guide of refinery process

8/7/2019 Guide of Refinery Process

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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 1 - 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 2 - 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 1 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


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REFINERY PROCESS FLOW CHART

Fuel Gas

Light Gas

H2

Light

Naptha

Heavy

Naptha

Desalted

Crude

Kerosene

Jet Fuel

Diesel Oil

Diesel

Gas Oil

ReducedCrude

Light Vaccume

Gas Oil

Diesel

Heavy Vaccume Gas Oil

(VDU) Vaccume Distillation Unit

VGO-HDTVaccume Gas Oil

Hydotreater

Hrdrocracker

Crude Oil StorageTank

(CDU)Crude Distillation Unit / Atmospheric Distillation Unit

NHTUNaptha Hydrotreate

Unit

NHTUNaptha Hydrotreate

Unit

DHDTDiesel Hydrotreater

Gas Processing

Amin

Me

Heating

Desalter

ATF HDT-ATF Hydrotreater


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Crude Oil Storage

Crude Oil Storage

The American Petroleum Institute (API) has developed a characterization for the density of crude oils:

API = (141.5/Specific Gravity@60F) -131.5

When comparing crude oils, the crude oil with the higher API will be easier to refine than one with a lower AP

In almost all cases, crude oils have no inherent value without petroleum refining processes to convert them i

marketable products. Crude oil is a complex mixture of hydrocarbons that also contains sulfur, nitrogen, heametals and salts. Most of these contaminants must be removed in part or total during the refining process. Thhydrocarbons that make up crude oil have boiling points from less than 60F to greater than 1200F (60-650C

Crude oil varies in sulfur content. Higher sulfur crude oil is more corrosive than lower sulfur crude oils. In ordprocess higher sulfur crude oils, equipment must be built from more expensive alloys to provide higher corroresistance. Many refineries are not able to process crude oils with high sulfur content.

Crude oil is delivered to a refinery by marine tanker, barge, pipeline, trucks and rail. The level of BS&W (bitumsediment and water) is monitored to avoid high levels of water and solids. Water separates from crude oil as in tanks waiting to be refined. This water is generally drained to waste water treatment just prior to processin

Process Chart


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Desalting

All crude oil contains salt, predominantly chlorides. Chloride salts can combine with water to formhydrochloric acid in atmospheric distillation unit overhead systems causing significant equipmentdamage and processing upsets. Chlorides and other salts will also deposit on heat exchanger surfacesreducing 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 andpreheated by exchanging heat with atmospheric distillation product streams to approximately 250F(120C). 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 watertreatment.

Process Chart


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Atmosheric Distillation Unit/ Crude Distillation Unit

CDU

Initial crude oil separation is accomplished by creating a temperature and pressure profile across a tower to edifferent composition throughout the tower.

Desalted crude oil is preheated to a temperature of 500-550F (260-290C) through heat exchange with distillatproducts, internal recycle streams and tower bottoms liquid. Finally, the crude oil is heated to approximately (400C) 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 poinmaterial in the bottom. Progressively higher boiling point material is present between the top and bottom of ttower. Heat is added to the bottom of the tower using a reboiler that vaporizes part of the tower bottom liquidreturns it to the tower. Heat is removed from the top of the tower through an overhead condenser. A portion ocondensed liquid is returned to the tower as reflux. The continuous vaporization and condensation of materiaeach 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), difuel, gas oil and resid. Atmospheric distillation units run at a pressure slightly above atmospheric in the overaccumulator. Temperatures above approximately 750F (400C) are avoided to prevent thermal cracking of cruinto light gases and coke. With the exception of Coker units, the presence of coke in process units is undesirbecause coke deposit fouls refining equipment and severely reduces process performance.


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Vaccum Distillation Units

Atmospheric resid is further fractionated in a Vacuum Distillation tower. Products that exist as a liquid atatmospheric pressure will boil at a lower temperature when pressure is significantly reduced. Absolute operapressure in a Vacuum Tower can be reduced to 20 mm of mercury or less (atmospheric pressure is 760 mm Haddition, 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 750F (400C) in a fired heater and fed to the Vacuum Distillatiowhere 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 vacutower products) are:


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Naptha HDS/ Hydrotreater

Most catalytic reforming catalysts contain platinum as the active material. Sulfur and nitrogen compounds wideactivate the catalyst and must be removed prior to catalytic reforming. The Naphtha HDS unit uses a cobaltmolybdenum catalyst to remove sulfur by converting it to hydrogen sulfide that is removed with unreactedhydrogen.

