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EMERGENCY EVACUATION INSTRUCTION

Whenever you hear the building alarm or are informed of a

general building emergency: Leave the building immediately, in an orderly fashion Do not use elevators Follow quickest evacuation route from where you are If the designated assembly point/area is unsafe or blocked due to

the emergency, proceed to the alternate assembly point Report to your Work Area Rep at the assembly point to be

checked off as having evacuated safely Specific safety requirements for TODAY

Today: NO testing of fire alarm systems

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COURSE OBJECTIVES

When you complete this module you will be able:

To grasp the role of gas plant in the refinery

To describe the sat and unsat gas processing unit

To grasp the different types of amines: advantages and

disadvantages

To select an amine from the various types available and

calculate amine circulation rates required

How to handle the operation of units, interaction and

challenges encountered

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COURSE PLAN

Total duration: 5 days Lecture: 3 days Practice on dynamic simulator: 2 days

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COURSE ASSESSMENT

Lecture :

The multiple-choice (knowledge based questions) section of the testis scored based on the number of questions you answered correctly

Multi-choice test : 40 questions

Passing grade: 36/ 40

No additional points are subtracted for questions answered

incorrectly

Even if you are uncertain about the answer to a question, it is better

to guess than not to respond at all Dynamic simulator :

Passing grade : Implement an extract operation procedure for 10

minutes and troubleshoot successfully 2 scenarios in simulator

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OUTLINE

I. Refinery gas treating process

II. Gas processing plant

III. Practice on dynamic simulator

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PART I.REFINERY GAS TREATING PROCESS

1. Introduction

2. The role and location of gas plant in refinery

3. Product treatment plant

4. LPG drying unit

5. Sweetening processes

6. LPG Fractionation plant

7. The distillation of the Light Ends from crude oil

8. SAT gas processing plant

9. UNSAT gas processing plant

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1. Introduction

GAS PLANT

Types of gas?8/169

Crude Distillation Unit (CDU)

Continuous Catalytic Reforming Unit (CCR) Hydrotreater Unit (naphtha, kerosene, diesel, VGO)

Delayed Coking Unit

Isomerization Unit

Other units

Residue Fluid Catalytic Cracking Unit (RFCC) main feedstock for gas recovery

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1. Introduction

Types of gas According to the source of gas:

Gas obtained from the distillation

Gas obtained from the processing

According to the chemical composition:Saturated gas: CDU, CCR, HTU

Unsaturated gas: FCC, Coking

According to the acid gas content:

Sour gas: H 2S > 1 % vol or CO 2 > 2 % volSweet gas: H 2S 1 % vol and CO 2 2 % vol

H2S and CO 2 may accumulate in dangerous concentrations

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When fractionation saturated gas Products

Fraction Application

Methane, ethane Fuel gas Refrigerant

Propane Feedstock for Liquefied petroleum gas (LPG) process Refrigeranti-butane Alkylation process

Rubber productionn-butane Butadiene production

Feedstock for LPG process Gasoline blending

i-pentane Rubber production Gasoline blending (high octane number, RON = 92.3)

n-pentane Isomerization process

1. Introduction

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Fraction Application

Propane; propylene Polymerization process Alkylation process

Petrochemical raw materials

Butane; butylene Alkylation process

Poly isobutylene production

Rubber production ...

Ethane; ethylene; pentane Petrochemical raw materials

1. Introduction

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When fractionation unsaturated gas Products

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The role of gas plant is:

Collecting

Processing

Separating

Location of the gas recovery plant can differ in the refinery,

depends on the different purposes of the refineries


gas from the various units for other purposes

which depends on the feed, product and specific

purpose, and the demand of each refinery

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Saturated gas

Unsaturated gas

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Propane andbutane

Sulphurcompounds

Residualwater

Productspecifications

Treatment

a twin fixed-bedmolecular sieve

Treatment process?

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Operating variable Units Propane Butane

Pressure Bar 22.4 10.7

Temperature 0C 43.3 43.3

Phase Liquid Liquid

Molecular Sieve Product Treating Process Operating Conditions

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43.3

4.6

15.2

22.4

10.7

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Contaminants Units Propane Butane

H2O wt ppm 10 Trace

H2S wt ppm 100 Trace

COS wt ppm 34 Trace

CH 3SH wt ppm 100 40

C 2H5SH wt ppm Trace 220

Typical Contaminant Level in Untreated LPG

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Saudi Aramco product specification / refrigeratedPropane LPG

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Saudi Aramco product specification / refrigeratedButane LPG

Remove Residual water + Sulphur compounds

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4. LPG DRYING UNIT

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1. Purpose: Reduce water content in the Refinery LPG

product in order to meet final product commercial

specification before sending to product storage

2. Feedstock:

C 3 Stream from

Delayed Cocker Unit

C3 Stream from

Hydrocracking Unit

C 3 Stream from

FCC Unit

Source

Extractive sweetening

with COS removal

followed by C3/C4

fractionation section

Caustic treatmentfollowed by C3/C4


Caustic treatmentfollowed by C3/C4


Water Content Saturated in water Saturated in water Saturated in water

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4. LPG DRYING UNIT

The LPG Drying Unit includes:Propane Dryer Beds (Adsorber)

Propane Regeneration Section (Heater, cooler and

associated facilities) (Desorber)

Propane transfer pump to storage

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4. LPG DRYING UNIT

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Most commonly used method for LPG drying is adsorption The adsorption method is capable of drying and

sweetening simultaneously ?

