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Establishment, Growth and Development of KNPC

Established in October 1960 as a share-holding company owned by the Kuwait government and

private sector, KNPC became fully government-owned in 1975. Since 1968 the company had been

exporting petroleum products from its Shuaiba Refinery. In 1980, following the restructuring of the

oil sector in Kuwait, KNPC was placed under the newly-created Kuwait Petroleum Corporation (KPC),

which was also government owned. Under this position, KNPC took control of distributing petroleum

products within Kuwait, along with the ownership of the Mina Ahmadi and Mina Abdullah refineries.

KNPC - Future projects (As per KPC 2030 downstream vision)

New Refinery Project

Clean Fuel Project

KNPC - Emerging Scenario

Shifting product demand

Stringent product specifications

Stringent environmental regulations

Feedstock quality deterioration

Future Technological Challenges

Meeting higher demand of light petroleum fractions (viz. distillates)

Meeting higher standards of product qualities

More emphasis on environment

Value addition to refineries

Technologies to improve margins

Zero emission refinery

Capacity Increase (To Meet Demand of Petroleum Products )

Low cost revamps/ addition of units

Run length improvement of units

http://en.wikipedia.org/wiki/Kuwait_Petroleum_Corporationhttp://en.wikipedia.org/wiki/Kuwait_Petroleum_Corporation

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Crude Oil Characteristics and its Significance

Crude oils are formed by the action of geological processes on the remains of ancient marine life. It is

a complex mixture of hydrocarbons and over 16,000 compounds have been identified in one sample.

Composition varies widely:

By geographical location

Mix of individual wells

Variance of wells with time

Chemistry of Petroleum

Crude oil contains almost all known hydrocarbons and non-hydrocarbons. As it drawn from earth, it

also contains impurities like H2O, mud & salts which get associated during its production and

transportation. Crude oil, the basic raw material of refining industry, is a mixture of eight different

hydrocarbon families:

i. Paraffins

ii. Cyclopentanes

iii. Cyclohexanes

iv. Cycloheptanes

v. Di-cyclo-paraffins

vi. Benzenes

vii. Aromatic cycloparaffins

viii. Dinuclear and polynuclear

Aromatics are present in smaller amounts in compounds containing metallic constituents such as

Vanadium, Nickel, Iron, Copper, Magnesium, Calcium, Zinc, Titanium etc. Besides impurities such as

Sulphur, Nitrogen and Oxygen compounds mostly present in high boiling point fractions are also

present in crude oil.

Based on boiling point, the fractions are separated and given secondary treatment to utilize it as

finished products. Based on proportion of types of hydrocarbon, it can be divided into Paraffin,

Naphthenic and Aromatic categories. The purely hydrocarbon content may be as high as 97% and as

low as 50% for heavy crude oils. The non-hydrocarbon portion retains hydrocarbon characteristics as

the molecules contain one or two atoms of elements other than carbon and hydrogen. The carbon

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content is between 83 to 87% and hydrogen content between 11 to 14%. The ratio of carbon to

hydrogen increases from the low to high molecular weight fraction due to increase in polynuclear

aromatic and multi ring cycloparaffins in these higher boiling fractions.

Atmospheric distillation is adopted for separating the compounds present into various fractions up to

366C:-

i. Overhead gases containing mainly methane, ethane, propane and butane.

ii. C590 C light naphtha

iii. 90C140C heavy naphtha

iv. 140C204C Mineral Turpentine Oil (MTO) 140C240C Aviation Turbine Fuel (ATF)

vi. 140C270 Kerosene

vii. 270C340C Gas oil

viii. 340C366C Jute Batching Oil (JBO)

366C plus fraction i.e. Reduced Crude Oil (RCO) is subjected to vacuum distillation for obtaining

vacuum gas oils, raw Lube Distillate and short residue. Various fractions obtained from to assess the

utility of the crude for processing for production of various products.

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Crude Oil Characteristics and their Significance

Density

Density is used for:

Weight to volume or vice versa calculations

Checking the consistency of crude supply

Control of refinery operation

Used in various correlations

Sulphur

Crude oils are also categorized based on sulphur. Sulphur is a measure of sourness and sweetness

of crude

- Sweet grades0.5% of Sulphur

Sulphur is passed on to products as much as regulations or market accepts. It is removed in

hydrotreater by reacting with H2 and recovered as elemental sulfur in SRU.

Reid Vapor Pressure (RVP) and Light End Analysis

RVP indicates relative Percentage of gaseous and lighter hydrocarbons in crude oil.

Light end analysis carried out by GLC actually gives the percentage of hydrocarbons up to C5 and isthe basis of assessing the LPG potential of crude.

Pour Point

Indicates relative amount of wax present in crude oil. Is the temperature below which pumping and

transportation problems may be encountered. Along with viscosity, is used in pumping and design

calculations:

Wax Content

Normal paraffins above C16 are solid at somewhat ambient temperatures. These hydrocarbonsaffect the flow behavior of crude, affect the product quality of gas oil, VGO and asphalt & lube

manufacture is also dependent on wax content of the crude.

Salt Content

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It is measure of contamination in crude that will cause overhead corrosion or foul up exchangers by

settling and sealing. It is removed in desalter by washing and settling mainly chlorides and sulphates

of Na, K, Ca, Mg.

Problems Encountered due to Salts are irregular behavior in distillation and equipment corrosion in

the atmospheric distillation caused by HCL liberated due to hydrolysis of chlorides

Increased Consumption of Ammonia

Salt is a major cause of blocking and fouling of heat exchangers

Residual product contamination

Salts may vary widely in ratio of metal ions, though common averages are Na: 70-75%, Mg:

15-20%, Ca: 10%.

