A Guide of Refinery Process .xls

7/28/2019 A Guide of Refinery Process .xls

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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 reactantscan 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 boilersand 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.


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REFINERY PROCESS FLOW CHART Fuel Gas

Light Gas H2

H2 H2

Light

Naptha

Heavy

Naptha

Desalted

Crude

Kerosene

Jet Fuel

Diesel Oil H2

Diesel

Gas Oil

Reduced

Crude

Light Vaccume

Gas Oil

Diesel

Heavy Vaccume Gas Oil

Gasoline

Vaccume Coker Napt

Residuel

(VDU)VaccumeDistillationUnit

ATF MEROAviation Turb

Fuel Merox

CCContinuos

Refo

(FCCU)Catalytic C

Uni

VGO-HDTVaccume Gas Oil

Hydotreater

Hrdrocracker

DCU- DelayedCoker Unit

Crude Oil StorageTank

(CDU)Crud

eDistillationUnit/AtmosphericDistillationUnit

NHTUNaptha Hydrotreate

Unit

ISLight NIsome

NHTUNaptha Hydrotreate

Unit

DHDTDiesel Hydrotreater

Gas Processing

ARUAmine Recovery

Unit

Merox Unit

Heating

Desalter

ATF HDT-ATF Hydrotreater


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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 60F to

reater than 1200F 60-650C .

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@60F) -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


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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 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 water treatment.

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 enable different composition throughout the tower.

Desalted crude oil is preheated to a temperature of 500-550F (260-290C) through heat exchange with

distillation products, internal recycle streams and tower bottoms liquid. Finally, the crude oil is heated to

approximately 750F (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

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

se aration of etroleum roducts 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 750F (400C) 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.


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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 400-500F (205-260C) 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 ~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 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.


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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 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 high

pressures 500-1500 psi (35-100 bar). As coke deposits on the catalyst, reactor temperature

must be raised. Once the reactor temperature reaches ~750F (400C), 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.


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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 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 high

pressures 500-1500 psi (35-100 bar). As coke deposits on the catalyst, reactor temperature

must be raised. Once the reactor temperature reaches ~750F (400C), the unit is scheduled for

shutdown and catalyst replacement.




of metal-oxide catalyst



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.


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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.




of metal-oxide catalyst. For desulphurization, the most common catalysts are cobalt-

molybdenum. When hydrodenitrofication (HDN) is desired in addition to desulfurization, nickel-

mol bdenum catal sts are recommended.



leave with the oil-hydrogen steam. Hydrogen is separated from oil and hydrogen sulfide andli ht end are stri ed from the desulfurized roduct.

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.


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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 tool

refiners use to correct the imbalance between the market demand for lighter petroleum

products and crude oil distillation that produces an excess of heavy, high boiling range

products. 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 moleculesinto multiple smaller molecules that boil in a much lower temperature range. The FCC can

achieve conversions of 70-80% of heavy gas oil into products boiling in the heavy gasoline

range. The reduction 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 products are sold on a volume basis, this gain has a significant effect on refinery

rofitabilit .

FCC reactions are promoted at high temperatures 950-1020F (510-550C) but relatively low

pressures of 10-30 psi (1-2 bar). At these temperatures, coke formation deactivates the

catalyst by blocking reaction sites on the solid catalyst. The FCC unit utilizes a very fine

powdery 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 a

regenerator where coke is burned off in controlled combustion with air creating carbon

monoxide, carbon dioxide, sulfur oxides (SOX) and nitrous oxides (NOX) as well as some

other combustion roducts.

Feedstock gas oil is preheated and mixed with hot catalyst coming from the regenerator at

1200-1350F (650-735C). The hot catalyst vaporizes the feedstock and heats it to reaction

temperature. To avoid overcracking, which reduces yield at the expense of gasoline, reaction

time is minimized. The primary reaction occurs in the transfer line (or riser) going to the

reactor. 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

gasoline range has good octane. Distillate range products have low pour points but poorer

combustion qualities. Light end products are highly olefinic (unsaturated) and are used as

feedstock for further upgrading processes like alkylation. With sulfur concentration of

gasoline reducing, FCC products (gasoline and distillates) may require desulfurization

throu h a HDS Unit rior to blendin .

Air emissions are a growing concern for FCC units. Emissions include catalyst fines, SOX

and NOX 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 chain

gas oil molecules into smaller molecules that boil in the gasoline, jet fuel and diesel fuel

range. The fundamental difference is that cracking reactions take place in an extremely

hydrogen rich atmosphere. Two reactions occur. First carbon bondsare 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 reactors

contain 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/HDN

reactor pretreats feedstock prior to the hydrocracking reactors. Hydrocracker units may be

configured in single stage or two stage reactor systems that enable a higher conversion of gas

oil into lower boilin oint material.

Typical feedstock to a Hydrocracker includes FCC cycle oil, coker gas oil and gas oil from

crude distillation. Heavy naphtha from the Hydrocracker makes excellent Catalytic Reformer

feedstock. Distillates from Hydrocracking make excellent jet fuel blend stocks. Light ends are

highly 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 substantial

contributor 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 in

the United States while Visbreaking is mostly applied in Europe.

