Chap 1 _refinery Process

7/31/2019 Chap 1 _refinery Process

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REFINERY PROCESS

A refinery is a factory. Just as a paper mill turns lumber into paper, a

refinery takes crude oil and turns it into gasoline and hundreds of otheruseful products. A typical refinery costs billions of dollars to build and

millions more to maintain. A refinery runs twenty-four hours a day, 365

days a year and requires a large number of employees to run. A refinerycan occupy as much land as several hundred football fields. Workers ride

bicycles to move from place to place inside the complex.

Today, some refineries turn more than half of every 42-gallon barrel ofcrude oil into gasoline. How does this transformation take place?

Essentially, refining breaks crude oil down into its various components,

which then are selectively reconfigured into new products. All refineriesperform three basic steps: separation, conversion, and treatment.

BASIC STEPS OF REFINERIES:

1. SEPERATION

2. CONVERSION3. TREATMENT

SEPARATION:

Heavy petroleum fractions are on the bottom, light fractions are on the

top. This allows the separation of the various petrochemicals. Modernseparation involves piping oil through hot furnaces. The resulting liquids and

vapors are discharged into distillation towers. Inside the towers, the liquids

and vapors separate into components or fractions according to weight andboiling point. The lightest fractions, including gasoline and liquid petroleum

gas (LPG), vaporize and rise to the top of the tower, where they condense

back to liquids. Medium weight liquids, including kerosene and diesel oildistillates, stay in the middle. (Heavier liquids, called gas oils, separate

lower down, while the heaviest fractions with the highest boiling points

settle at the bottom.)


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CONVERSION:

Cracking and rearranging molecules adds value to the products. This

is where refinings fanciest footwork takes placewhere fractions from thedistillation towers are transformed into streams (intermediate components)

that eventually become finished products. The most widely used conversionmethod is called cracking because it uses heat and pressure to crack heavy

hydrocarbon molecules into lighter ones. A cracking unit consists of one ormore tall, thick-walled, bullet-shaped reactors and a network of furnaces,

heat exchangers and other vessels. Cracking and coking are not the only

forms of conversion. Other refinery processes, instead of splitting molecules,rearrange them to add value. Alkylations, for example, makes gasoline

components by combining some of the gaseous byproducts of cracking. The

process, which essentially is cracking in reverse, takes place in a series oflarge, horizontal vessels and tall, skinny towers that loom above other

refinery structures. Reforming uses heat, moderate pressure and catalysts to

turn naphtha, a light, relatively low-value fraction, into high-octane gasolinecomponents.

TREATMENT:

The finishing touches occur during the final treatment. To make

gasoline, refinery technicians carefully combine a variety of streams fromthe processing units. Among the variables that determine the blend are

octane level, vapor pressure ratings and special considerations, such aswhether the gasoline will be used at high altitudes.

STOARAGE TANK:

Both the incoming crude oil and the outgoing final products need to

be stored. These liquids are stored in large tanks on a tank farm. Pipelines

carry the final products from the tank farm near the refinery to other tanksall across the country source: Energy Information Administration


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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 acomplex 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 oilhave boiling points from less than 60F to greater than 1200F (60-650C).

Crude oil varies in sulfur content. Higher sulfur crude oil is more corrosive

than lower sulfur crude oils. In order to process higher sulfur crude oils,

equipment must be built from more expensive alloys to provide highercorrosion resistance. Many refineries are not able to process crude oils with

high sulfur content.

The American Petroleum Institute (API) has developed a

characterization for the density of crude oils API = (141.5/Specific Gravity@60F) -131.5 When comparing crude oils, the crude oil with the higher API will be

easier to refine than one with a lower AP

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 isgenerally drained to waste water treatment just prior to processing

DESALTING:

All crude oil contains salt, predominantly chlorides. Chloride salts cancombine with water to form hydrochloric acid in atmospheric distillation

unit overhead systems causing significant equipment damage andprocessing upsets. Chlorides and other salts will also deposit on heatexchanger surfaces

reducing energy efficiency and increasing equipment repairs and

cleaning.


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Salt must be removed from crude oil prior to processing. Crude oil is

pumped from storage tanks and preheated by exchanging heat withatmospheric distillation product streams to approximately 250F

(120C). Inorganic salts are removed by emulsifying crude oil withwater 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.

ATMOSPHERIC DISTALLATION UNIT/CRUDE

DISTALLATION UNIT:

PRINCIPLE:

Initial crude oil separation is accomplished by creating a temperature and

pressure profile across a tower to enable different composition throughout

the tower.

PROCESSESS:

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

through heat exchange with distillation products, internal recycle streamsand tower bottoms liquid. Finally, the crude oil is heated to approximately

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

Distillation concentrates lower boiling point material in the top of thedistillation tower and higher boiling point aterial in the bottom.