Mg is most prolific producer of HCL with Ca and Na in descending order

Small quantities of HCL may substantially enhance corrosion of sulphur compounds

Sediment and Water

Sediment has no relationship with salt but both might increase with connate water

Sediment Fine particles of sand clay, volcanic ash, drilling mud, rust, iron sulphide, metals

and scale

Damaging Effects Plugging Abrasion and residual product contamination

Water causes irregular behavior in distillation.

Sediment in crude is determined for custody transfer purposes

Lower the sediments and water, higher the reliability of the unit. It is also a

major pointer for corrosive materials in crudes

Asphaltenes, Carbon Residue and Ash Content

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Asphaltenes

Are polynuclear condensed aromatic hydrocarbons having high molecular weight

These are insoluble in heptane and soluble in Benzene/ Toluene

Asphaltenes and carbon residue indicate the extent to which heavy hydrocarbons are present

in crude oil.

Ash Content

Metallic constituents concentrate in the ash of the crude oil

Carbon Residue

Its a carbonaceous residue formed after evaporation and pyrolysis of the sample.

Viscosity

It is a measure of resistance to flow and is an important parameter for effective desalting. It is also

highly dependent on temperature.

High viscosity crudes need high temperatures for effective desalting. There is a limit for temperature

in desalters operation.

KUOP

It is a measure of parafinity vis--vis aromaticity of crude.

High KUOP is desired for high conversion in FCC, aromatic molecules cannot be cracked in FCC. They

will simply take a ride through the plant.

TAN

TAN is actually Total Acid Number.

It is a measure of Naphthenic Acid (NA) contents in crude. This leads to corrosion in various sections

of the unit. Over 1,500 known NA species are present in crude.

All naphthenic acids are not corrosive. Latest research indicates that TAN is not a complete Corrosion

Index. TAN with 2.5 may corrode at higher rate than TAN with say 6 !

Detailed metallurgical reviews and monitoring mechanisms must be put in place.

Specifications of Petroleum Products and Related Tests

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Vapor Pressure

Significance of Tests

Flash Point

It is the minimum temperature at which the sample gives sufficient vapor which forms an explosivemixture with air giving a flash when a flame is applied to it under conditions of the test method. Flash

point is associated with safety during storage and application in some respects. When a product like

kerosene is stored either at home or at a commercial location, it forms vapor above it depending

upon the ambient temperature. If the vapor so formed is sufficient to form an explosive mixture with

air, there would be explosions when a small naked flame is exposed to it. Each country has it own

legislation with respect to flash point depending upon the climatic conditions of the country.

Pour Point

When heavy petroleum oils containing wax are allowed to settle (like in storage tanks), wax separatesout from them making the oil immobile. If the oil does not move, it cannot be pumped. The

temperature at which the oil becomes immobile (does not move) is termed as pour point when

tested under the conditions of the test methods.

Distillation

The volatility of an oil is indicated by its distillation characteristics. Unlike pure compounds,

petroleum oils are mixtures of several hydrocarbons and so will have a boiling range instead of boiling

point. The oil should have suitable boiling range (volatility) so that it can be used in a particular

application. For example, Motor Gasoline which is used in spark ignition internal combustion engines,

has the following specifications for distillation:

Recovery up to 70o

C 10 to 45% Min

Recovery up to 100o

C 40 to 70% Min

Recovery up to 180o

C 90% v Min

Since the application is in a spark ignition engine, the fuel should easily vaporize to a sufficient degree

so that when a spark is applied it can ignite. The specification for recovery at 70o C is laid to meet this

requirement. The maximum limit of 45% is laid to prevent some other undesirable effects such as

vapor lock. This quality is called easy start. The specification for recovery at 100oC is set to give

power to engine and take load. The specification for recovery at 180oC and final boiling point are set

to prevent crank case oil dilution and un burnt hydrocarbon in tail gases (air pollution).

Copper Corrosion

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This test is applicable to motor gasoline. If motor gasoline contains any soluble solid residue, the

residue gets deposited in the carburetor and other parts after the gasoline is vaporized. Such deposit

may clog the jet and prevent fuel flow due to which the engine stops. That is why this test is done on

MS. The specification is 40 mg per liter max.

One point should be noted. Some solid material is added to MS deliberately for some purposes.

Example: Dye to identify the MS from others. These type of residues are excluded from the spec.

Octane Number

It is defined as the per cent volume of iso octane in a mixture of iso octane and normal heptane that

gives the same knocking as that of the fuel when tested under defined conditions.

Iso octane is assigned a value of 100 and normal heptane 0 octane number.

Normal paraffins have the lowest octane number. Next comes napthenes followed by iso paraffins,

olefins and aromatics for the same carbon number. However, this is only a general rule and may

differ in the case of iso paraffins. Some of them have lower octane numbers than corresponding

napthenes and some other higher octane number depending upon the branching of the iso paraffin.

Octane numbers are not truly additive. When used singly, the hydrocarbons behave in some way and

when used in a mixture, they behave in another way. For example, Toluene has a RON 107 when it is

a single component system. But when it is mixed with other hydrocarbons, it behaves as if its octane

number is > 120.

Some schools of thought say that in multi-component systems, like naphtha, octane number isadditive on weight percent basis. Some others believe that it is additive on mol. per cent basis. In

effect, there are always some exceptions and some deviations.

Research Octane Number and Motor Octane Number.

