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

Refinery Process

Executive Summary
The refining process depends on the chemical processes of distillation (separating liquids
by their different boiling points) and catalysis (which speeds up reaction rates), and uses
the principles of chemical equilibria. Chemical equilibrium exists when the reactants in a
reaction are producing products, but those products are being recombined again into
reactants. By altering the reaction conditions the amount of either products or reactants
can be increased.
Refining is carried out in three main steps.
Step 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

Prepared By- Tendering Estimation Dept.

Essar Constructions India Ltd.


REFINERY PROCESS FLOW CHART

ARU
Amine Recovery
Unit

Fuel Gas

Light Gas

Refinery Fuel/Fuel Gas
Sr
SRU
Sulphur Recover
Unit

H2S

Gas Processing

Sulphur

Propane
LPG
Butane

Merox Unit

H2

Desalted
Crude

ISOM
Light Naptha
Isomerisation

NHTU

Naptha Hydrotreate
Unit

Heavy
Naptha

Naptha

Gasolines Blending

CCR
Continuos Catalytic
Reformer

Super Premium Unleaded
Premiun unleaded
Unleaded

Supporting Units

H2S to SRU

Kerosene
Jet Fuel

ATF HDTATF Hydrotreater

Diesel Oil

DHDT

Diesel Hydrotreater

ATF MEROX
Aviation Turbine
Fuel Merox

Jet Fuel/
Kerosene

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

H2S
Diesel

Diesel Fuel
Stripped Water

Gas Oil
Propane
Poly Unit
Reduced
Crude

ETP

Butane
PRU

Light Vaccume
Gas Oil

VGO-HDT
Vaccume Gas Oil
Hydotreater

(FCCU) Fluid
Catalytic Cracking
Units

Alkylation
Unit

CO2

Propylene
Propylene

C3/C4
To Hydrocracker
&
Hydrotreater

Diesel
Heavy Vaccume Gas Oil

I Butane

Hrdrocracker

Gasoline

Neddle Coke
Unit
Vaccume
Residuel

DCU- Delayed Coker
Unit

Coker Naptha to CCR

PREPARED BY:- TENDERING ESTIMATION TEAM

Natural Gas

Steam

Premier Coke

PREPARED BY:-

Coker Gas Oil to FCCU
Petroleum Coke

Bitumen
Blowing

H2

HMU- Hydrogen
Manufacturing Unit

(VDU) Vaccume Distillation Unit

Heating

Light
Naptha

(CDU)Crude Distillation Unit / Atmospheric Distillation Uni t

Desalter

H2

NHTU
Naptha Hydrotreate
Unit

Units Name
AGS- Air Generation System
AGU- Acid Generation Unit
ARU- Amine Recovery Unit
ATF Merox- Aviation Turbine Fuel Merox
ATF-HDT- Aviation Turbine Fuel Hydrotreater
CCR- Continuous Catalytic Reformer
CDU- Crude Distillation Unit
DCU-Delayed Crocker Unit
Desal/Demin Plant

DHDT- Diesel Hydrotreating
ETP- Effluent Treatment Plant
FCCU- Fluid Catalytic Cracker Unit
GMU- Gasoline Merox Unit
HMU- Hydrogen Manufacturing Unit
NCU-Needle Coke Unit
NHT- Naptha Hydrotreater
PRU- Propylene Recovery Unit
SGU-Saturated Gas Unit
SRU- Sulphur Recoveru Unit
SS&H- Sulphur Storage & Handling
SWS- Sour Water Stripper
UGS- Unsaturated Gas Seperation Unit
VBS- Visbreaker Unit
VDU- Vaccume Distillation Unit
VGO-HDT- Vaccume Gas Hydrotreater

sws- Sour Water
Stripper

Crude Oil Storage
Tank

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TENDERING & ESTIMATION TEAM
ESSAR CONSTRUCTIONS INDIA LTD.
KURLA, MUMBAI

BITUMEN
(Road, Roofing, waterproofing)

ESSAR CONSTRUCTIONS INDIA LTD. MUMBAI


Crude Oil Storage

Crude Oil Storage
In almost all cases, crude oils have no inherent value without petroleum refining processes to convert
them into marketable products. Crude oil is a complex mixture of hydrocarbons that also contains sulfur,
nitrogen, heavy metals and salts. Most of these contaminants must be removed in part or total during the
refining process. The hydrocarbons that make up crude oil have boiling points from less than 60˚F to
greater than 1200˚F (60-650˚C).
Crude oil varies in sulfur content. Higher sulfur crude oil is more corrosive than lower sulfur crude oils.
In order to process higher sulfur crude oils, equipment must be built from more expensive alloys to
provide higher corrosion resistance. Many refineries are not able to process crude oils with high sulfur
The American Petroleum Institute (API) has developed a characterization for the density of crude oils:
˚API = (141.5/Specific Gravity@60˚F) -131.5
When comparing crude oils, the crude oil with the higher API will be easier to refine than one with a lower
API.
Crude oil is delivered to a refinery by marine tanker, barge, pipeline, trucks and rail. The level of BS&W
(bituminous sediment and water) is monitored to avoid high levels of water and solids. Water separates
from crude oil as it sits in tanks waiting to be refined. This water is generally drained to waste water
treatment just prior to processing.

