October 26, 2017 | Author: vazzoleralex6884 | Category: Cracking (Chemistry), Oil Refinery, Petroleum, Catalysis, Gasoline
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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 TENDERING & ESTIMATION TEAM, ECIL, MUMBAI

Light Gas

Light Naptha

Heavy Naptha

Desalted Crude

Kerosene Jet Fuel

Diesel Oil

Gas Oil

Reduced Crude

Light Vaccume Gas Oil

Heavy Vaccume Gas Oil

Vaccume Residuel

Fuel Gas




H2S Diesel


Diesel I Butane Gasoline

Coker Naptha to CCR Coker Gas Oil to FCCU Petroleum Coke

BITUMEN (Road, Roofing, waterproofing)

Refinery Fuel/Fuel Gas Sr 1 2 3 4 5 6 7 8 9 10 11 12 13 14 16 17 18 19 20 21 22 23 24 25 26

Units Name AGS- Air Generation System AGU- Acid Generation Unit ARU- Amine Recovery Unit ATF Merox- Aviation Turbine Fuel M ATF-HDT- Aviation Turbine Fuel Hy CCR- Continuous Catalytic Reform 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 Un 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 VBS- Visbreaker Unit VDU- Vaccume Distillation Unit VGO-HDT- Vaccume Gas Hydrotre

H2S t

Sour Water (From CDU, VDU, HDS, FCCu, Etc)

Strippe Propane


CO Propylene

To Hydrocracker & Hydrotreater


Premier Coke


Generation System d Generation Unit ne Recovery Unit x- Aviation Turbine Fuel Merox - Aviation Turbine Fuel Hydrotreater ntinuous Catalytic Reformer de Distillation Unit ayed Crocker Unit

esel Hydrotreating uent Treatment Plant uid Catalytic Cracker Unit soline Merox Unit drogen Manufacturing Unit dle Coke Unit tha Hydrotreater pylene Recovery Unit urated Gas Unit phur Recoveru Unit ulphur Storage & Handling ur Water Stripper saturated Gas Seperation Unit

cume Distillation Unit T- Vaccume Gas Hydrotreater

H2S to SRU

Stripped Water


H2 Natural Gas



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 pro

Crude oil varies in sulfur content. Higher sulfur crude oil is more corrosive than lower sulfur crude oils. In order to process high The American Petroleum Institute (API) has developed a characterization for the density of crude oils: ˚API = (141.5/Specific [email protected]˚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 a

t them into marketable products. Crude oil is a complex mixture of hydrocarbons that also contains sulfur, nitrogen, heavy metals and salts.

. In order to process higher sulfur crude oils, equipment must be built from more expensive alloys to provide higher corrosion resistance. M

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 w

, heavy metals and salts. Most of these contaminants must be removed in part or total during the refining process. The hydrocarbons that m

er corrosion resistance. Many refineries are not able to process crude oils with high sulfur content.

ude oil as it sits in tanks waiting to be refined. This water is generally drained to waste water treatment just prior to processing.

. The hydrocarbons that make up crude oil have boiling points from less than 60˚F to greater than 1200˚F (60-650˚C).



All crude oil contains salt, predominantly chlorides. Chloride salts can combine with water to form hydrochloric acid in atmosph

Salt must be removed from crude oil prior to processing. Crude oil is pumped from storage tanks and preheated by exchanging

drochloric acid in atmospheric distillation unit overhead systems causing significant equipment damage and processing upsets. Chlorides an

preheated by exchanging heat with atmospheric distillation product streams to approximately 250˚F (120˚C). Inorganic salts are removed b

ssing upsets. Chlorides and other salts will also deposit on heat exchanger surfaces reducing energy efficiency and increasing equipment re

ganic salts are removed by emulsifying crude oil with water and separating them in a desalter. Salts are dissolved in water and brine is remo

d increasing equipment repairs and cleaning.

in water and brine is removed using an electrostatic field and sent to the waste water treatment.

