caustic is added to the product prior to air injection Combined feed enters a fixed bed reactor where a catalyst oxidizes mercaptan sulfur into disulfides Caustic is removed from the bottom of the reactor and wasted to the sewer or spent caustic treatment Sour Water Stripper Stripping steam and wash water in various refining operations is condensed and removed from overhead condensate accumulators or product separators This water contains impurities most notably sulfur compounds and ammonia Hydrogen sulfide and ammonia are removed in the sour water stripper By varying the pH of the feed solution, hydrogen sulfide may be removed for amine treatment and ammonia may be removed for reuse or neutralization in separate strippers Once stripped of contaminants, water is either reused for desalter water or discharged directly to waste water treatment facilities Sulfur Recovery The sulfur recovery process used in most refineries is a "Claus Unit" In general, the Claus Unit involves combusting one-third of the hydrogen sulfide (H2S) into SO2 and then reacting the SO2 with the remaining H2S in the presence of cobalt-molybdenum catalyst to form elemental sulfur The conversion chemistry is: 2H2H2S + O2 → SO2 + H2O (Combustion) H2S + SO2→ S + H2O (Conversion) Generally, multiple conversion reactors are required Conversion of 96-97% of the H2 to elemental sulfur is achievable in a Claus Unit If required for air quality, a Tail Gas Treater may be used to remove remaining H2S in the tail gas from the Sulfur Recovery process HMU Hydrogen manufacturing Unit The large consumption of hydrogen, particularly in the hydrocracker, has meant that the Essar refinery has its own hydrogen manufacturing unit The hydrogen is produced by converting hydrocarbons and steam into hydrogen, and produces CO and CO2 as byproducts The hydrocarbons (preferably light hydrocarbons and butane) are desulfurised and then undergo the steam reforming reaction over a nickel catalyst The reactions which occur during reforming are complex but can be simplified to the following equations: CnHm + nH2O → nCO + (( 2n + m )/2)H2 CO + H2O → CO2 + H2 The second reaction is commonly known as the water gas shift reaction The process of reforming can be split into three phases of preheating, reaction and superheating The overall reaction is strongly endothermic and the design of the HMU reformer is a careful optimisation between catalyst volume, furnace heat transfer surface and pressure drop In the preheating zone the steam/gas mixture is heated to the reaction temperature It is at the end of this zone that the highest temperatures are encountered The reforming reaction then starts at a temperature of about 700°C and, being endothermic, cools the process The final phase of the process, superheating and equilibrium adjustment, takes place in the region where the tube wall temperature rises again The CO2 in the hydrogen produced by reforming is removed by absorption (see purification below), but trace quantities of both CO and CO2 remain These are converted to methane (CH4) by passing the hydrogen stream through a methanator The reactions are highly exothermic and take place as follows: CO + 3H2 → CH4 + H2O CO2 + 4H2 → CH4 + 2H2O Finally, all produced hydrogen is cooled and sent to the Hydrocracker Gasoline Petroleum refineries produce a variety of components that are then used to blend refined products Product blending is a critical source of flexibility and profitability for refining operations Of great interest is the economic blending of gasoline Gasoline is not a single product Refiners blend hundreds of different specifications In addition to the different grades of gasoline we all see at the retail pump, gasoline is subject to different specifications based on country, geographic location, season, humidity, altitude, and environmental regulations This further complicates distribution systems with additional requirements for low sulfur, conventional, reformulated and oxygenated "boutique" blends Key to good gasoline performance is octane, vapor pressure (Reid Vapor Pressure - RVP) and distillation range of the blend Below is a table of octane, RVP and specific gravity blending values for some typical gasoline blending components: Component Iso-butane n-butane Iso-pentane n-pentane Iso-hexane LSR Isomerate Hydrocrackate Coker Naphtha FCC Gasoline Reformate, 94 RON Reformate, 100 RON Alkylate, C4 Alkylate, C5 The Gas Plant Light ends are hydrocarbons boiling at the lowest temperatures including methane, ethane, propane, butanes, and pentanes, which contain from one to five carbon atoms Light ends are fractionated in distillation towers and treated with amine contacting to remove hydrogen sulfide The most abundant source of lights ends is cracking operations Unsaturated light ends, containing ethylene, propylene, butylenes and pentylenes (from the Fluidized Catalytic Cracking Unit and Coker Unit), are fractionated separately from saturated light ends (from Crude Distillation, Hydrocracking, and Catalytic Reforming) This allows separate disposition: Methane and ethane to fuel gas Ethylene and propylene to petrochemical feedstock