Reactor conditions are relatively mild for Naphtha HDS at 400-500F (205-260C) and relatively moderate press350-650 psi (25-45 bar). As coke deposits on the catalyst, reactor temperature must be raised. Once the reactotemperature reaches ~750F (400C), 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 NaHDS. Often pentanes, hexanes and light naphtha are removed and sent directly to gasoline blending or pretrean Isomerization Unit prior to gasoline blending.


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Kerosene HDS/ Hydrotreater

Hydrotreating is a catalytic process to stabilize products and remove objectionable elementslike sulfur, nitrogen and aromatics by reacting them with hydrogen. Cobalt-molybdenumcatalysts are used for desulphurization. When nitrogen removal is required in addition to

sulfur, nickel-molybdenum catalysts are used. In some instances, aromatics saturation ispursued during the hydrotreating process in order to improve diesel fuel performance.

Most hydrotreating reactions take place between 600-800F (315-425C) and at moderately highpressures 500-1500 psi (35-100 bar). As coke deposits on the catalyst, reactor temperaturemust be raised. Once the reactor temperature reaches ~750F (400C), the unit is scheduled forshutdown and catalyst replacement.

Hydrogen is combined with feed either before or after it has been heated to reactiontemperature. The combined feed enters the top of a fixed bed reactor, or series of reactorsdepending on the level of contaminant removal required, where it flows downward over a bedof 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 productsleave 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 sulfideis sent to sour gas processing and water removed from the process is sent to sour waterstripping prior to use as desalter water or discharge.


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Diesel HDS/Hydrotreater

Hydrotreating is a catalytic process to stabilize products and remove objectionable elementslike sulfur, nitrogen and aromatics by reacting them with hydrogen. Cobalt-molybdenumcatalysts are used for desulphurization. When nitrogen removal is required in addition to

sulfur, nickel-molybdenum catalysts are used. In some instances, aromatics saturation ispursued during the hydrotreating process in order to improve diesel fuel performance.

Most hydrotreating reactions take place between 600-800F (315-425C) and at moderately highpressures 500-1500 psi (35-100 bar). As coke deposits on the catalyst, reactor temperaturemust be raised. Once the reactor temperature reaches ~750F (400C), the unit is scheduled forshutdown and catalyst replacement.

Hydrogen is combined with feed either before or after it has been heated to reactiontemperature. The combined feed enters the top of a fixed bed reactor, or series of reactorsdepending on the level of contaminant removal required, where it flows downward over a bedof 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 productsleave 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 sulfideis sent to sour gas processing and water removed from the process is sent to sour waterstripping prior to use as desalter water or discharge.


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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 600-800F (315-425C) and at relatively high

pressures up to 2000 psi (138 bar) depending on the level of reaction severity needed to meetproduct specification and the composition of the feedstock.

Hydrogen is combined with feed either before or after it has been heated to reactiontemperature. The combined feed enters the top of a fixed bed reactor, or series of reactorsdepending on the level of contaminant removal required, where it flows downward over a bedof metal-oxide catalyst. For desulphurization, the most common catalysts are cobalt-molybdenum. When hydrodenitrofication (HDN) is desired in addition to desulfurization,nickel-molybdenum 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 productsleave with the oil-hydrogen steam. Hydrogen is separated from oil and hydrogen sulfide andlight end are stripped from the desulfurized product.

Hydrogen sulfide is sent to sour gas processing and water removed from the process is sentto sour water stripping prior to use as desalter water or discharge.


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Fluid Catalytic Cracker (FCC)

The FCC is considered by many as the heart of a modern petroleum refinery. FCC is the toolrefiners use to correct the imbalance between the market demand for lighter petroleumproducts and crude oil distillation that produces an excess of heavy, high boiling rangeproducts. The FCC unit converts heavy gas oil into gasoline and diesel.