These are determined under different conditions of the test.

Test Condition RON MON

Engine speed 600 RPM 900 RPM

Spark advance 13o

Variable

Mixture Temp - - 300o

F

In Take Air Temp 125o

F 100o

F

AKI (Anti Knock Index)

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It is defined as the average of RON and MON.

AKI = (RON + MON)/2

Anti-Knock Index is regarded as more critical for engine performance than RON alone.

Cetane Number

This test is applicable to diesel fuels which use ignition by compression.

Cetane number is defined as the per cent volume of n-cetane in a mixture of n-Cetane and alpha

methyl naphthalene that would give the same knocking as that of the fuel under test.

n-Cetane is assigned a value of 100 and alpha methyl naphthalene a value of 0.

Alpha methyl naphthalene has some storage stability problem. It turns red when exposed to air. So,

although it is a primary fuel, a secondary fuel for routine use is also stated in the test method. This ishepta Methyl Nonane (HMN). Another consideration for using HMN is its easier availability.

Cetane Index

It is an alternative to cetane number. It is nearly equal to cetane number but not an actually

determined value required cetane engine. Cetane index is not applicable to fuels containing cetane

improves.

Smoke Point

Smoke point is defined as the maximum length of the flame which does not give smoke when testedunder prescribed conditions using the prescribed apparatus. Smoke point shows the hydrocarbon

nature of the fuel. Paraffins have high smoke points followed by naphthenes and then by aromatics.

The test is applicable primarily to kerosene. The main purpose of kerosene is for use in lantern. If the

kerosene gives smoke when it burns, it gives less light. As the flame size increases the light given out

would also be more. But if the kerosene starts giving smoke, the height of the flame has no meaning.

So the higher the flame without smoke, the better.

Smoke point is related to hydrogen content of the fuel. The higher the hydrogen content, the higher

will be the smoke point. Paraffins contain highest hydrogen content for the same carbon number. So

the smoke point of paraffins is highest.

Aniline Point

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BMCI is an indication of predominant nature of Hydrocarbons in a product.

All normal paraffins have BMCI zero or less than zero.

A high BMCI indicates predominantly Aromatic nature.

A low BMCI indicates predominantly paraffinic nature.

Intermediate BMCI indicates mixtures of both and also naphthenic nature.

BMCI more than 100 indicates presence of condensed rings.

BMCI of some hydrocarbons

Hydrocarbon BMCI

N Paraffins 0 or < 0

Iso Paraffins < 15

Cyclohexane 50

Benzene 99

BMCI is a calculated value form density and 50% boiling point. It is defined as,

BMCI (48640 / K) + (473.7 * G) 456.8

Where,

K = 50% Boiling Point in o K

G = Specific Gravity @ 200F / 4

0C

Bromine Number

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Bromine number is defined as the grams of bromine that react with 100 grams of the sample.

Bromine number gives the olefinity of the sample.

Olefins react with bromine giving additional products. Each double bond absorbs two atoms of

bromine.

Example:

CH3CH2CH2CH2CH = CH2+Br2 CH3CH2CH2CH2CHBRCH2Br

Benzene Content

This test is applicable to motor gasoline.

Benzene is carcinogenic (causes cancer). Its limit in MS is recognized by all countries.

Weathering Test

This test is applicable to LPG. It indicates the amount of non-vaporizable matter in LPG.

Refining operation

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Desalting

The crude oil is contaminated with various impurities mainly salts of Ca, Mg, Na, CI, SO4, etc. These

salts, however, in small proportions in crude, can cause severe corrosion in crude units, particularly in

the overhead section. Several refineries worldwide have faced emergency shutdowns or have had to

release hydrocarbons due to corrosion and material failures. Hence, it is important to remove the

salts from crude prior to distillation. The desalters are designed for 99% salt removal and reach less

than 1 ptb (part per thousand barrels) in desalted crude.

Crude oil received from tank farm is heated from 30 to 140 - 150o

C in cold preheat trains. This is

done by recovering heat from outgoing products streams from the unit. This prepares crude for

efficient desalting. Then it is passed through a desalter after being mixed with de-emulsifier and

water thru a mixer valve. In the desalter, crude passes through high electric field. The salt dissolved in

water settles at the bottom as brine and desalted crude with less than one parts per thousand barrel

comes out from the top of the vessel.

Separation of water containing salt is enhanced by deemulsifier. Desalters remove salts, sludge and

mud from crude to avoid corrosion and fouling in exchangers columns and downstream equipment.

Distillation

Atmospheric & Vacuum

The desalted crude is then heated from 140 to 190o

C at 25 Kg/cm2 pressure by heating with a

heavier hot stream. Then it is taken to the flash drum. From the top we get lighter components which

directly go to the crude column. The flashed crude is passed through hot preheat exchangers andfurther heated from 190C to 250260C. The purpose of hot preheat train is to recover heat from

pump arounds to reduce furnace duty. Furnace provides required heat for fractionation in

atmospheric column and crude is heated up to 385C.

The heated crude is fractionated in atmospheric distillation column of CDU. The fractions below

165C are withdrawn as column overheads and sent to SGU. Here mainly gases,

LPG and FRN are separated. Heavies boiling at more than 386oC are reheated under vacuum

condition (to avoid cracking) and fractionated in vacuum column of VDU. Besides the straight run

products such as LPG, Naphtha, Kerosene and Diesel, the other distillation products are intermediates

viz. (1) Gas Oil (HAGO+LVGO+HVGO) which become feedstock for FCC after treatment in VGOHT and

(2) VR which becomes feedstock for delayed coker.