Progressively higher boiling point material is present between the top andbottom of the ower. 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 anoverhead condenser. A portion of the condensed liquid is returned to the

tower as reflux. The continuous vaporization and condensation of material

on


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each tray of the fractionation tower is what creates the separation of

petroleum products within the tower.

PRODUCTS:

The most common products of atmospheric distillation are fuel gas, naphtha,

kerosene (including jet fuel), diesel fuel, gas oil and resid. Atmosphericdistillation units run at a pressure slightly above atmospheric in the overhead

accumulator. Temperatures above approximately 750F (400C) are avoided

to prevent thermal cracking of crude oil into light gases and coke. With theexception of Coker units, the presence of coke in process units is undesirable

because coke deposit fouls refining equipment and severely reduces process

performance.

VACUUM DISTALLATION UNIT: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 750F (400C) in a firedheater and fed to the Vacuum Distillation tower where it is

fractionated into light gas oil, heavy gas oil and vacuum reside.

Typical products and their true boiling points (TBP) from crude oil

distillation (i.e., both atmospheric and vacuum tower products) are:


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HYDROTREATER(NAPHTA):-

Most catalytic reforming catalysts contain platinum as the active

material. Sulfur and nitrogen compounds will deactivate the catalyst andmust be removed prior to catalytic reforming. The Naphtha HDS unit uses a

cobalt- molybdenum catalyst to remove sulfur by converting it to hydrogen

sulfide that is removed with unreacted hydrogen.

Reactor conditions are relatively mild for Naphtha HDS at 400-500F

(205-260C) and relatively moderate pressure350-650 psi (25-45 bar). As coke deposits on the catalyst, reactor

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

shutdown and catalyst replacement. If required, the boiling range of the Catalytic Reforming charge stock

can be changed by redistilling in the Naphtha HDS. Often pentanes,

hexanes and light naphtha are removed and sent directly to gasoline


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blending or pretreated in an Isomerization Unit prior to gasoline

blending.

HYDROTREATER (KEROSENE):

Hydrotreating is a catalytic process to stabilize products and remove

objectionable elements like sulfur, nitrogen and aromatics by reacting themwith 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 600-800F (315-425C) and

at moderately high pressures 500-1500 psi (35-100 bar). As coke deposits onthe catalyst, reactor temperature must be raised. Once the reactor

temperature reaches ~750F (400C), the unit is scheduled for shutdown and

catalyst replacement. Hydrogen is combined with feed either before or after it has been

heated to reaction temperature. The combined feed enters the top of a

fixed bed reactor, or series of reactors depending on the level ofcontaminant removal required, where it flows downward over a bed of

metal-oxide catalyst Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur,

ammonia from nitrogen, saturated hydrocarbons and free metals.

Metals remain on the catalyst and other products leave with the oil-

hydrogen steam. Hydrogen is separated from oil in a product

separator. Hydrogen sulfide and light ends are stripped from the desulfurized

product. Hydrogen sulfide is sent to sour gas processing and water

removed from the process is sent to sour water stripping prior to use

as desalter water or discharge.


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HYDROTREATER (DIESEL):

Hydrotreating is a catalytic process to stabilize products and remove

objectionable elementslike sulfur, nitrogen and aromatics by reacting themwith 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. Mosthydrotreating reactions take place between 600-800F (315-425C) and at

moderately high pressures 500-1500 psi (35-100 bar). As coke deposits onthe catalyst, reactor temperature must be raised. Once the reactor

temperature reaches ~750F (400C), the unit is scheduled for shutdown and

catalyst replacement.Hydrogen is combined with feed either before or after it

has been heated to reaction temperature. The combined feed enters the top ofa fixed bed reactor, or series of reactors depending on the level of

contaminant removal required, where it flows downward over a bed ofmetal-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 otherproducts leave with the oil-


separator.

Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur,ammonia fromnitrogen, saturated hydrocarbons and free metals.Metals remain on the catalyst and other products leave with the oil-


separator.


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GAS OIL HDS:-

Hydrotreating is a catalytic process to stabilize products and removeobjectionable elements, particularly sulfur and nitrogen, by reacting them

with hydrogen prior to feed to the FCC Unit. Most hydrotreating reactionstake place between 600-800F (315-425C) and at relatively high pressuresup 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 removalrequired, where it flows downward over a bed of metal-oxide catalyst. For

desulphurization, the most common catalysts are cobalt-

molybdenum. When hydrodenitrofication (HDN) is desired in addition todesulfurization,

nickel-molybdenum catalysts are recommended. Hydrogen reacts with the oil to produce hydrogen sulfide from sulfur,

ammonia from nitrogen, saturated hydrocarbons and free metals.