The FCC process cracks heavy gas oils by breaking the carbon bonds in large molecules intomultiple smaller molecules that boil in a much lower temperature range. The FCC can achieveconversions of 70-80% of heavy gas oil into products boiling in the heavy gasoline range. Thereduction in density across the FCC also has the benefit of producing a volume gain (i.e.,combined product volumes are greater than the feed volume). Since most petroleum productsare sold on a volume basis, this gain has a significant effect on refinery profitability.

FCC reactions are promoted at high temperatures 950-1020F (510-550C) but relatively lowpressures of 10-30 psi (1-2 bar). At these temperatures, coke formation deactivates thecatalyst by blocking reaction sites on the solid catalyst. The FCC unit utilizes a very finepowdery catalyst know as a zeolite catalyst that is able to flow like a liquid in a fluidized bed -hence the name "Fluid Cat Cracker". Catalyst is continually circulated from the reactor to aregenerator where coke is burned off in controlled combustion with air creating carbonmonoxide, carbon dioxide, sulfur oxides (SOX) and nitrous oxides (NOX) as well as some

other combustion products.

Feedstock gas oil is preheated and mixed with hot catalyst coming from the regenerator at1200-1350F (650-735C). The hot catalyst vaporizes the feedstock and heats it to reactiontemperature. To avoid overcracking, which reduces yield at the expense of gasoline, reactiontime is minimized. The primary reaction occurs in the transfer line (or riser) going to thereactor. The primary purpose of the reactor is to separate catalyst from reaction products.

FCC products are more highly unsaturated than distillation products. Naphtha in the gasolinerange has good octane. Distillate range products have low pour points but poorer combustionqualities. Light end products are highly olefinic (unsaturated) and are used as feedstock forfurther upgrading processes like alkylation. With sulfur concentration of gasoline reducing,FCC products (gasoline and distillates) may require desulfurization through a HDS Unit priorto blending.

Air emissions are a growing concern for FCC units. Emissions include catalyst fines, SOX andNOX components. Electrostatic precipitators and scrubbers are used to reduce air emissions.As air quality concerns grow, more equipment to reduce SOX and NOX are expected.


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Hydrocracker

The Hydrocracker is similar to the FCC in that it is a catalytic process that cracks long chaingas oil molecules into smaller molecules that boil in the gasoline, jet fuel and diesel fuelrange. The fundamental difference is that cracking reactions take place in an extremelyhydrogen rich atmosphere. Two reactions occur. First carbon bonds are broken followed by

attachment of hydrogen. Hydrocracker products are sulfur free and saturated.

Another difference is operating conditions. Hydrocrackers run at high temperature 650-800F(345-425C) and very high pressures of 1500-3000 psi (105-210 bar). Hydrocracker reactorscontain multiple fixed beds of catalyst typically containing palladium, platinum, or nickel.These catalysts are poisoned by sulfur and organic nitrogen, so a high-severity HDS/HDNreactor pretreats feedstock prior to the hydrocracking reactors. Hydrocracker units may beconfigured in single stage or two stage reactor systems that enable a higher conversion ofgas oil into lower boiling point material.

Typical feedstock to a Hydrocracker includes FCC cycle oil, coker gas oil and gas oil fromcrude distillation. Heavy naphtha from the Hydrocracker makes excellent Catalytic Reformerfeedstock. Distillates from Hydrocracking make excellent jet fuel blend stocks. Light ends arehighly saturated and a good source of iso-butane for alkylation. The yield across aHydrocracker may exhibit volumetric gains as high as 20-25% making it a substantialcontributor to refinery profitability.


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ETPA major ancillary facility of the expanded refinery is the effluent water treatment plant.

The treatment of effluent water is as follows. Process water is deodorised in sour-water

strippers where the gas (H2S and NH3) is stripped off. The stripped water has oil removed inthe gravity separators and then, together with some rainwater, is homogenised in a buffer

tank. From this tank, the effluent water is piped to a flocculation/flotation unit where air and

polyelectrolytes are injected in small concentrations to make the suspended oil and solids

separate from the water. The latter are skimmed off and piped to a separate sludge

handling/disposal unit. The remaining watery effluent from the flotation unit is passed to

adjoining biotreater where the last of the dissolved organic impurities are removed by the

action of micro-organisms in the presence of oxygen (biodegradation). On a continual basis,

sludge containg micro-organisms is removed to the sludge handling/disposal unit


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Coker / Visbreaker

Coking and visbreaking are both thermal decomposition processes. Coking is predominant inthe United States while Visbreaking is mostly applied in Europe.