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 co

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

Distillation concentrates lower boiling point material in the top of the distillation tower and higher boiling point material in the bo

The most common products of atmospheric distillation are fuel gas, naphtha, kerosene (including jet fuel), diesel fuel, gas oil a

ower to enable different composition throughout the tower.

ith distillation products, internal recycle streams and tower bottoms liquid. Finally, the crude oil is heated to approximately 750˚F (400˚C) in

ng point material in the bottom. Progressively higher boiling point material is present between the top and bottom of the tower. Heat is adde

fuel), diesel fuel, gas oil and resid. Atmospheric distillation units run at a pressure slightly above atmospheric in the overhead accumulator.

imately 750˚F (400˚C) in a fired heater and fed to the atmospheric distillation tower.

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 towe

e overhead accumulator. Temperatures above approximately 750˚F (400˚C) are avoided to prevent thermal cracking of crude oil into light ga

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

ng of crude oil into light gases and coke. With the exception of Coker units, the presence of coke in process units is undesirable because co

f the condensed liquid is returned to the tower as reflux. The continuous vaporization and condensation of material on each tray of the fract

s undesirable because coke deposit fouls refining equipment and severely reduces process performance.

al on each tray of the fractionation tower is what creates the separation of petroleum products within the tower.

Vaccum Distillation Units Atmospheric resid is further fractionated in a Vacuum Distillation tower. Products that exist as a liquid at atmospheric pressure Atmospheric resid is heated to approximately 750˚F (400˚C) in a fired heater and fed to the Vacuum Distillation tower where it

Typical products and their true boiling points (TBP) from crude oil distillation (i.e., both atmospheric and vacuum tower product

Light Naphtha Heavy Naphtha Kerosene Light Gas Oil Heavy Gas Oil Vacuum Gas Oil Vacuum Resid

Initial TBP Final TBP - ˚F (˚C) 80 (27) 200 (95) 200 (95) 380 (195) 355 (180) 500 (260) 470 (245) 650 (345) 630 (330) 800 (425) 775 (410) 1000 (540) 1000 (540)

quid at atmospheric pressure will boil at a lower temperature when pressure is significantly reduced. Absolute operating pressure in a Vacuu

um Distillation tower where it is fractionated into light gas oil, heavy gas oil and vacuum resid.

ric and vacuum tower products) are:

rating pressure in a Vacuum Tower can be reduced to 20 mm of mercury or less (atmospheric pressure is 760 mm Hg). In addition, superhe

Hg). In addition, superheated steam is injected with the feed and in the tower bottom to reduce hydrocarbon partial pressure to 10 mm of m

al pressure to 10 mm of mercury or less.

Naptha HDS/ Hydrotreater

Most catalytic reforming catalysts contain platinum as the active material. Sulfur and nitrogen compounds will deactivate the ca

Reactor conditions are relatively mild for Naphtha HDS at 400-500˚F (205-260˚C) and relatively moderate pressure 350-650 ps

If required, the boiling range of the Catalytic Reforming charge stock can be changed by redistilling in the Naphtha HDS. Often

unds will deactivate the catalyst and must be removed prior to catalytic reforming. The Naphtha HDS unit uses a cobalt-molybdenum cataly

erate pressure 350-650 psi (25-45 bar). As coke deposits on the catalyst, reactor temperature must be raised. Once the reactor temperature

n the Naphtha HDS. Often pentanes, hexanes and light naphtha are removed and sent directly to gasoline blending or pretreated in an Isom

obalt-molybdenum catalyst to remove sulfur by converting it to hydrogen sulfide that is removed with unreacted hydrogen.

ce the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement.

g 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

Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at moderately high pressures 500-1500 psi (35-1

Hydrogen is combined with feed either before or after it has been heated to reaction temperature. The combined feed enters th

Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free

Hydrogen sulfide and light ends are stripped from the desulfurized product. Hydrogen sulfide is sent to sour gas processing an

ur, nitrogen and aromatics by reacting them with hydrogen. Cobalt-molybdenum catalysts are used for desulphurization. When nitrogen rem

ssures 500-1500 psi (35-100 bar). As coke deposits on the catalyst, reactor temperature must be raised. Once the reactor temperature reac

e combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where

ed hydrocarbons and free metals. Metals remain on the catalyst and other products leave with the oil-hydrogen steam. Hydrogen is separat

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

ation. When nitrogen removal is required in addition to sulfur, nickel-molybdenum catalysts are used. In some instances, aromatics saturati reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement.

removal required, where it flows downward over a bed of metal-oxide catalyst

eam. Hydrogen is separated from oil in a product separator. water or discharge.

ances, aromatics saturation is pursued during the hydrotreating process in order to improve diesel fuel performance.