Propylene, butylenes, pentylenes, and iso-butane to alkylation Saturated propane and butane for sale Saturated butane to isomerization Gas plant condensate (pentane and higher) are blended to motor gasoline The Gas Plant The Gas Plant will remove the light hydrocarbons from the Naphtha Unit product Lean oil is used to absorb and recover the propane and butane to allow the hydrogen, methane, ethane and hydrogen sulfide to be sent overhead as fuel gas The remaining liquid will be separated out into propane, iso-butane, butane, light naphtha and heavy naphtha Distillation columns are used to separate these gases in the same way as the Crude column The lighter boiling point materials leave the top and the heavier ones leave through the bottom of the tower In addition, the mixed butanes and iso-butane are sent the Alklyation Unit The heavy naphtha is also sent to the Reformer for upgrading Product Blending Refined products are typically the result of blending several component streams or blend stocks Intermediate product qualities are measured and appropriate volumes are mixed into finished product storage using either batch operations or "in-line" blending methods While gasoline blending consumes the most time and effort, other products are blended for sale as well Examples of other products include jet fuel, diesel fuel, fuel oil, and lubricants to name a few Properties include flash point, aniline point, cetane number, pour point, smoke point, viscosity index and others Many of these properties not blend linearly, so finished properties must be predicted using sophisticated math models and experience-based algorithms The cost associated with reprocessing or reblending off-spec product is prohibitive Support Units (SRU/SWS/HMU/ETP) There are several processes that are not directly involved in the processing of hydrocarbons or forming intermediate products, yet play a critical supporting role Without them a petroleum refinery would not be able to exist These processes include the production of hydrogen, the removal of sulfur from water and gas, the production of steam and the treatment of waste water resulting from operations Bitumen Blowing In most cases, the refinery bitumen production by straight run vacuum distillation does not meet the market product quality requirements Authorities and industrial users have formulated a variety of bitumen grades with often stringent quality specifications, such as narrow ranges for penetration and softening point These special grades are manufactured by blowing air through the hot liquid bitumen in a BITUMEN BLOWING UNIT By blowing, the asphaltenes are partially dehydrogenated (oxidised) and form larger chains of asphaltenic molecules via polymerisation and condensation mechanism Blowing will yield a harder and more brittle bitumen (lower penetration, higher softening point), not by stripping off lighter components but changing the asphaltenes phase of the bitumen The bitumen blowing process is not always successful: a too soft feedstock cannot be blown to an on-specification harder grade The blowing process is carried out continuously in a blowing column The liquid level in the blowing column is kept constant by means of an internal draw-off pipe This makes it possible to set the air-to-feed ratio (and thus the product quality) by controlling both air supply and feed supply rate The feed to the blowing unit (at approximately 210 0C), enters the column just below the liquid level and flows downward in the column and then upward through the draw-off pipe Air is blown through the molten mass (280-300 0C) via an air distributor in the bottom of the column The bitumen and air flow are countercurrent, so that air low in oxygen meets the fresh feed first This, together with the mixing effect of the air bubbles jetting through the molten mass, will minimise the temperature effects of the exothermic oxidation reactions: local overheating and cracking of bituminous material The blown bitumen is withdrawn continuously from the surge vessel under level control and pumped to storage through feed/product heat exchangers VGO Hydrocracking Unit In the VGO Hydrocracking Unit, heavy petroleum-based hydrocarbon feedstock (VGO) is cracked into products of lower molecular weight such as liquid petroleum gas (LPG), gasoline, jet fuel and diesel oil The hydrocracking VGO process produces diesel oil with a high cetane number but with low aromatics and sulphur content, making it ideal diesel blending stock Yield structure (1=100%): VHC VGO Hydrocracking Unit Yields ... iso-butane for alkylation The yield across a Hydrocracker may exhibit volumetric gains as high as 20-25% making it a substantial contributor to refinery profitability ETP A major ancillary facility... naphtha and heavy naphtha Distillation columns are used to separate these gases in the same way as the Crude column The lighter boiling point materials leave the top and the heavier ones leave... Distillation Unit / Atmospheric Distillation Uni t Desalter H2 NHTU Naptha Hydrotreate Unit Units Name AGS- Air Generation System AGU- Acid Generation Unit ARU- Amine Recovery Unit ATF Merox- Aviation