With the exception of the coking process, formation of coke in a petroleum refinery isundesirable because coke fouls equipment and reduces catalyst activity. However, in thecoking process, coke is intentionally produced as a byproduct of vacuum resid conversionfrom low value fuel and asphalt into higher value products.

The most common form of the coking process in today's refineries is Delayed Coking wherevacuum resid is thermally cracked into smaller molecules that boil at lower temperatures.Products include naphtha, gas oils and coke. Light product yield varies by feedstock but isgenerally around 75% conversion. Coke is sold as a fuel or specialty product into the steeland aluminum industry after calcining to remove impurities.

Vacuum resid is fed to the coker fractionator to remove as much light material as possible.Bottoms from the fractionator are heated in a direct fired furnace to more than 900F (480C)and discharged into a coke drum where thermal cracking is completed. High velocity and

stream injection are used to minimize coke formation in furnace tubes. Coke deposits in thedrum and cracked products are sent to the fractionator for recovery. Coke drums typicallyoperate in the 25-50 psi (2-4 bar) range while the fractionator operates at a pressure slightlyabove atmospheric in the overhead accumulator. Fractionator bottoms are recycled throughthe furnace to extinction.

Multiple coke drums are used. As one drum is being filled with coke, others are offline forcoke removal. Coke removal involves steaming, quenching, hydraulic cutting to remove solidcoke from the drum and vessel preparation for return to service.

Coker light products are highly unsaturated. Coker light ends are recovered as an olefin feedsource for alkylation. Coker naphtha requires desulfurization before upgrade in the CatalyticReforming Unit. Coker gas oils are generally sent to the Hydrocracker for upgrade.

Visbreaking is a milder form of thermal cracking often used to reduce the viscosity and pourpoint of vacuum resid in order to meet specification for heavy fuel oil. Visbreaking helps avoidthe use of expensive cutter stock required for dilution. The process is carefully controlled topredominantly crack long paraffin chains off aromatic compounds while avoiding cokingreactions.

There is a tradeoff between furnace temperature and residence time for visbreakingoperations. Longer residence time leads to lower furnace outlet temperatures. In general,operations are conducted between 800-930F (425-500C). Material is quenched with cold gasoil to stop the cracking process. Pressure is important to unit design and ranges between 300-750 psi (20-50 bar).


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ARU

The Amine Treating Unit removes CO2 and H2S from sour gas and hydrocarbon

streams in the Amine Contactor. The Amine (MDEA) is regenerated in the Amine

Regenerator, and recycled to the Amine Contactor.

The sour gas streams enter the bottom of the Amine Contactor. The cooled lean

amine is trim cooled and enters the top of the contactor column. The sour gas flowsupward counter-current to the lean amine solution. An acid-gas-rich-amine solution

leaves the bottom of the column at an elevated temperature, due to the exothermic

absorption reaction. The sweet gas, after absorption of H2S by the amine solution,flows overhead from the Amine Contactor.

The Rich Amine Surge Drum allows separation of hydrocarbon from the amine

solution. Condensed hydrocarbons flow over a weir and are pumped to the drain. Therich amine from the surge drum is pumped to the Lean/Rich Amine Exchanger.

The stripping of H2S and CO2 in the Amine Regenerator regenerates the rich amine

solution. The Amine Regenerator Reboiler supplies the necessary heat to strip H2S

and CO2 from the rich amine, using steam as the heating medium.

Acid gas, primarily H2S and water vapor from the regenerator is cooled in the Amine

Regenerator Overhead Condenser. The mixture of gas and condensed liquid is

collected in the Amine Regenerator Overhead Accumulator. The uncondensed gas is

sent to Sulfur Recovery.