The LPG is sent to LPG Merox unit for treatment before sending to RTF. The FRN is directly sent to the

HNUU in the aromatics complex. The Light Kero (LK) fraction is routed as SKO to RTF directly or via

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Kero Merox unit as ATF. The Heavy Kero (HK) fraction is blended with diesel fraction. The diesel

fractions can be routed to DHT or RTF as required.

Saturated Gas Concentration (SGU)

The overhead liquid and gases from CDU, reformer and hydrotreaters of petro-chemical complex arepassed through this plant to separate into following fractions:

1. Gases (C1+C2) for burning into furnaces or as petrochemical feedstock after H2S is removed

in Amine Treating Unit.

2. LPG (C3+C4) for domestic and industrial use after removal of Mercaptanes in Merox Unit.

3. Naptha (C5 to 165C) for sending to fertilizer or petrochemicals plants as feedstock.

Distillate Hydrotreating

Hydrotreating processes remove impurities such as sulfur and nitrogen from distillate fuels

naphtha, kerosene and diesel by treating the feed with hydrogen at elevated temperature and

pressure in the presence of catalyst. Hydrotreating of atmospheric residue is to reduce the sulfur and

metal contents of residue for producing low sulfur fuel oil or feeding to vacuum rerun unit.

Brief Description of the diesel hydro-treater is as follows.

The feed is pumped through cold and hot feed-reactor effluent exchangers and then with recycled

gas streams through the combined feed heater. The combined feed heater heats the feed up to the

reactor inlet temperature. The reactor consists of one vessel with two beds of catalysts, consisting ofone inert and three different types of catalysts. Recycled gas is added as a quench between the beds

to quench the top bed heat of reaction. The reactor effluent is cooled through a series of heat

exchangers where it, in turn, heats up the fresh feed, the stripper feed, the recycled gas and then

provides heat for generation of HP, MP and LP steam.

A wash water stream is then injected into the reactor effluent before final cooling in the air-product

condenser. From the product condenser, the reactor effluent enters the separator. The separator is a

horizontal vessel with a water boot that separates the recycled gas from the stripper feed and the

wash water from the stripper feed. The recycle gas goes through a recycled gas water cooler and

knockout drum to remove heavier hydrocarbon components before entering the overhead condenser

recycled gas scrubber. This scrubber is used to remove H2S from the recycled gas by bringing it in

contact with a liquid stream of lean amine. The top of the vessel contains a water wash section to

pick up any entrained amine. The recycled gas exits from the top of the recycle gas scrubber, and is

then mixed with makeup gas hydrogen before entering the recycle gas compressor. The stripper feed

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is heated in a series of exchangers where it in turn cools the stripper bottoms, reactor effluent,

before entering the stripper column.

The stripper is used to remove H2S from the diesel product, and also to separate un-stabilized

naphtha from the diesel product. Both the net off gas and the un-stabilized naphtha liquid that are

produced are routed to the Saturated Gas Concentration Unit. The stripper bottom is cooled through

a series of exchangers, then further cooled by air and water before entering the diesel product

coalescer and the salt drier which removes water prior to routing to the diesel product blending

system.

Hydrogen Production and Management

Hydrogen Production Plant

Hydrogen is produced commercially using following technologies:

(i) Partial oxidisation

(ii) Coal gasification

(iii) Electrolysis of water

(iv) Steam hydrocarbon reforming

(v) Platforming as a by-product.

Process Description

Feed (Refinery Fuel Gas, or Natural Gas or LPG or Hydrotreated Light Naphtha) is first mixed with

recycle hydrogen and passed through pre-treatment section. The function of pre-treatment section is

to remove sulphur in feed by hydrogenation, in the form of H2S, and removal of chloride by sodium

aluminate, the catalyst used is CoMo or NaMo. H2S is absorbed in Zno bed.

If sulphur is 200 ppm, double

stage pre-treatment is used. The De-sulphurized feed is pre-heated with steam and passed through

Nickel Catalyst packed in Vertical narrow tubes mounted in the reformer furnace. This process is

endothermic and heat is supplied by fuel firing. Following reactions take place:

Steam Reforming

CH4 + H2O l 3H2 + CO

CO + H2O l H2 + CO2

Water Gas Shift

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Process Description

Merox is the abbreviation of Mercaptan Oxidation. In this process mercaptan is separated from

hydrocarbon by washing with caustic solution. The separated merceptan is oxidised into disulfide

form which can be disposed of in slop stream. Organic sulphur from LPG, ATF/Kerosene and Gasoline

are removed by this process.

Hydrogen Sulfide (H2S) from LPG is removed by extraction with regenerated lean Amine in Amine

Treating Unit (A TU). Treated LPG is passed through reactor and mixed with caustic solution

containing merox catalyst. Then it passes through extractor to remove mercaptan. Then, it is washed

with water to remove caustic. Treated sweet LPG free of H2S and Mercaptan is sent to storage.

In case of ATF/Kerosene and Gasoline treatment, first it is mixed with caustic, air and catalyst and

then passed to reactor to convert mercaptanes to Disulfides, which is separated from caustic and

product in caustic sulphur. Caustic in recycled. Sweetened product is stored in intermediate tanks

before blending into finished product.

Following reactions take place

Mercaptan gets converted into disulfides

4RSH + O2 2RSSR + 2H2O

Caustic Regeneration

RSH + NaOH NaSR+ H2O

(oil phase) Aqueous (Sodium Mercaptide soluble in phase Aqueous phase)

Catalyst

4NaSR+02+2H2O 2RSSR+4NaOH

(Aqueous Phase) 45C (oil Phase)

The purpose of caustic in Merox process is:

To transfer the mercaptane, or the thiol portion of the mercaptane, to the aqueous phase.