Diesel HDS/Hydrotreater

Hydrotreating is a catalytic process to stabilize products and remove objectionable elements like sulfur, nitrogen and aromatics

Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at moderately high pressures 500-1500 psi (35-1

Hydrogen is combined with feed either before or after it has been heated to reaction temperature. The combined feed enters th

Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free

Hydrogen sulfide and light ends are stripped from the desulfurized product. Hydrogen sulfide is sent to sour gas processing an

ur, nitrogen and aromatics by reacting them with hydrogen. Cobalt-molybdenum catalysts are used for desulphurization. When nitrogen rem

ssures 500-1500 psi (35-100 bar). As coke deposits on the catalyst, reactor temperature must be raised. Once the reactor temperature reac

e combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where

ed hydrocarbons and free metals. Metals remain on the catalyst and other products leave with the oil-hydrogen steam. Hydrogen is separat

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

ation. When nitrogen removal is required in addition to sulfur, nickel-molybdenum catalysts are used. In some instances, aromatics saturati reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst replacement.

removal required, where it flows downward over a bed of metal-oxide catalyst

eam. Hydrogen is separated from oil in a product separator. water or discharge.

ances, aromatics saturation is pursued during the hydrotreating process in order to improve diesel fuel performance.

Gas Oil HDS

Hydrotreating is a catalytic process to stabilize products and remove objectionable elements, particularly sulfur and nitrogen, b

Hydrogen is combined with feed either before or after it has been heated to reaction temperature. The combined feed enters th

Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen, saturated hydrocarbons and free

Hydrogen sulfide is sent to sour gas processing and water removed from the process is sent to sour water stripping prior to us

arly sulfur and nitrogen, by reacting them with hydrogen prior to feed to the FCC Unit. Most hydrotreating reactions take place between 600

e combined feed enters the top of a fixed bed reactor, or series of reactors depending on the level of contaminant removal required, where

ed hydrocarbons and free metals. Metals remain on the catalyst and other products leave with the oil-hydrogen steam. Hydrogen is separat

water stripping prior to use as desalter water or discharge.

s 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 se

removal required, where it flows downward over a bed of metal-oxide catalyst. For desulphurization, the most common catalysts are cobalt

eam. Hydrogen is separated from oil and hydrogen sulfide and light end are stripped from the desulfurized product.

on the level of reaction severity needed to meet product specification and the composition of the feedstock.

mmon catalysts are cobalt-molybdenum. When hydrodenitrofication (HDN) is desired in addition to desulfurization, nickel-molybdenum cataly

nickel-molybdenum catalysts are recommended.

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 imbala

The FCC process cracks heavy gas oils by breaking the carbon bonds in large molecules into multiple smaller molecules that b FCC reactions are promoted at high temperatures 950-1020˚F (510-550˚C) but relatively low pressures of 10-30 psi (1-2 bar). Feedstock gas oil is preheated and mixed with hot catalyst coming from the regenerator at 1200-1350˚F (650-735˚C). The hot

FCC products are more highly unsaturated than distillation products. Naphtha in the gasoline range has good octane. Distillate

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

use to correct the imbalance between the market demand for lighter petroleum products and crude oil distillation that produces an excess

e smaller molecules that boil in a much lower temperature range. The FCC can achieve conversions of 70-80% of heavy gas oil into produc

es of 10-30 psi (1-2 bar). At these temperatures, coke formation deactivates the catalyst by blocking reaction sites on the solid catalyst. The

0˚F (650-735˚C). The hot catalyst vaporizes the feedstock and heats it to reaction temperature. To avoid overcracking, which reduces yield

has good octane. Distillate range products have low pour points but poorer combustion qualities. Light end products are highly olefinic (unsa

components. Electrostatic precipitators and scrubbers are used to reduce air emissions. As air quality concerns grow, more equipment to re

that produces an excess of heavy, high boiling range products. The FCC unit converts heavy gas oil into gasoline and diesel.