The Amine Regenerator Reflux Pump, pumps the condensate in the Regenerator

Accumulator, mainly water, to the top tray of the Amine Regenerator A portion of the

pump discharge is sent to the sour water tank.

Lean amine solution from the Amine Regenerator is cooled in the Lean/Rich

Exchanger. A slipstream of rich amine solution passes through a filter to remove

particulates and hydrocarbons, and is returned to the suction of the pump. The lean

amine is further cooled in the Lean Amine Air Cooler, before entering the Amine

Contactor.


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Needle Coke Unit

Needle Coke is a premium grade, high value petroleum coke, used in themanufacturing of graphite electrodes for the arc furnaces in the metallurgy industry.Its hardness is due to the dense mass formed with a structure of carbon threads orneedles oriented in a single direction. Needle coke is highly crystalline and canprovide the properties needed for manufacturing graphite electrode. It can withstand

temperatures as high as 28000C.

The technology is primarily focused on production of needle coke in any existingdelayed coker unit using heavier hydrocarbon streams without any costly pre-treatment. Formation of needle coke requires specific feedstocks, special cokingand also special calcination conditions. If feedstocks are suitable for needle coke,process conditions for coking and calcination are selected to improve the propertiesand yield of the needle coke. Typical yield of needle coke is 18-30 wt% of fresh feed.

The maximum limits of sulfur and ash in calcined needle coke are 0.6 and 0.3 wt%

respectively. Higher sulfur content of coke can cause the puffing of electrode. Highash content can increase the resistivity and decrease electrode strength. Thecalcined coke with higher sulfur and ash content is not considered suitable formanufacturing of graphite electrode even if other properties meet the quality ofpremium grade coke. Thus, the quality and price of needle coke are highlydependent on the properties of feedstock used for coking.

Refineries having delayed coker unit either processing low sulfur crude and/orhaving a residue hydrotreater unit and/or having RFCC/ FCC unit processing lowsulfur feed are suitable for considering this technology.


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Catalytic Reforming

Gasoline has a number of specifications that must be satisfied to provide high performancefor today's motor vehicles. Octane, however, is the most widely recognized specification. Theoctane number is generally reported as the average of Research Octane Number (RON) andMotor Octane Number (MON), (R+M)/2. MON is the more severe test, so for a given fuel RON is

always higher than MON.

Unfortunately, heavy naphtha from atmospheric distillation, which forms a significantpercentage of the gasoline blend, has an octane rating of around 50 (R+M)/2. Octane demandfor gasoline ranges from upper-80 to mid 90 (R+M)/2. Catalytic Reforming is the workhorse foroctane upgrade in today's modern refinery. Molecules are reformed into structures thatincrease the percentage of high octane components while reducing the percentage of lowoctane components.

In short, Catalytic Reforming converts straight chain and saturated molecules intounsaturated cyclic and aromatic compounds. In doing so, it liberates a significant amount ofhydrogen that may be used in desulfurization and saturation reactions elsewhere in therefinery. In addition to hydrogen and reformate, some light ends are removed to meet vaporpressure requirements. Catalytic Reforming creates a density increase (i.e., finished productvolume is significantly less than feed volume) that creates a volumetric loss to refiningoperations.

Reforming uses platinum catalyst. Sulfur poisons the catalyst; therefore, virtually all sulfurmust be removed prior to reforming. Temperature is used to control produced octane. The unitis operated at temperatures between 925-975F (500-525C) and pressures between 100-300psi (7-25 bar). Reformer octane is generally controlled between 90 and 95 (R+M)/2 dependingon gasoline blending demands. As a result of very high reactor temperatures, coke forms onthe catalyst, which reduces activity. Coke must either be removed continuously (ContinuousCatalyst Regeneration CCR Units) or periodically (Semi-regenerative Units) to maintain

performance.


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Isomerization

Catalytic reforming has little effect on Light Straight Run gasoline (LSR), which is material inthe C5 - 165F (74C) boiling range. This fraction is removed from reformer feed. Its octanenumber may be significantly improved by converting normal paraffins into their isomers in theIsomerization Unit.