To supply the alkaline environment needed for the reaction to proceed in the desired

direction.

This process is used for treating LPG, Gasoline and ATF.

Sulphur Recovery Plant

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The objective of sulphur recovery plant is to convert H2S to elemental sulphur.

Sulphur recovery is required because of:

Increasing demand for environmental friendly fuels.

Increased used of high sulphur and heavier crudes in future.

Tightening of emission standards by government/ Regulatory bodies.

Salient features of sulphur plant are:

Minimum sulphur recovery level of 98.7%

Ammonia destruction capability

Turndown capability 25%

Process Description

Acid gasses from Amin Recovery Unit (ARU) and sour gasses from sour water stripper are heated in

pre-treater and burnt in presence of regulated quantity of air from CLAUS Air Blower in CLAUS

Reaction Funance. The product from claus reaction funance is passed thru 1st and 2nd pass

condensers.

The sulphur condensed is routed to Liquid Sulphur Degassing Pit. The unreacted vapour is passed thru

claus reactor. The vapour from the claus reactor outlet is passed thru 1st and 2nd pass condensers.

The condensed sulphur is taken to Liquid Sulphur Degassing Pit. The uncondensed vapour is passedthrough Cold Bed Adsorption (CBA) Reactors 1st and 2nd passes. The outlet vapour is passed thru 1st

and 2nd pass of CBA condenser. The condensed sulphur is routed to liquid sulphur degassing pit and

the remaining gases are taken to tail gas incinerator for burning and releasing thru high stack. Sulphur

after Degassing is taken to granulation unit from where it goes for despatch to market. The off-gases

from sulphur degassing pit is recycled to CBA section for recovery of sulphur.

What is Claus Reaction?

When two molecules of Hydrogen Sulphide (H2S) react with one molecule of Sulphur Dioxide (SO2)

to give elemental sulphur in the presence of Alumina Catalyst, the reaction is called Claus Reaction

Amine Treating Unit (ATU)

The purpose of this process unit is to remove H2S from fuel gases to meet environmental

requirements.

Process Description

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The fuel gas containing H2S is introduced in Middle section of Amine Absorber Column where Lean

Methyl Diethanol is introduced near top section. By counter current flow H2S is absorbed in Amine

and sweet fuel gas (FG) free of H2S comes out from column top. The rich Amine from bottom of the

absorber column is taken to Flash Drum where any fuel gas carried over is separated out. The rich

Amine is then pumped through heater where it is heated by the hot lean amine stream coming frombottom of Amine stripper. In the stripper, Amine Acid Gas from top of the column is routed to

sulphur recovery plant along with sour gases from other process units. The lean Amine from bottom

of the stripper exchanges heat with Rich Amine and then pumped to storage tank through cooler for

recycling to Amine Absorber.

Process Chemistry

The circulating amine is 35% MDEA solution, Hydrogen sulfide H2S OR HSH is a weak acid and ionizes

in water to form hydrogen ions and sulfide ions.

HSH H+ + SH

Ethanol amines or weak bases ionize in water to form amine as hydroxyl ions

(CH2OHCH2)2NCH3+H20 CH2OHCH2)2NHCH3+OH

When H2S dissolves into the solution containing the amine ions, it will react to form a weakly bonded

salt of the acid and the base.

(CH2OHCH2)2 NCH3+SH (CH2OHCH2)2NSCH3

The sulfide ion is absorbed by the amine solution. Overall (CH2OHCH2)2NCH3+H2S

(CH2OHCH2)2NSCH3

Fluidized Catalytic Cracking (FCC)

Fluid Catalytic Cracking has developed into a major upgrading process in the oil refining industry for

conversion of heavy fuel oil into more valuable products ranging from light olefins to LPG, naphtha

and middle distillates. The attractiveness of FCC process is to its flexibility to process wide range of

feed stocks from a variety of crudes and its favorable economics of operation. The objective is to

maximize Olefins, LPG, C7 C9 aromatics, high throughput and minimize LCO and bottoms.

Hot regenerated catalyst is mixed at the bottom of reactor with raw feed and steam. After pre-

acceleration, it is brought in to contact with the staged feeds supplied as finely atomized droplets.

Feed instantaneously vaporizes and travels up the riser with the catalyst where conversion reaction

takes place. At the top of reactor, the vapor is disengaged from catalyst. The vapor is sent to main

fractionating column. In this column, mainly LPG, Gasoline, middle distillates and decanted oil are

obtained. The spent catalyst is steam stripped to remove hydrocarbon vapor and then sent to two

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stage regenerators for burning coke before it is recycled to reactor along with makeup catalyst to

reactor.

Air is injected in catalyst regenerator for burning coke. Water generated in the system leaves with

flue gas from Power Recovery Train. Flue gases are sent to CO boiler and thereafter to a cleanup

system to remove particulates, SOx and NOx. ZSM additive is added to catalyst to increase LPG yield.

Residues are also used as feedstock in RFCC.

MTBE

MTBE (Methyl Tertiary Butyl Ether) is a gasoline blending component which is used as octane booster

for gasoline stocks. It is produced from the cracked LPG stream of Fluidized Catalytic Cracking unit.

The cracked LPG from FCC primarily consists of a range of C3 and C4 olefins which form the feedstock

for the MTBE unit. MTBE is primarily produced by reaction of Iso-butylene and Methanol in the

presence of Ion exchange resin type catalyst.