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

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 fluidiz

king, which reduces yield at the expense of gasoline, reaction time is minimized. The primary reaction occurs in the transfer line (or riser) go

s are highly olefinic (unsaturated) and are used as feedstock for further upgrading processes like alkylation. With sulfur concentration of ga

ow, more equipment to reduce SOX and NOX are expected.

the benefit of producing a volume gain (i.e., combined product volumes are greater than the feed volume). Since most petroleum products

ow like a liquid in a fluidized bed - hence the name "Fluid Cat Cracker". Catalyst is continually circulated from the reactor to a regenerator w

e transfer line (or riser) going to the reactor. The primary purpose of the reactor is to separate catalyst from reaction products.

sulfur concentration of gasoline reducing, FCC products (gasoline and distillates) may require desulfurization through a HDS Unit prior to ble

most petroleum products are sold on a volume basis, this gain has a significant effect on refinery profitability.

eactor to a regenerator where coke is burned off in controlled combustion with air creating carbon monoxide, carbon dioxide, sulfur oxides (

ugh a HDS Unit prior to blending.

on dioxide, sulfur oxides (SOX) and nitrous oxides (NOX) as well as some other combustion products.


The Hydrocracker is similar to the FCC in that it is a catalytic process that cracks long chain gas oil molecules into smaller mol

Another difference is operating conditions. Hydrocrackers run at high temperature 650-800˚F (345-425˚C) and very high press

Typical feedstock to a Hydrocracker includes FCC cycle oil, coker gas oil and gas oil from crude distillation. Heavy naphtha fro

molecules into smaller molecules that boil in the gasoline, jet fuel and diesel fuel range. The fundamental difference is that cracking reactions

25˚C) and very high pressures of 1500-3000 psi (105-210 bar). Hydrocracker reactors contain multiple fixed beds of catalyst typically contain

lation. Heavy naphtha from the Hydrocracker makes excellent Catalytic Reformer feedstock. Distillates from Hydrocracking make excellent

e is that cracking reactions take place in an extremely hydrogen rich atmosphere. Two reactions occur. First carbon bonds are broken follow

of catalyst typically containing palladium, platinum, or nickel. These catalysts are poisoned by sulfur and organic nitrogen, so a high-severity

ocracking make excellent jet fuel blend stocks. Light ends are highly saturated and a good source of iso-butane for alkylation. The yield acro

n bonds are broken followed by attachment of hydrogen. Hydrocracker products are sulfur free and saturated.

trogen, so a high-severity HDS/HDN reactor pretreats feedstock prior to the hydrocracking reactors. Hydrocracker units may be configured

r alkylation. The yield across a Hydrocracker may exhibit volumetric gains as high as 20-25% making it a substantial contributor to refinery p

units may be configured in single stage or two stage reactor systems that enable a higher conversion of gas oil into lower boiling point mate

al contributor to refinery profitability.

to lower boiling point material.

ETP A 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 in the 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

Coker / Visbreaker

Coking and visbreaking are both thermal decomposition processes. Coking is predominant in the United States while Visbreak

With the exception of the coking process, formation of coke in a petroleum refinery is undesirable because coke fouls equipme

The most common form of the coking process in today's refineries is Delayed Coking where vacuum resid is thermally cracked

Vacuum resid is fed to the coker fractionator to remove as much light material as possible. Bottoms from the fractionator are h

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

Coker light products are highly unsaturated. Coker light ends are recovered as an olefin feed source for alkylation. Coker naph

Visbreaking is a milder form of thermal cracking often used to reduce the viscosity and pour point of vacuum resid in order to m

There is a tradeoff between furnace temperature and residence time for visbreaking operations. Longer residence time leads t

ted States while Visbreaking is mostly applied in Europe.

cause coke fouls equipment and reduces catalyst activity. However, in the coking process, coke is intentionally produced as a byproduct of

resid is thermally cracked into smaller molecules that boil at lower temperatures. Products include naphtha, gas oils and coke. Light produc

rom the fractionator are heated in a direct fired furnace to more than 900˚F (480˚C) and discharged into a coke drum where thermal crackin

val. Coke removal involves steaming, quenching, hydraulic cutting to remove solid coke from the drum and vessel preparation for return to s

for alkylation. Coker naphtha requires desulfurization before upgrade in the Catalytic Reforming Unit. Coker gas oils are generally sent to th

vacuum resid in order to meet specification for heavy fuel oil. Visbreaking helps avoid the use of expensive cutter stock required for dilution.