Process Chart


Desalting
All crude oil contains salt, predominantly chlorides. Chloride salts can combine with water to form
hydrochloric acid in atmospheric distillation unit overhead systems causing significant equipment
damage and processing upsets. Chlorides and other salts will also deposit on heat exchanger surfaces
reducing energy efficiency and increasing equipment repairs and cleaning.
Salt must be removed from crude oil prior to processing. Crude oil is pumped from storage tanks and
preheated by exchanging heat with atmospheric distillation product streams to approximately 250˚F
(120˚C). Inorganic salts are removed by emulsifying crude oil with water and separating them in a desalter.
Salts are dissolved in water and brine is removed using an electrostatic field and sent to the waste water

treatment.

Process Chart


Atmosheric Distillation Unit/ Crude Distillation Unit
CDU
Initial crude oil separation is accomplished by creating a temperature and pressure profile across a tower to enable
different composition throughout the tower.
Desalted crude oil is preheated to a temperature of 500-550˚F (260-290˚C) through heat exchange with distillation
products, internal recycle streams and tower bottoms liquid. Finally, the crude oil is heated to approximately 750˚F
(400˚C) in a fired heater and fed to the atmospheric distillation tower.
Distillation concentrates lower boiling point material in the top of the distillation tower and higher boiling point
material in the bottom. Progressively higher boiling point material is present between the top and bottom of the
tower. Heat is added to the bottom of the tower using a reboiler that vaporizes part of the tower bottom liquid and
returns it to the tower. Heat is removed from the top of the tower through an overhead condenser. A portion of the
condensed liquid is returned to the tower as reflux. The continuous vaporization and condensation of material on
each tray of the fractionation tower is what creates the separation of petroleum products within the tower.

The most common products of atmospheric distillation are fuel gas, naphtha, kerosene (including jet fuel), diesel
fuel, gas oil and resid. Atmospheric distillation units run at a pressure slightly above atmospheric in the overhead
accumulator. Temperatures above approximately 750˚F (400˚C) are avoided to prevent thermal cracking of crude oil
into light gases and coke. With the exception of Coker units, the presence of coke in process units is undesirable
because coke deposit fouls refining equipment and severely reduces process performance.


Vaccum Distillation Units
Atmospheric resid is further fractionated in a Vacuum Distillation tower. Products that exist as a liquid at
atmospheric pressure will boil at a lower temperature when pressure is significantly reduced. Absolute
operating pressure in a Vacuum Tower can be reduced to 20 mm of mercury or less (atmospheric

pressure is 760 mm Hg). In addition, superheated steam is injected with the feed and in the tower bottom
to reduce hydrocarbon partial pressure to 10 mm of mercury or less.
Atmospheric resid is heated to approximately 750˚F (400˚C) in a fired heater and fed to the Vacuum
Distillation tower where it is fractionated into light gas oil, heavy gas oil and vacuum resid.
Typical products and their true boiling points (TBP) from crude oil distillation (i.e., both atmospheric and
vacuum tower products) are:


Naptha HDS/ Hydrotreater
Most catalytic reforming catalysts contain platinum as the active material. Sulfur and nitrogen
compounds will deactivate the catalyst and must be removed prior to catalytic reforming. The Naphtha
HDS unit uses a cobalt-molybdenum catalyst to remove sulfur by converting it to hydrogen sulfide that is
removed with unreacted hydrogen.
Reactor conditions are relatively mild for Naphtha HDS at 400-500˚F (205-260˚C) and relatively moderate
pressure 350-650 psi (25-45 bar). As coke deposits on the catalyst, reactor temperature must be raised.
Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for shutdown and catalyst
replacement.
If required, the boiling range of the Catalytic Reforming charge stock can be changed by redistilling in
the Naphtha HDS. Often pentanes, hexanes and light naphtha are removed and sent directly to gasoline
blending or pretreated in an Isomerization Unit prior to gasoline blending.