ALKYLATION

Alkylation combines low-molecular-weight olefins (primarily a mixture of propylene and butylenes)

with Isobutane in the presence of a catalyst, either sulfuric acid or hydrofluoric acid. The product is

called alkylate and is composed of a mixture of high-octane, branched-chain paraffinic hydrocarbons.

Alkylate is a premium blending stock because it has exceptional antiknock properties and is clean

burning. The octane number of the alkylate depends mainly upon the kind of olefins used and upon

operating conditions.

HYDROCRACKING

Hydrocracking is a two-stage process combining catalytic cracking and hydrogenation, wherein

heavier feedstocks are cracked in the presence of hydrogen to produce more desirable products. The

hydrocracking process largely depends on the nature of the feedstock and the relative rates of the

two competing reactions, hydrogenation and cracking. When the feedstock has a high paraffinic

content, the primary function of hydrogen is to prevent the formation of polycyclic aromatic

compounds. Another important role of hydrogen in the hydrocracking process is to reduce tar

formation and prevent buildup of coke on the catalyst. Hydrogenation also serves to convert sulfur

and nitrogen compounds present in the feedstock to hydrogen sulfide and ammonia.

Heavy Naphtha Hydrofining Unit

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The function of this hydro treating unit is to treat the feed naphtha and remove impurities like heavy

metals, sulfur, nitrogen and olefins, which are poison for Platformer catalyst.

Platformer Unit

The platformer unit processes hydrotreated naphtha from the Heavy Naptha Unifining unit, strippercolumn bottoms, for the production of aromatics for downstream unit processing and separation.

Major reactions taking place in platforming unit are as follows:

1. Dehydrogenation of naphthenes

2. Hydrocracking of paraffins

3. Isomerisation

4. Dehydrocyclisation of paraffins

The spent catalyst is regenerated continuously in situ, which takes place in Cyclemax CCR.

Flare system

The flare system in a refinery is the most important system. It is the one of the important system that

needs to be commissioned / line up before starting any process unit and this will be the last system

that will be decommissioned after shutdown. It allows the various process refinery process units to

depressurize the units by venting out the hydrocarbons to a safer place and burning it in a controlled

condition during any kind of emergencies / startups / shutdowns.

Flare system is provided with fuel gas line connected to flare header, which always maintains positive

pressure. This prevents air (oxygen) entry into the system which could cause an explosion apart from

keeping the flare system online continuously to take care of any emergencies. Flare system is

normally provided with pilots which is lighted first and kept on line always. Flare is also provided with

steam rings for smoke less firing in case of excessive firing rate.

All hydrocarbon service pressure relief valves are connected to flare header. The flare gas flows via a

knockout drum followed by a seal pot through a non-return flapper valve to arrest the back flow of

air into flare header. The knock out drum removes any hydrocarbon condensate carried along with

the gas. The liquid is pumped out to slop tank from time to time. The seal pot is filled with water toprovide a seal, which prevents air sucking back to the header.

Flare Gas Recovery Unit (FGRU) is to recover most valuable hydrocarbons from the flare gases using

compressor and associated facilities. The system supplies the recovered gas to the refinery fuel gas

headers.

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Refinery water supply

The following important water supply systems exist in the refinery.

1. Fresh water supply system: This provides utility water supply, make up to the circulating water

system, make-up to fire water supply system and make up to drinking water treatment system.

2. Fire water supply system: Throughout the process units and offsites areas, the fire water supply

pipeline network is laid in the form of ring. Firewater tanks are provided in offsites area to have an

immediate supply source for fighting any major fire. In critical areas, long distance throw nozzles are

provided.

3. Recirculating hot and cold water system: For cooling of hot products, this system is provided. It is

having chemical treatment system to avoid scaling and corrosion in related pipelines and equipment.

Cooling Towers are also provided in the system where water is cooled by evaporation before

recirculation. Blow-down

in the form of leakage and manual draining is provided to avoid buildup of salt concentration. Make

up water is taken from fresh water system. In some of the coastal refineries, once through cooling

water system is used and sea water is utilised for the cooling of products.

Fuel oil and fuel gas system: For providing fuel supply to process units furnaces, and boilers this

system is provided. In fuel gas, mostly methane, ethane and purged gases from hydrogen units are

used. The supply system is maintained at constant pressure. For fuel oil, varying range of fuels from

LDO to Asphalts are used. Storage tanks, blending facilities and pumping system are provided for

supply of fuel oil to furnaces and boilers.

Hydrogen, Nitrogen and air supply systems:

Hydrogen is generated in Hydrogen plant or catalytic reformer unit. It is utilised in hydro-treatment

units. It is a very hazardous gas to handle as the flame cannot be seen.

Nitrogen is used for catalyst regeneration, blanketing tanks from atmospheric oxygen in the case of

lubes and other products which form explosive mixture when coming in contact with air, and

maintaining inert atmosphere in the process unit equipment. Nitrogen is produced in generators

installed in the refinery or is purchased from outside. Air is used for utility purposes, catalystregeneration, decoking of furnace tubes and instrumentation etc. It is taken from atmosphere and

compressed before using.

Start up and shut down

Start up and shutdown is an important operation activity in the refinery involving great degree of risk

to have accidents, fire and damages. Risk management is very important aspect in performing this

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critical operation activity in a safe manner. Well prepared, proven and safe start up and shut down

procedures are made available to the operating personnel and equally important is that they are

followed to perform these operation in a safe and efficient manner.