ger residence time leads to lower furnace outlet temperatures. In general, operations are conducted between 800-930˚F (425-500˚C). Mater

duced as a byproduct of vacuum resid conversion from low value fuel and asphalt into higher value products.

ils and coke. Light product yield varies by feedstock but is generally around 75% conversion. Coke is sold as a fuel or specialty product into

um where thermal cracking is completed. High velocity and stream injection are used to minimize coke formation in furnace tubes. Coke dep

preparation for return to service.

ils are generally sent to the Hydrocracker for upgrade.

stock required for dilution. The process is carefully controlled to predominantly crack long paraffin chains off aromatic compounds while avo

930˚F (425-500˚C). Material is quenched with cold gas oil to stop the cracking process. Pressure is important to unit design and ranges betw

l or specialty product into the steel and aluminum industry after calcining to remove impurities.

n furnace tubes. Coke deposits in the drum and cracked products are sent to the fractionator for recovery. Coke drums typically operate in th

atic compounds while avoiding coking reactions.

nit design and ranges between 300-750 psi (20-50 bar).

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

atmospheric in the overhead accumulator. Fractionator bottoms are recycled through the furnace to extinction.


The Amine Treating Unit removes CO2 and H2S from sour gas and hydrocarbon streams in the Amine Contactor. The Amine (

The sour gas streams enter the bottom of the Amine Contactor. The cooled lean amine is trim cooled and enters the top of the The Rich Amine Surge Drum allows separation of hydrocarbon from the amine solution. Condensed hydrocarbons flow over a

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

Acid gas, primarily H2S and water vapor from the regenerator is cooled in the Amine Regenerator Overhead Condenser. The m The Amine Regenerator Reflux Pump, pumps the condensate in the Regenerator Accumulator, mainly water, to the top tray of

Lean amine solution from the Amine Regenerator is cooled in the Lean/Rich Exchanger. A slipstream of rich amine solution pa

e Contactor. The Amine (MDEA) is regenerated in the Amine Regenerator, and recycled to the Amine Contactor. 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

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 Exchan

mine Regenerator Reboiler supplies the necessary heat to strip H2S and CO2 from the rich amine, using steam as the heating medium.

erhead Condenser. The mixture of gas and condensed liquid is collected in the Amine Regenerator Overhead Accumulator. The uncondens

y water, to the top tray of the Amine Regenerator A portion of the pump discharge is sent to the sour water tank.

of rich amine solution passes through a filter to remove particulates and hydrocarbons, and is returned to the suction of the pump. The lean

. An acid-gas-rich-amine solution leaves the bottom of the column at an elevated temperature, due to the exothermic absorption reaction. T Lean/Rich Amine Exchanger. the heating medium.

umulator. The uncondensed gas is sent to Sulfur Recovery.

tion of the pump. The lean amine is further cooled in the Lean Amine Air Cooler, before entering the Amine Contactor.

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

mine Contactor.

Needle Coke Unit Needle Coke is a premium grade, high value petroleum coke, used in the manufacturing of graphite electrodes for the arc furn

The technology is primarily focused on production of needle coke in any existing delayed coker unit using heavier hydrocarbon

The maximum limits of sulfur and ash in calcined needle coke are 0.6 and 0.3 wt% respectively. Higher sulfur content of coke c

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

electrodes for the arc furnaces in the metallurgy industry. Its hardness is due to the dense mass formed with a structure of carbon threads o

using heavier hydrocarbon streams without any costly pre-treatment. Formation of needle coke requires specific feedstocks, special coking a

er sulfur content of coke can cause the puffing of electrode. High ash content can increase the resistivity and decrease electrode strength.

otreater unit and/or having RFCC/ FCC unit processing low sulfur feed are suitable for considering this technology.

cture of carbon threads or needles oriented in a single direction. Needle coke is highly crystalline and can provide the properties needed fo

edstocks, special coking and also special calcination conditions. If feedstocks are suitable for needle coke, process conditions for coking an

ease electrode strength. The calcined coke with higher sulfur and ash content is not considered suitable for manufacturing of graphite elect

the properties needed for manufacturing graphite electrode. It can withstand temperatures as high as 28000C.

s conditions for coking and calcination are selected to improve the properties and yield of the needle coke. Typical yield of needle coke is 1

facturing of graphite electrode even if other properties meet the quality of premium grade coke. Thus, the quality and price of needle coke a

l yield of needle coke is 18-30 wt% of fresh feed.

nd price of needle coke are highly dependent on the properties of feedstock used for coking.