Metals remain on the catalyst and other products leave with the oil-

hydrogen steam. Hydrogen is separated from oil and hydrogen sulfideand 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.


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FLUID CATALYTIC CRACKER (FCC):The FCC is considered by many as the heart of a modern petroleum

refinery. FCC is the tool refiners use to correct the imbalance between the

market demand for lighter petroleum products and crude oil distillation that

produces an excess of heavy, high boiling range products. The FCC unitconverts 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 lowertemperature range. The FCC can achieve conversions of 70-80% of heavy

gas oil into products boiling in the heavy gasoline range. The reduction indensity 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 significanteffect on refinery profitability.

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

but relatively low pressures of 10-30 psi (1-2 bar). At these temperatures,coke formation deactivates the catalyst by blocking reaction sites on the

solid catalyst. The FCC unit utilizes a very fine powdery catalyst know as a

zeolite catalyst that is able to flow like a liquid in a fluidized bed - hence thename "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 nitrousoxides (NOX) as well as some other combustion products.

Feedstock gas oil is preheated and mixed with hot catalyst coming

from the regenerator at 1200-1350F (650-735C). The hot catalystvaporizes the feedstock and heats it to reaction temperature. To avoid

overcracking, which reduces yield at the expense of gasoline, reactiontime is minimized. The primary reaction occurs in the transfer line (or

riser) going to the reactor. The primary purpose of the reactor is toseparate 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. Lightend products are highly olefinic (unsaturated) and are used as

feedstock for further upgrading processes like alkylation. With sulfur


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concentration of gasoline reducing, FCC products (gasoline and

distillates) may require desulfurization through a HDS Unit prior toblending.

The hydrocracker is similar to the FCC in that it is a catalytic process thatcracks long chain gas oil molecule in to smaller molecule that boil in the

gasoline jet fuel and diesel fuel range the fundamental difference is thatcracking reaction take palce in an extramley hydrogen rich atmosphere two

reaction occurs first carbon bond are broken followed by attachment of

hydrogen. Hydrocracker products are sulfur and saturated.Another difference is operating conditions. Hydrocrackers run at high

temperature 650-800F (345-425C) and very high pressures of 1500-3000

psi (105-210 bar). Hydrocracker reactors contain multiple fixed beds ofcatalyst 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. Hydrocrackerunits 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, cokergas oil and gas oil from crude distillation. Heavy naphtha from theHydrocracker 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 foralkylation. The yield across a Hydrocracker may exhibit volumetric


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gains as high as 20-25% making it a substantial contributor to refinery

profitability.

ETP:


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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 waterhas 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 areinjected 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 theflotation 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 containgmicro-organisms is removed to the sludge handling/disposal unit


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COKER/VISK BREAKER: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 reducescatalyst activity. However, in the coking process, coke is intentionally

produced as a byproduct of vacuum resid conversion from low value fueland 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 lowertemperatures. 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 aftercalcining 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 adirect fired furnace to more than 900F (480C) and discharged into a

coke drum where thermal cracking is completed. High velocity and

stream injection are used to minimize coke formation in furnace tubes.Coke deposits in the drum and cracked products are sent to the

fractionator for recovery. Coke drums typically operate in the 25-50

psi (2-4 bar) range while the fractionator operates at a pressure

slightly above atmospheric in the overhead accumulator. Fractionatorbottoms 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 andvessel preparation for return to service.

Coker light products are highly unsaturated. Coker light ends are

recovered as an olefin feed source for alkylation. Coker naphtharequires 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 ofexpensive cutter stock required for dilution. The process is carefully

controlled to predominantly crack long paraffin chains off aromaticcompounds while avoiding coking reactions.


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There is a tradeoff between furnace temperature and residence time

for visbreakingoperations. Longer residence time leads to lowerfurnace outlet temperatures. In generaloperations are conducted

between 800-930F (425-500C). Material is quenched with cold gasoil to stop the cracking process. Pressure is important to unit design

and ranges between300-750 psi (20-50 bar).

NEEDLE COKE UNIT:

Needle Coke is a premium grade, high value petroleum coke, used in themanufacturing of graphite electrodes for the arc furnaces in the metallurgy

industry. Its hardness is due to the dense mass formed with a structure of

carbonthreads or needles oriented in a single direction. Needle coke is highlycrystallineand can provide the properties needed for manufacturing graphite

electrode. It canwithstand temperatures as high as 28000C.

The technology is primarily focused on production of needle coke in anyexisting delayed coker unit using heavier hydrocarbon streams without any

costly pre-treatment. Formation of needle coke requires specific feedstocks,

special coking and also special calcination conditions. If feedstocks aresuitable 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 and0.3

wt% respectively. Higher sulfur content of coke can cause the puffing ofelectrode. 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 otherproperties meet the quality of


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

low

sulfur feed are suitable for considering this technology.