Hazards

Dangers/Hazards encountered while performing start up and shutdown activities

Unknown or accidental formation of explosive mixtures of Air and Hydrocarbon

Contacting cold water with hot oil

presence of toxic and inflammable substances

Presence of pyrophoric iron

Vacuum, thermal and mechanical shocks

Startup operation can be classified as

1. Initial startup like pre-commissioning

2. Commissioning after major shutdown

3. Start up after short shutdown

4. Start up after emergency shutdown

Initial startup includes extensive pre-commissioning activities such as

Flushing and drying of process and utilities lines

Preparation ofequipments

Checking of Instrument loops and logic systems

Checking of correct functioning of all safety systems, etc

Normal startup / Commissioning includes the following activities

Preparation, purging

Tightness test

Fuel gas backing

Cold circulation

Hot circulation

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Normalization activities

Startup preparation includes the following activities

Preparation of operating procedure

Completion of mechanical jobs

De-blinding and lining up of machinery and equipments

Commissioning of fire and safety equipments

Commissioning of utilities, etc

Purgingis done to remove air / oxygen from the system by using steam or nitrogen.

Steam Blowingof pipeline uses the kinetic energy of steam to literally and physically entrain andblow out solid and liquid debris within a pipe line.

Tightness testis done to ensure that the flanged joints are boxed without any leak. Nitrogen is used

normally used for increasing the pressure and leak check is done by soap test or hold test.

Fuel gas back up is to ensure positive pressure in the system after steam out. Precautions like

stopping of all hot jobs, closing of bleeders, drains and vents are taken before carrying out this

activity.

Cold Oil / Gas circulationis to check up the system line up and make sure that all instruments and

machineries are all functioning well. Stop circulation after initial run and allow water to settle downand drain from low points. Repeat till water from system drains are free and ensure that all

instruments, safety interlocks are all activated.

Hot Oil / Gas circulationis to bring the system temperature close to feed cut in temperature, remove

final traces of water and increase the system pressure. During this step, the following activities like

final water draining from drains must be done at 140 150 0F, remaining water evaporation at 220

250 0F and hot bolting of flanges at 480 570 0F are performed.

Normalization operationincludes the following steps like feed cut in1. Increase of temperature and pressure to desired operating value

2. Commissioning of all auxiliary systems

3. Stabilization of operation at low throughput

4. Start dosing of chemicals

5. Routing of products to storage once they meet the required quality specs

6. Increase the throughput to maximum.

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Start up after short periodwill have system with cold or hot circulation running and the remaining

steps mentioned above are carry forward.

Start up after emergency shutdowninvolves, carrying out root cause analysis to solve the problem

and follow normal start up procedure from where applicable.

Shutdowncan be classified as

Planned shutdown for long duration (like Turnarounds where majority of systems /

equipments are opened)

Planned short shutdown for short period (like Specific systems / unit are opened)

Unplanned emergency shutdown.

Major planned shutdownrequires extensive planning and implementation of the major activities like

preparation, decommissioning of unit, depressurize & drain, purging, positive Isolation, cool down,

opening up.

Shutdown preparationactivity includes

Preparation of shutdown procedure

Preparation of Work lists, blind lists etc

Advance information to all concerned departments within the refinery & upstream

downstream industries

Carrying out pre shutdown jobs, etc.

Decommissioning activity includes

Reduction of load to minimum

Reduction of heat and Cooling down the system gradually

Changing over to light oil if required

Shutting off heat, shutting off feed,

Flushing out system and further cool down.

Depressurize and drain activity includes depressurization of the system to flare, transferring of

maximum system to slops and drain the remaining to sewers.

Purgingis to expel hydrocarbons / toxic gases from the system by steam or nitrogen.

Steam outA steam out employs the heat content of steam to break down tars, gums, sludges, andother viscous contaminants within a vessel (or a pipe line) in order to reduce their viscosity and allow

them to dissolve or be drained away in order to clean out the vessel or pipe line.

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Positive isolationby blinding to be done as per blind list prepared (Operations to correctly identify

blind locations) & register them.

Cool down is essential for man entry and to remove pyrophoric iron present in the system. It can be

done by water washing of the system.

Open upactivity includes the test for toxic, flammable and oxygen gases and ensure ventilation and

safety appliances are provided inside the vessel.

Short period shutdown may have situation like unit having positive pressure, vessels are having

levels & oil / gas circulation in progress. No major maintenance Job can be carried out and

opportunity can be utilized for carrying out the essential jobs only.

Emergency shutdown is unplanned, unexpected and may be associated with unsafe situation.

Emergency may be due to feed failure; power failure, utility failure (like steam / instrument air /

cooling water etc.), furnace tube leak, flange leak / pipe rupture etc.

Emergency to be handled safely by learning, discussing, performing simulated exercises of all type of

emergencies. Operators have to be familiarized with the types of emergencies and the action to be

taken for shutting down the unit without damage.

Safety

Crude oil refining involves a great degree of risk due to existence of personal or occupational safety

and process safety hazards associated with the refining operation. Hazards in the refinery can be

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Presence of flammable gas / vapor & liquid at high temperature, pressure & quantity,

Presence of toxic gases / corrosive chemicals & pyrophoric material,

Presence of steam, compressed air & nitrogen,

Presence of fine particles and failing objects,

Exposure to heat radiations,

Presence of electrical shock.