Catalytic Reforming

Gasoline has a number of specifications that must be satisfied to provide high performance for today's motor vehicles. Octane Unfortunately, heavy naphtha from atmospheric distillation, which forms a significant percentage of the gasoline blend, has an

In short, Catalytic Reforming converts straight chain and saturated molecules into unsaturated cyclic and aromatic compounds

Reforming uses platinum catalyst. Sulfur poisons the catalyst; therefore, virtually all sulfur must be removed prior to reforming.

s motor vehicles. Octane, however, is the most widely recognized specification. The octane number is generally reported as the average of

he 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. Cataly

and aromatic compounds. In doing so, it liberates a significant amount of hydrogen that may be used in desulfurization and saturation react

moved prior to reforming. Temperature is used to control produced octane. The unit is operated at temperatures between 925-975˚F (500-5

eported as the average of Research Octane Number (RON) and Motor Octane Number (MON), (R+M)/2. MON is the more severe test, so f

to mid 90 (R+M)/2. Catalytic Reforming is the workhorse for octane upgrade in today's modern refinery. Molecules are reformed into structu

ation and saturation reactions elsewhere in the refinery. In addition to hydrogen and reformate, some light ends are removed to meet vapor

etween 925-975˚F (500-525˚C) and pressures between 100-300 psi (7-25 bar). Reformer octane is generally controlled between 90 and 95

he more severe test, so for a given fuel RON is always higher than MON.

are reformed into structures that increase the percentage of high octane components while reducing the percentage of low octane compon

e removed to meet vapor pressure requirements. Catalytic Reforming creates a density increase (i.e., finished product volume is significant

rolled between 90 and 95 (R+M)/2 depending on gasoline blending demands. As a result of very high reactor temperatures, coke forms on t

age of low octane components.

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

peratures, coke forms on the catalyst, which reduces activity. Coke must either be removed continuously (Continuous Catalyst Regeneration

ous Catalyst Regeneration CCR Units) or periodically (Semi-regenerative Units) to maintain performance.


Catalytic reforming has little effect on Light Straight Run gasoline (LSR), which is material in the C5 - 165˚F (74˚C) boiling rang

Isomerization can result in a significant octane increase since n-pentane has a research octane number (RON) of 62 and iso-p

Isomerization catalysts contain platinum and, like reforming, must have all sulfur removed. Additionally, some catalysts require

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

165˚F (74˚C) boiling range. This fraction is removed from reformer feed. Its octane number may be significantly improved by converting nor

ber (RON) of 62 and iso-pentane has a RON of 92. Once through isomerization can increase LSR gasoline octane from 70 to around 82 RO

ly, some catalysts require continuous additions of small amounts of organic chlorides to maintain activity. Organic chlorides are converted to

ane can be made from n-butane using isomerization.

mproved by converting normal paraffins into their isomers in the Isomerization Unit.

e from 70 to around 82 RON.

chlorides are converted to hydrochloric acid; therefore, Isomerization feed must be free of water to avoid serious corrosion problems. Other

orrosion problems. Other catalysts use a molecular sieve base and are reported to tolerate water better. Isomerization uses reaction tempe

ation uses reaction temperatures of 300-400˚F (150-200˚C) at pressures of 250-400 psi (17-27 bar).

Propylene Recovery Unit


Alkylation is a refining process that provides an economic outlet for very light olefins produced at the FCC and Coker. Alkylatio

In the Alkylation Unit, propylene, butylenes and sometimes pentylenes (also known as amylenes) are combined with iso-butan

Sulfuric Acid Alkylation runs at 35-60˚F (2-15˚C) to minimize polymerization reactions while HF Alkylation, which is less sensitiv

Alkylation products are distilled to remove propane, iso-butane and alkylate. Sulfuric acid sludge must be removed and regene

FCC and Coker. Alkylation is the opposite of cracking. The process takes small molecules and combines them into larger molecules with hi

combined with iso-butane in the presence of a strong acid catalyst (either hydrofluoric (HF) or sulfuric acid) to form branched, saturated mo

tion, which is less sensitive to polymerization reactions, runs at 70-100˚F (20-38˚C). Chilling or refrigeration is required to remove heat of re

st be removed and regenerated. HF is neutralized with KOH, which may be regenerated and returned to the process.

o larger molecules with high octane and low vapor pressure characteristics.

m branched, saturated molecules. Alkylate has an octane around 95 (R+M)/2 and low vapor pressure making it a valuable gasoline blending

uired to remove heat of reaction.

valuable gasoline blending component particularly for premium grade products. It contains no olefins, aromatics or sulfur.