Isomerization can result in a significant octane increase since n-pentane has a researchoctane number (RON) of 62 and iso-pentane has a RON of 92. Once through isomerization canincrease 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 organicchlorides to maintain activity. Organic chlorides are converted to hydrochloric acid; therefore,Isomerization feed must be free of water to avoid serious corrosion problems. Other catalystsuse a molecular sieve base and are reported to tolerate water better. Isomerization usesreaction temperatures of 300-400F (150-200C) at pressures of 250-400 psi (17-27 bar).

For refineries that do not have hydrocracking facilities to supply iso-butane for alkylation feed,iso-butane can be made from n-butane using isomerization.


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Propylene Recovery Unit


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Alkylation

Alkylation is a refining process that provides an economic outlet for very light olefinsproduced at the FCC and Coker. Alkylation is the opposite of cracking. The process takessmall molecules and combines them into larger molecules with high octane and low vaporpressure characteristics.

In the Alkylation Unit, propylene, butylenes and sometimes pentylenes (also known asamylenes) are combined with iso-butane in the presence of a strong acid catalyst (eitherhydrofluoric (HF) or sulfuric acid) to form branched, saturated molecules. Alkylate has anoctane around 95 (R+M)/2 and low vapor pressure making it a valuable gasoline blendingcomponent particularly for premium grade products. It contains no olefins, aromatics orsulfur.

Sulfuric Acid Alkylation runs at 35-60F (2-15C) to minimize polymerization reactions while HFAlkylation, which is less sensitive to polymerization reactions, runs at 70-100F (20-38C).Chilling or refrigeration is required to remove heat of reaction.

Alkylation products are distilled to remove propane, iso-butane and alkylate. Sulfuric acidsludge must be removed and regenerated. HF is neutralized with KOH, which may beregenerated and returned to the process.


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Merox Treatment

Technical Profile

Merox is a process to sweeten products by extracting and/or converting mercaptan sulfur toless objectionable disulfides. It is often used to treat products such as liquefied petroleumgases, 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 columnbottom as extract. Air and possibly catalyst are mixed with extract and sent to an oxidationreactor where caustic is regenerated and mercaptans are converted to disulfides. Disulfidesare insoluble in water and can be removed in a product separator that vents excess air andgas for disposal or destruction and separates sulfide oil, which may be returned to the refiningprocess, from regenerated caustic, which is returned to the extraction column. Over timecaustic will become spent and must be wasted to other refinery uses or to spent causticdestruction.

When removal of mercaptan sulfur is not required, "sweetening" may be applied to improveodor where mercaptan sulfur is converted to disulfide and carried out with the petroleumproduct. For sweetening, dilute caustic is added to the product prior to air injection. Combinedfeed 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 caustictreatment.


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Sour Water Stripper

Stripping steam and wash water in various refining operations is condensed and removedfrom overhead condensate accumulators or product separators. This water containsimpurities most notably sulfur compounds and ammonia. Hydrogen sulfide and ammonia areremoved in the sour water stripper.

By varying the pH of the feed solution, hydrogen sulfide may be removed for amine treatmentand ammonia may be removed for reuse or neutralization in separate strippers. Once strippedof contaminants, water is either reused for desalter water or discharged directly to wastewater treatment facilities.


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Sulfur Recovery

The conversion chemistry is:

2H2H2S + 3 O2 2 SO2 + 2 H2O (Combustion)

2 H2S + SO2 3 S + 2 H2O (Conversion)

The sulfur recovery process used in most refineries is a "Claus Unit". In general, the ClausUnit involves combusting one-third of the hydrogen sulfide (H2S) into SO2 and then reactingthe SO2 with the remaining H2S in the presence of cobalt-molybdenum catalyst to formelemental sulfur.

Generally, multiple conversion reactors are required. Conversion of 96-97% of the H2 toelemental sulfur is achievable in a Claus Unit. If required for air quality, a Tail Gas Treater maybe used to remove remaining H2S in the tail gas from the Sulfur Recovery process.


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HMUHydrogen manufacturing UnitThe 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 700C 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 do 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.