With the exception of the coking process, formation of coke in a petroleum refinery is

undesirable because coke fouls equipment and reduces catalyst activity. However, in the

coking 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 where

vacuum 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 is

generally around 75% conversion. Coke is sold as a fuel or specialty product into the steel

and 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 the

drum and cracked products are sent to the fractionator for recovery. Coke drums typically

operate in the 25-50 psi (2-4 bar) range while the fractionator operates at a pressure slightly

above atmospheric in the overhead accumulator. Fractionator bottoms are recycled through

the furnace to extinction.

Multiple coke drums are used. As one drum is being filled with coke, others are offline for

coke removal. Coke removal involves steaming, quenching, hydraulic cutting to remove solid

coke from the drum and vessel preparation for return to service.

Coker light products are highly unsaturated. Coker light ends are recovered as an olefin feed

source for alkylation. Coker naphtha requires desulfurization before upgrade in the Catalytic

Reforming 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 avoid

the use of expensive cutter stock required for dilution. The process is carefully controlled to

predominantly crack long paraffin chains off aromatic compounds while avoiding coking

reactions.

There is a tradeoff between furnace temperature and residence time for visbreaking

operations. Longer residence time leads to lower furnace outlet temperatures. In general,

operations are conducted between 800-930F (425-500C). Material is quenched with cold gas

oil to stop the cracking process. Pressure is important to unit design and ranges between 300-

750 psi (20-50 bar).


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ARUT e Am ne Treat ng Un t removes CO2 an H2S rom sour gas an y rocar on

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

Regenerator, and recycled to the Amine Contactor.

e sour gas s reams en er e o om o e m ne on ac or. e coo e ean

amine is trim cooled and enters the top of the contactor column. The sour gas flows

upward 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. The

rich amine from the surge drum is pumped to the Lean/Rich Amine Exchanger.

T e str pp ng o H2S an CO2 n t e Am ne Regenerator regenerates t e r c am ne

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

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

Ac gas, pr mar y H2S an water vapor rom t e regenerator s coo e n t e Am ne

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.

T e Am ne Regenerator Re ux Pump, pumps t e con ensate n t e 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.

ean am ne so ut on rom t e m ne egenerator s coo e n t e ean c

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 UnitNeedle Coke is a premium grade, high value petroleum coke, used in the

manufacturing 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 or

needles oriented in a single direction. Needle coke is highly crystalline and can

provide 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 existing

delayed coker unit using heavier hydrocarbon streams without any costly pre-

treatment. Formation of needle coke requires specific feedstocks, special coking

and also special calcination conditions. If feedstocks are suitable for needle coke,

process conditions for coking and calcination are selected to improve the properties

and 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. High

ash content can increase the resistivity and decrease electrode strength. The

calcined coke with higher sulfur and ash content is not considered suitable for

manufacturing of graphite electrode even if other properties meet the quality of

premium grade coke. Thus, the quality and price of needle coke are highly

dependent on the properties of feedstock used for coking.

Refineries having delayed coker unit either processing low sulfur crude and/or

having a residue hydrotreater unit and/or having RFCC/ FCC unit processing low

sulfur 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 performance

for today's motor vehicles. Octane, however, is the most widely recognized specification. The

octane number is generally reported as the average of Research Octane Number (RON) and

Motor 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 significant

percentage of the gasoline blend, has an octane rating of around 50 (R+M)/2. Octane demand

for gasoline ranges from upper-80 to mid 90 (R+M)/2. Catalytic Reforming is the workhorse for

octane upgrade in today's modern refinery. Molecules are reformed into structures that

increase the percentage of high octane components while reducing the percentage of low

octane com onents.

In short, Catalytic Reforming converts straight chain and saturated molecules into

unsaturated cyclic and aromatic compounds. In doing so, it liberates a significant amount of

hydrogen that may be used in desulfurization and saturation reactions elsewhere in the

refinery. In addition to hydrogen and reformate, some light ends are removed to meet vaporpressure requirements. Catalytic Reforming creates a density increase (i.e., finished product

volume is significantly less than feed volume) that creates a volumetric loss to refining

o erations.

Reforming uses platinum catalyst. Sulfur poisons the catalyst; therefore, virtually all sulfur

must be removed prior to reforming. Temperature is used to control produced octane. The

unit is operated at temperatures between 925-975F (500-525C) and pressures between 100-

300 psi (7-25 bar). Reformer octane is generally controlled between 90 and 95 (R+M)/2

depending on gasoline blending demands. As a result of very high reactor temperatures, coke

forms on the catalyst, which reduces activity. Coke must either be removed continuously

(Continuous Catalyst Regeneration CCR Units) or periodically (Semi-regenerative Units) to

maintain erformance.


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Isomerization

Catalytic reforming has little effect on Light Straight Run gasoline (LSR), which is material in

the C5 - 165F (74C) 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 300-400F (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 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 35-60F (2-15C) to minimize polymerization reactions while HF

Alkylation, 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 be

regenerated 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 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 improveodor 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

s ent caustic treatment.


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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.


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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 SO2and then reacting

the SO2 with the remaining H2S in the presence of cobalt-molybdenum catalyst to form

elemental sulfur.

The conversion chemistry is:

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

2 H2S + SO2 3 S + 2 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.


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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 producedby 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 theend 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

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 RONReformate, 100 RON

Alkylate, C4Alkylate, C5


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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:

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 sale5. Saturated butane to isomerization

6. 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 sentthe Alklyation Unit. The

heavy 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 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 do 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

rohibitive.


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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.


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Bitumen BlowingIn 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

rade.

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.


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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

Documents

A Guide of Refinery Process .xls