Kerosene HDS/ Hydrotreater
Hydrotreating is a catalytic process to stabilize products and remove objectionable elements
like sulfur, nitrogen and aromatics by reacting them with hydrogen. Cobalt-molybdenum
catalysts are used for desulphurization. When nitrogen removal is required in addition to
sulfur, nickel-molybdenum catalysts are used. In some instances, aromatics saturation is
pursued during the hydrotreating process in order to improve diesel fuel performance.
Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at moderately high
pressures 500-1500 psi (35-100 bar). As coke deposits on the catalyst, reactor temperature

must be raised. Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for
shutdown and catalyst replacement.
Hydrogen is combined with feed either before or after it has been heated to reaction
temperature. The combined feed enters the top of a fixed bed reactor, or series of reactors
depending on the level of contaminant removal required, where it flows downward over a bed
of metal-oxide catalyst
Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen,
saturated hydrocarbons and free metals. Metals remain on the catalyst and other products
leave with the oil-hydrogen steam. Hydrogen is separated from oil in a product separator.
Hydrogen sulfide and light ends are stripped from the desulfurized product. Hydrogen sulfide
is sent to sour gas processing and water removed from the process is sent to sour water
stripping prior to use as desalter water or discharge.


Diesel HDS/Hydrotreater
Hydrotreating is a catalytic process to stabilize products and remove objectionable elements
like sulfur, nitrogen and aromatics by reacting them with hydrogen. Cobalt-molybdenum
catalysts are used for desulphurization. When nitrogen removal is required in addition to
sulfur, nickel-molybdenum catalysts are used. In some instances, aromatics saturation is
pursued during the hydrotreating process in order to improve diesel fuel performance.
Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at moderately high
pressures 500-1500 psi (35-100 bar). As coke deposits on the catalyst, reactor temperature
must be raised. Once the reactor temperature reaches ~750˚F (400˚C), the unit is scheduled for
shutdown and catalyst replacement.
Hydrogen is combined with feed either before or after it has been heated to reaction
temperature. The combined feed enters the top of a fixed bed reactor, or series of reactors
depending on the level of contaminant removal required, where it flows downward over a bed
of metal-oxide catalyst
Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen,
saturated hydrocarbons and free metals. Metals remain on the catalyst and other products

leave with the oil-hydrogen steam. Hydrogen is separated from oil in a product separator.
Hydrogen sulfide and light ends are stripped from the desulfurized product. Hydrogen sulfide
is sent to sour gas processing and water removed from the process is sent to sour water
stripping prior to use as desalter water or discharge.


Gas Oil HDS
Hydrotreating is a catalytic process to stabilize products and remove objectionable elements,
particularly sulfur and nitrogen, by reacting them with hydrogen prior to feed to the FCC Unit.
Most hydrotreating reactions take place between 600-800˚F (315-425˚C) and at relatively high
pressures up to 2000 psi (138 bar) depending on the level of reaction severity needed to meet
product specification and the composition of the feedstock.
Hydrogen is combined with feed either before or after it has been heated to reaction
temperature. The combined feed enters the top of a fixed bed reactor, or series of reactors
depending on the level of contaminant removal required, where it flows downward over a bed
of metal-oxide catalyst. For desulphurization, the most common catalysts are cobaltmolybdenum. When hydrodenitrofication (HDN) is desired in addition to desulfurization, nickelmolybdenum catalysts are recommended.
Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur, ammonia from nitrogen,
saturated hydrocarbons and free metals. Metals remain on the catalyst and other products
leave with the oil-hydrogen steam. Hydrogen is separated from oil and hydrogen sulfide and
light end are stripped from the desulfurized product.
Hydrogen sulfide is sent to sour gas processing and water removed from the process is sent
to sour water stripping prior to use as desalter water or discharge.


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 molecules

into 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
profitability.
FCC reactions are promoted at high temperatures 950-1020˚F (510-550˚C) 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 products.
Feedstock gas oil is preheated and mixed with hot catalyst coming from the regenerator at
1200-1350˚F (650-735˚C). 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
through a HDS Unit prior to blending.
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.

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 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 650-800˚F
(345-425˚C) 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 boiling point 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 a
Hydrocracker may exhibit volumetric gains as high as 20-25% making it a substantial
contributor to refinery profitability.


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 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 conversion
from 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 900˚F (480˚C)
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 pour
point 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 800-930˚F (425-500˚C). Material is quenched with cold gas
oil to stop the cracking process. Pressure is important to unit design and ranges between 300750 psi (20-50 bar).


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 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.
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.


Needle Coke Unit
Needle 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 pretreatment. 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.