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Gasoline

Component

Iso-butane

n-butane

Iso-pentane

n-pentane

Iso-hexane

LSR

Isomerate

Hydrocrackate

Coker Naphtha

FCC Gasoline

Reformate, 94 RON

Reformate, 100 RON

Petroleum refineries produce a variety of components that are then used to blend refinedproducts. Product blending is a critical source of flexibility and profitability for refiningoperations. Of great interest is the economic blending of gasoline.

Gasoline is not a single product. Refiners blend hundreds of different specifications. Inaddition to the different grades of gasoline we all see at the retail pump, gasoline is subject todifferent specifications based on country, geographic location, season, humidity, altitude, andenvironmental regulations. This further complicates distribution systems with additionalrequirements for low sulfur, conventional, reformulated and oxygenated "boutique" blends.

Key to good gasoline performance is octane, vapor pressure (Reid Vapor Pressure - RVP) anddistillation range of the blend. Below is a table of octane, RVP and specific gravity blendingvalues for some typical gasoline blending components:

Alkylate, C4

Alkylate, C5


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The Gas Plant

This allows separate disposition:

1. Methane and ethane to fuel gas

2. Ethylene and propylene to petrochemical feedstock

3. Propylene, butylenes, pentylenes, and iso-butane to alkylation

4. Saturated propane and butane for sale

5. Saturated butane to isomerization

6. Gas plant condensate (pentane and higher) are blended to motor gasoline.

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 arefractionated 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 theFluidized Catalytic Cracking Unit and Coker Unit), are fractionated separately from saturatedlight ends (from Crude Distillation, Hydrocracking, and Catalytic Reforming).

The Gas Plant will remove the light hydrocarbons from the Naphtha Unit product. Lean oil isused to absorb and recover the propane and butane to allow the hydrogen, methane, ethaneand hydrogen sulfide to be sent overhead as fuel gas. The remaining liquid will be separatedout 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 bottomof the tower. In addition, the mixed butanes and iso-butane are sent the Alklyation Unit. Theheavy naphtha is also sent to the Reformer for upgrading.


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Product Blending

Refined products are typically the result of blending several component streams or blendstocks. Intermediate product qualities are measured and appropriate volumes are mixed intofinished product storage using either batch operations or "in-line" blending methods.

While gasoline blending consumes the most time and effort, other products are blended forsale as well. Examples of other products include jet fuel, diesel fuel, fuel oil, and lubricants toname a few. Properties include flash point, aniline point, cetane number, pour point, smokepoint, viscosity index and others. Many of these properties do not blend linearly, so finishedproperties must be predicted using sophisticated math models and experience-basedalgorithms. The cost associated with reprocessing or reblending off-spec product isprohibitive.


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Support Units (SRU/SWS/HMU/ETP)

There are several processes that are not directly involved in the processing ofhydrocarbons 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 fromwater and gas, the production of steam and the treatment of waste water resultingfrom operations.


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Bitumen Blowing

In most cases, the refinery bitumen production by straight run vacuum distillationdoes not meet the market product quality requirements. Authorities and industrialusers have formulated a variety of bitumen grades with often stringent qualityspecifications, such as narrow ranges for penetration and softening point. Thesespecial 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 largerchains of asphaltenic molecules via polymerisation and condensation mechanism.Blowing will yield a harder and more brittle bitumen (lower penetration, highersoftening point), not by stripping off lighter components but changing theasphaltenes phase of the bitumen. The bitumen blowing process is not alwayssuccessful: a too soft feedstock cannot be blown to an on-specification hardergrade.

The blowing process is carried out continuously in a blowing column. The liquidlevel 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) bycontrolling both air supply and feed supply rate. The feed to the blowing unit (atapproximately 210 0C), enters the column just below the liquid level and flowsdownward in the column and then upward through the draw-off pipe. Air is blownthrough the molten mass (280-300 0C) via an air distributor in the bottom of thecolumn. The bitumen and air flow are countercurrent, so that air low in oxygenmeets the fresh feed first. This, together with the mixing effect of the air bubblesjetting through the molten mass, will minimise the temperature effects of theexothermic oxidation reactions: local overheating and cracking of bituminousmaterial. The blown bitumen is withdrawn continuously from the surge vessel underlevel control and pumped to storage through feed/product heat exchangers.


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VGO Hydrocracking UnitIn 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

guide of refinery process

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