CATALYTIC REFORMING: CATALYTIC

REFORMING:Gasoline has a number of specifications that must be satisfied to providehigh performancefor today's motor vehicles. Octane, however, is the most

widely recognized specification. Theoctane number is generally reported asthe average of Research Octane Number (RON) andMotor Octane Number(MON), (R+M)/2. MON is the more severe test, so for a given fuel RON is

always higher than MON. Unfortunately, heavy naphtha from atmosphericdistillation, which forms a significant percentage of the gasoline blend, has an octane ratingof 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 octanecomponents while reducing the percentage of low

octane components.

In short, Catalytic Reforming converts straight chain and saturatedmolecules into unsaturated cyclic and aromatic compounds. In doing so, it

liberates significant amount of hydrogen that may be used in desulfurization

and saturation reactions elsewhere in the refinery. In addition to hydrogenand 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 avolumetric loss to refining operations.

Reforming uses platinum catalyst. Sulfur poisons the catalyst; therefore,virtually all sulfur must be removed prior to reforming. Temperature is usedto control produced octane. The unit is operated at temperatures between

925-975F (500-525C) and pressures between 100-

300 psi (7-25 bar). Reformer octane is generally controlled between 90 and95 (R+M)/2 depending on gasoline blending demands. As a result of very

high reactor temperatures, coke forms on the catalyst, which reduces


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activity. Coke must either be removed continuously (Continuous Catalyst

Regeneration CCR Units) or periodically (Semi- regenerative Units) tomaintain performance.

ISOMERISM:Catalytic reforming has little effect on Light Straight Run gasoline (LSR),which is material in the C5 - 165F (74C) boiling range. This fraction is

removed from reformer feed. Its octane number may be significantly

improved by converting normal paraffins into their isomers in theIsomerization 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 ofsmall amounts of organic chlorides to maintain activity. Organic chlorides

are converted to hydrochloric acid; therefore, Isomerization feed must befree of water to avoid serious corrosion problems. Other catalysts use a

molecular sieve base and are reported to tolerate water better.

Isomerization uses reaction temperatures of 300-400F (150-200C) atpressures of 250-400 psi (17-27 bar).

For refineries that do not have hydrocracking facilities to supply iso-butane

for alkylationFeed, iso-butane can be made from n-butane using isomerization,


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ALKYLATION:

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

produced at the FCC and Coker. Alkylation is the opposite of cracking. The process takes

small molecules and combines them into larger molecules with high octane and low vapor

pressure characteristics.

In the Alkylation Unit, propylene, butylenes and sometimes pentylenes (also known as

amylenes) are combined with iso-butane in the presence of a strong acid catalyst (either

hydrofluoric (HF) or sulfuric acid) to form branched, saturated molecules. Alkylate has an

octane around 95 (R+M)/2 and low vapor pressure making it a valuable gasoline blendingcomponent particularly for premium grade products. It contains no olefins, aromatics or

sulfur.

Sulfuric Acid Alkylation runs at 35-60F (2-15C) to minimizepolymerization reactions while HF Alkylation, which is less sensitive to

polymerization reactions, runs at 70-100F (20-38C). Chilling orrefrigeration 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 beregenerated and returned to the process.


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THE GAS PLANT:

Light ends are hydrocarbons boiling at the lowest temperatures including methane, ethane,

propane, butanes, and pentanes, which contain from one to five carbon atoms. Light endsare fractionated in distillation towers and treated with amine contacting to remove

hydrogen sulfide. The most abundant source of lights ends is cracking operations.

Unsaturated light ends, containing ethylene, propylene, butylenes and

pentylenes (from the Fluidized Catalytic Cracking Unit and Coker Unit), are

fractionated separately from saturated light ends (from Crude Distillation,Hydrocracking, and Catalytic Reforming).

THE GAS PALNT

The Gas Plant will remove the light hydrocarbons from the Naphtha Unit

product. Lean oil is used to absorb and recover the propane and butane toallow the hydrogen, methane, ethane and hydrogen sulfide to be sent

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

Distillation columns are used to separate these gases in the same way as the Crude column.The lighter boiling point materials leave the top and the heavier ones leave through the

bottom of the tower. In addition, the mixed butanes and iso-butane are sent the Alklyation

Unit. The heavy naphtha is also sent to the Reformer for upgrading

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 containsimpurities most notably sulfur compounds and ammonia. Hydrogen sulfide and ammonia

are removed in the sour water stripper.

SULPHER RECOVERY:

The sulfur recovery process used in most refineries is a "Claus Unit". In general, the ClausUnit involves combusting one-third of the hydrogen sulfide (H2S) into SO2 and then

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

form elemental sulfur.


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Documents

Chap 1 _refinery Process