In addition to the above mentioned hazards present in the refinery, some basic cause for incidents

occurring are due to

Lack of knowledge,

Inadequate work standards,

Non-compliance of standard working procedures laid down in the operating manuals,

Working without proper personal protective equipments,

Using defective equipments,

In adequate equipment guards or protection,

Substandard housekeeping and inadequate illumination and ventilation etc.

Personal safety hazards may lead to accidents like slips, falls, cuts etc that usually affect one

individual worker. On the other hand, process safety hazards may cause major accidents involving the

release of potentially dangerous materials, fires and explosion or both.

Process safety incidents can have catastrophic effects and can result in multiple injuries and fatalities,

as well as substantial economic damage. Process safety incidents can harm workers inside plant and

members of the public who resides nearby. Therefore, effective process safety management is

required for the safe operation of refinery.

Process safety management assists the refinery in managing the above discussed safety hazards

involved in performing the refinery operation in safe manner. It focuses mainly on the design and

engineering of refining facilities,

hazard assessments,

incident investigation,

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A. Apparent losses

i. Measuring devices in storage tanks and custody transfers for proper accounting

ii. Automating road/rail dispatch facilities.

B. Real losses

i. Vapour recovery from flare and product loading facilities

ii. Handling of light hydrocarbon slop in process unit and offsite area in closed blow down system

iii. Conversion of fixed roof tanks to floating roof tanks for low flash products including diesel and use

of proper type of roof seals.

iv. Automatic tank gauging

v. Use of proper mixers in crude tanks for minimizing sludge formation and modern method of

removal and recovery of only sludge/oil to reduce loss

vi. Minimising slop generation to reduce evaporation loss in slop handling system

vii. Close monitoring of BSW in crude processed to avoid plant upsets and increased losses.

viii. Routing of all sour gases to sulphur recovery unit

ix. Routing of off gases from vacuum column to furnaces.

Energy Conservation

Conservation of oil and gas has assumed greater importance in view of the emphasis on demand side

management of energy. Average fuel loss in the refineries 7 35 % which is higher compared to

global levels (of similar configuration).

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Energy optimisation for a refinery begins early in the development and design stage with the

establishment of a set of energy saving guidelines applicable to the project. Some of the areas given

below need to be looked into:

1. Integration of heat exchange system of the units to utilize the heat from hot stream of another

unit crude distillation unit and vacuum distillation units are heat integrated.

2. Optimisation of heat exchangers train use of pinch technology.

3. Direct hot feed from one unit to another unit without passing through intermediate tanks.

4. Energy efficient processes/equipment such as furnaces, pumps, exchangers etc. Provision of air

preheter in furnace.

5. Proper insulation of hot products and steam lines.

6. Optimisation of

i. Reflux ratio in distillation process

ii. Solvent feed ratio in extraction process

7. Use of soaker technology for visbreaking.

8. Use of microprocessor based control system alongwith DDCS (Digital Distributed Control System)

and advanced process control.

9. Heat recovery from process streams for heating colder process streams/ boiler feed water.

10. Power generation in new refinery will be through combined cycle operation integrated with

gasification.

11. Steam system High pressure steam will be cascaded down to lower level by back pressure

turbines either generating power or coupled with various key process compressors and pumps.

Pressure reduction of steam through a control valve will be minimised.

12. Minimise leakage through glands/seals of pumps, compressors and turbines.

13. Low level heat recovery.

14. Soot blowers for convection section of furnaces to improve heat recovery in furnaces.

15. Steam generation from hot streams.

16. Benchmarking, gap analysis and setting targets.

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17. Energy audit for continuous improvement of energy performance.

Gross Refining Margin

Gross Refining Margin (GRM) is the differential between the product realisation and the cost of crude

processed to obtain these products. GRM of a particular refinery will depend upon various internal

and external factors. Some of these factors are discussed below:

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Internal Factors

The secondary processing facilities available with the refinery which affect the product yield of the

refinery

The fuel used and losses incurred in the production processes.

External Factors

The international prices of various crudes and products

The demand and supply balance of various products refined by the refinery

The duty structure prevailing in the country relating to crude and products.

Operating Cost of the Refinery

The operating cost of the refinery includes various elements, some of which are as under:

Power and fuel: Fuel is used either directly in the refining process or to generate power and utilities

to be used in the refining process. Fuel may be purchased from outside suppliers (like natural gas),

power from electricity board or internal refined products (like LSHS, FO or HSD) may be used as fuel.

Chemicals and catalysts: During the refining process of petroleum products, various chemicals and

catalysts are used. The purpose of chemicals is mainly to improve the quality of products so as to

meet the desired specifications. Catalysts are used in various reformers and other secondary

processing facilities.

Establishment cost: This is related to the manpower deployed and includes the salary and wages paid

to staff, overtime, bonus etc.

Repair and maintenance cost: It is incurred in various mechanical, electrical and civil jobs carried out

for the maintenance of plant and machinery.

General administrative cost: This cost includes expenses such as traveling. Printing, insurance and

other related overhead expenditure.

Depreciation: Operating cost includes depreciation on plant and machinery, furniture, equipment andother fixed assets used in the refining process towards general wear and tear.

Net Margin

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The net margin is the difference between gross margin and operating cost. This is virtually the net

profit to the refinery.

Net Margin = Gross margin Operating cost.

For higher profitability, gross margin should be increased and operating cost reduced by increasedefficiency in refining operations

In the net back system, the estimated realization is calculated on the basis of expected yield from the

particular refinery for a specific crude. For the purpose of procurement of crude for a particular

refinery, net back estimation is used to evaluate the suitable crude for the refinery. The crude which

is having higher net back to the refinery is normally procured for it.