Merox Treatment Technical Profile

Merox is a process to sweeten products by extracting and/or converting mercaptan sulfur to less objectionable disulfides. It is o

Hydrogen sulfide free feed is contacted with caustic in a counter-current extraction column. Sweet product exits the column ov

When removal of mercaptan sulfur is not required, "sweetening" may be applied to improve odor where mercaptan sulfur is co

ctionable disulfides. It is often used to treat products such as liquefied petroleum gases, naphtha, gasoline, kerosene, jet fuel and heating o

oduct exits the column overhead and caustic/extracted mercaptans exit the column bottom as extract. Air and possibly catalyst are mixed w

ere mercaptan sulfur is converted to disulfide and carried out with the petroleum product. For sweetening, dilute caustic is added to the prod

ene, jet fuel and heating oils.

sibly catalyst are mixed with extract and sent to an oxidation reactor where caustic is regenerated and mercaptans are converted to disulfide

ustic is added to the product prior to air injection. Combined feed enters a fixed bed reactor where a catalyst oxidizes mercaptan sulfur into

are converted to disulfides. Disulfides are insoluble in water and can be removed in a product separator that vents excess air and gas for d

zes mercaptan sulfur into disulfides. Caustic is removed from the bottom of the reactor and wasted to the sewer or spent caustic treatment.

s excess air and gas for disposal or destruction and separates sulfide oil, which may be returned to the refining process, from regenerated c

r spent caustic treatment.

ocess, from regenerated caustic, which is returned to the extraction column. Over time caustic will become spent and must be wasted to oth

and must be wasted to other refinery uses or to spent caustic destruction.

Sour Water Stripper

Stripping steam and wash water in various refining operations is condensed and removed from overhead condensate accumu By varying the pH of the feed solution, hydrogen sulfide may be removed for amine treatment and ammonia may be removed

ead condensate accumulators or product separators. This water contains impurities most notably sulfur compounds and ammonia. Hydrog

mmonia may be removed for reuse or neutralization in separate strippers. Once stripped of contaminants, water is either reused for desalter

ds and ammonia. Hydrogen sulfide and ammonia are removed in the sour water stripper.

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 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 Cla

ves combusting one-third of the hydrogen sulfide (H2S) into SO2 and then reacting the SO2 with the remaining H2S in the presence of coba

ulfur 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

2S in the presence of cobalt-molybdenum catalyst to form elemental sulfur.

2S 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 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.


Petroleum refineries produce a variety of components that are then used to blend refined products. Product blending is a critic

Gasoline is not a single product. Refiners blend hundreds of different specifications. In addition to the different grades of gasol

Key to good gasoline performance is octane, vapor pressure (Reid Vapor Pressure - RVP) and distillation range of the blend. B

ComponentRVP MON Iso-butane 71 92 n-butane 52 92 Iso-pentan 19.4 90.8 n-pentane 14.7 87.2 Iso-hexane 6.4 78.4 LSR 11.1 61.6 Isomerate 13.5 81.1 Hydrocrack 1.7 75.6 Coker Nap 3.6 FCC Gasol 4.4 76.8 Reformate 2.8 84.4 Reformate 4.2 88.2 Alkylate, C 4.6 95.9 Alkylate, C 1.0 88.88

RON 93.0 93.0 93.2 71.5 79.2 66.4 83 79 67.2 92.3 94.0 100 97.3 89.7

Gravity, ˚API 120 111 95 88.9 76.5 78.6 80.4 55.5 57.2 57.2 45.8 41.2 70.3 -

Product blending is a critical source of flexibility and profitability for refining operations. Of great interest is the economic blending of gasoline

e different grades of gasoline we all see at the retail pump, gasoline is subject to different specifications based on country, geographic locati

ation range of the blend. Below is a table of octane, RVP and specific gravity blending values for some typical gasoline blending component

omic blending of gasoline.

country, geographic location, season, humidity, altitude, and environmental regulations. This further complicates distribution systems with ad

oline blending components:

stribution systems with additional requirements for low sulfur, conventional, reformulated and oxygenated "boutique" blends.