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 components.
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 vapor
pressure 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
operations.
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 925-975˚F (500-525˚C) and pressures between 100300 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 performance.


Isomerization
Catalytic reforming has little effect on Light Straight Run gasoline (LSR), which is material in
the C5 - 165˚F (74˚C) boiling range. This fraction is removed from reformer feed. Its octane
number may be significantly improved by converting normal paraffins into their isomers in the
Isomerization Unit.
Isomerization can result in a significant octane increase since n-pentane has a research
octane number (RON) of 62 and iso-pentane has a RON of 92. Once through isomerization can
increase LSR gasoline octane from 70 to around 82 RON.
Isomerization catalysts contain platinum and, like reforming, must have all sulfur removed.
Additionally, some catalysts require continuous additions of small amounts of organic
chlorides to maintain activity. Organic chlorides are converted to hydrochloric acid; therefore,
Isomerization feed must be free of water to avoid serious corrosion problems. Other catalysts
use a molecular sieve base and are reported to tolerate water better. Isomerization uses
reaction temperatures of 300-400˚F (150-200˚C) at pressures of 250-400 psi (17-27 bar).
For refineries that do not have hydrocracking facilities to supply iso-butane for alkylation feed,
iso-butane can be made from n-butane using isomerization.


Propylene Recovery Unit



Alkylation
Alkylation is a refining process that provides an economic outlet for very light olefins

produced at the FCC and Coker. Alkylation is the opposite of cracking. The process takes
small molecules and combines them into larger molecules with high octane and low vapor
pressure characteristics.
In the Alkylation Unit, propylene, butylenes and sometimes pentylenes (also known as
amylenes) are combined with iso-butane in the presence of a strong acid catalyst (either
hydrofluoric (HF) or sulfuric acid) to form branched, saturated molecules. Alkylate has an
octane around 95 (R+M)/2 and low vapor pressure making it a valuable gasoline blending
component particularly for premium grade products. It contains no olefins, aromatics or
sulfur.
Sulfuric Acid Alkylation runs at 35-60˚F (2-15˚C) to minimize polymerization reactions while HF
Alkylation, which is less sensitive to polymerization reactions, runs at 70-100˚F (20-38˚C).
Chilling or refrigeration is required to remove heat of reaction.
Alkylation products are distilled to remove propane, iso-butane and alkylate. Sulfuric acid
sludge must be removed and regenerated. HF is neutralized with KOH, which may be
regenerated and returned to the process.


Merox Treatment
Technical Profile
Merox is a process to sweeten products by extracting and/or converting mercaptan sulfur to
less objectionable disulfides. It is often used to treat products such as liquefied petroleum
gases, naphtha, gasoline, kerosene, jet fuel and heating oils.
Hydrogen sulfide free feed is contacted with caustic in a counter-current extraction column.
Sweet product exits the column overhead and caustic/extracted mercaptans exit the column
bottom as extract. Air and possibly catalyst are mixed with extract and sent to an oxidation
reactor where caustic is regenerated and mercaptans are converted to disulfides. Disulfides
are insoluble in water and can be removed in a product separator that vents excess air and
gas for disposal or destruction and separates sulfide oil, which may be returned to the refining
process, from regenerated caustic, which is returned to the extraction column. Over time
caustic will become spent and must be wasted to other refinery uses or to spent caustic

destruction.
When removal of mercaptan sulfur is not required, "sweetening" may be applied to improve
odor where mercaptan sulfur is converted to disulfide and carried out with the petroleum
product. For sweetening, dilute caustic is added to the product prior to air injection.
Combined feed enters a fixed bed reactor where a catalyst oxidizes mercaptan sulfur into
disulfides. Caustic is removed from the bottom of the reactor and wasted to the sewer or
spent caustic treatment.


Sour Water Stripper
Stripping steam and wash water in various refining operations is condensed and removed
from overhead condensate accumulators or product separators. This water contains
impurities most notably sulfur compounds and ammonia. Hydrogen sulfide and ammonia are
removed in the sour water stripper.
By varying the pH of the feed solution, hydrogen sulfide may be removed for amine treatment
and ammonia may be removed for reuse or neutralization in separate strippers. Once stripped
of contaminants, water is either reused for desalter water or discharged directly to waste
water treatment facilities.


Sulfur Recovery
The sulfur recovery process used in most refineries is a "Claus Unit". In general, the Claus
Unit involves combusting one-third of the hydrogen sulfide (H2S) into SO2 and then reacting
the SO2 with the remaining H2S in the presence of cobalt-molybdenum catalyst to form
elemental sulfur.
The conversion chemistry is:
2H2H2S + 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.


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.