The Gas Plant

Light ends are hydrocarbons boiling at the lowest temperatures including methane, ethane, propane, butanes, and pentanes, w

Unsaturated light ends, containing ethylene, propylene, butylenes and pentylenes (from the Fluidized Catalytic Cracking Unit a 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

The Gas Plant will remove the light hydrocarbons from the Naphtha Unit product. Lean oil is used to absorb and recover the pr

Distillation columns are used to separate these gases in the same way as the Crude column. The lighter boiling point materials

butanes, and pentanes, which contain from one to five carbon atoms. Light ends are fractionated in distillation towers and treated with amin Catalytic Cracking Unit and Coker Unit), are fractionated separately from saturated light ends (from Crude Distillation, Hydrocracking, and

absorb and recover the propane and butane to allow the hydrogen, methane, ethane and hydrogen sulfide to be sent overhead as fuel gas.

hter boiling point materials leave the top and the heavier ones leave through the bottom of the tower. In addition, the mixed butanes and iso

wers and treated with amine contacting to remove hydrogen sulfide. The most abundant source of lights ends is cracking operations.

tion, Hydrocracking, and Catalytic Reforming).

ent overhead as fuel gas. The remaining liquid will be separated out into propane, iso-butane, butane, light naphtha and heavy naphtha.

he mixed butanes and iso-butane are sent the Alklyation Unit. The heavy naphtha is also sent to the Reformer for upgrading.

acking operations.

a and heavy naphtha.

Product Blending

Refined products are typically the result of blending several component streams or blend stocks. Intermediate product qualities

While gasoline blending consumes the most time and effort, other products are blended for sale as well. Examples of other pro

rmediate product qualities are measured and appropriate volumes are mixed into finished product storage using either batch operations or

well. Examples of other products include jet fuel, diesel fuel, fuel oil, and lubricants to name a few. Properties include flash point, aniline poin

ither batch operations or "in-line" blending methods.

de flash point, aniline point, cetane number, pour point, smoke point, viscosity index and others. Many of these properties do not blend linea

perties do not blend linearly, so finished properties must be predicted using sophisticated math models and experience-based algorithms. T

ence-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,

These processes include the production of hydrogen, the removal of sulfur from water and gas, the production of steam and th

ng intermediate products, yet play a critical supporting role. Without them a petroleum refinery would not be able to exist.

roduction 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 req

By blowing, the asphaltenes are partially dehydrogenated (oxidised) and form larger chains of asphaltenic molecules via polym

The blowing process is carried out continuously in a blowing column. The liquid level in the blowing column is kept constant by

market product quality requirements. Authorities and industrial users have formulated a variety of bitumen grades with often stringent quality

tenic molecules via polymerisation and condensation mechanism. Blowing will yield a harder and more brittle bitumen (lower penetration, h

olumn 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

with often stringent quality specifications, such as narrow ranges for penetration and softening point. These special grades are manufacture

men (lower penetration, higher softening point), not by stripping off lighter components but changing the asphaltenes phase of the bitumen.

d thus the product quality) by controlling both air supply and feed supply rate. The feed to the blowing unit (at approximately 210 0C), enter

l grades are manufactured by blowing air through the hot liquid bitumen in a BITUMEN BLOWING UNIT

es phase of the bitumen. The bitumen blowing process is not always successful: a too soft feedstock cannot be blown to an on-specification

roximately 210 0C), enters the column just below the liquid level and flows downward in the column and then upward through the draw-off p

own to an on-specification harder grade.

ard 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 bitum

m 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 mix

This, together with the mixing effect of the air bubbles jetting through the molten mass, will minimise the temperature effects of the exotherm

re effects of the exothermic oxidation reactions: local overheating and cracking of bituminous material. The blown bitumen is withdrawn con

bitumen is withdrawn continuously from the surge vessel under level control and pumped to storage through feed/product heat exchangers

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

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