The LPG Drying Unit includes:

Propane Dryer Beds (Adsorber)Propane Regeneration Section (Heater, cooler andassociated facilities) (Desorber)Propane transfer pump to storage

Molecule Diameter, A o

H 2 O 2.75

H 2 S 4.1CO 2 4.7

C3

6.3

C 4 6.5

Zeolite 4A or 5A

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Process flow diagrams (PFD)

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Process flow diagrams (PFD)

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Dehydration by adsorption

87

6

4

2

1 : Desorption2 : Adsorption

: Close valve: Open valve

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H2S

Corrosivematerial

Highlytoxic

Safety limit of H 2S inworking area is

usually < 20 ppm

To prevent the effectof corrosion in

process equipment,H2S concentrationmust be < 43 ppm

The predominant sulphur compounds

have an unpleasant smell

Corrosive and disturb the fuel stability

due to gum formation

remove H 2S + mercaptans

(RSH) from refinery streams

RSH

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a. H2S removal

Absorption by amine

Adsorption same principle of gas dryingb. Sulfur recovery Claus process

c. Mercaptan removal Merox process

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Absorption of Acid Gases by Amines

a. H 2S removal

Typical H 2Sremoval plantin a refinery

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Absorption of Acid Gases by AminesThe most commonly used amines in gas treating: MEA, DEA, MDEA

DEA is much less corrosive to carbon steel and less volatile than MEA

MDEA is much less reactive than either DEA or MEA

The reactions take place in the DEA process:

H2S + R 2NH R 2NH2+ +HS -

CO 2 + 2R 2NH R 2NCOO - + R 2NH2+

CO 2 + H 2O + R 2NH R 2NH2+

5. Acid gas processing and mercaptans removal

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Primary amineSecondary

amine Tertiary amine

Chemical formula

Type MEA DEA MDEA

Molecular weight 61 105 119

Solvent wt% in solution 15 20 20 35 40 55Circulation (gal/mol AG) 100 165 60 125 65 110

H2S/CO 2 selectivity 1 1 3

Steam (lb/gal) 1.0 1.2 0.9 1.1 0.9 1.1

Max. AG flow (m 3 /d) 70,000 14,000 40,000

Comparison of amine solvents

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Counter-current absorption of Acid Gases by Amines

Process description?

Th li i fl h f MEA

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The preliminary process flow sheet for a MEAtreating plant

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Feedstock: Acid gas streams (contain H 2S)

Purpose: Reduce the sulphur dioxide (SO 2) emissions in order to

meet environmental guidelines

Gases with an H 2S content of over 25% are suitable for the

recovery of sulphur in the Claus process.

The main reaction:

2H 2S + O 2 2S + 2H 2O H = - 186.6kJ/mol

b. Sulphur Recovery Claus Unit

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Catalytic sectionThermal section

Air to the acid gas iscontrolled such that 1/3 ofall H 2S is converted to SO 2

In the thermal stage of Claus process, if moreoxygen is added, the occurred reaction is:

2H 2S + 3O 2 2SO 2 + 2H 2O


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H =-518 kJ/mol

H =-41,8 kJ/mol

Highly exothermic Over 2.6 tons of steam willbe generated / ton of S yield

2H 2S+O 2 2S+2H 2O, H = - 186.6kJ/mol

Activated alumina orHeating is necessary to prevent

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Activated alumina ortitanium dioxide is used

g y psulphur condensation in the catalyst

bed avoid catalyst fouling

The catalytic conversion ismaximized at lower T, butabove the dew point of S

A typical Claus process with 2 catalytic stagesyields 96% of the S in the input stream

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Typical two bed Claus process catalytic converter vessel

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If the acid gas feed contains COS and/or CS 2, they are

hydrolyzed at high temperature:

COS + H 2O H2S + CO 2

CS 2 + 2H 2O 2H 2S + CO 2


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The residual gas from the Claus process is commonly called tail gas

The tail gas still containing combustible components and

sulphur compounds (H 2S, H 2 and CO) is either burned in anincineration unit or further desulphurized in a downstream tail

gas clean-up unit (TGCU):

2H2S + SO

2 3S + 2H

2O

Incinerating the residual H 2S after sulphur recovery produces SO 2.

Therefore, further sulphur recovery is done for the tail gases.

TGCU process can reduce SO 2 to 0.15 vol% and H 2S to 0.3 vol%.

Tail Gas Clean Up


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Typical Tail gas clean-up scheme

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The principle of mercaptans removal is oxidation (called

MEROX process )

The catalytic oxidation of RSH in the presence of O 2

and alkalinity:

Air provides the O 2

Caustic soda provides the alkalinity

c. Mercaptans Removal

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Role of MEROX in a refinery

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The equilibrium occurs between the RSH oily phase and the RSH

that dissolves in the aqueous phase

Extraction equilibrium is favoured by lower molecular weight

mercaptans and lower temperatures

The feedstock is passed through a caustic prewash to reduce the

acid

The operating pressure is chosen to assure that the air required forsweetening is completely dissolved at the operating temperature

Sand filter containing a simple bed of coarse sand: remove free

water and a portion of the dissolved water from the product


Mercaptans Removal

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Conventional Meroxprocess unit for

extracting mercaptansfrom LPG

To remove any H S

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To remove any H 2Sthat would interferewith the sweetening

Extraction equilibrium is favoured bylower MW mercaptans and lower T

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The sweetened LPG exits the tower and flows through:- a caustic settler vessel to remove any entrained caustic,

- a water wash vessel to further remove any residual entrained caustic- a vessel containing a bed of rock salt to remove any entrained water.

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The oxidizer vessel has a packed bed to favorize this reaction.The caustic-RSSR mixture then flows into the separator vessel:a lower layer of "lean" Merox caustic and an upper layer ofRSSR. The vertical section of the separator is for thedisengagement and venting of excess air and includesa Raschig ring section to prevent entrainment of any RSSR in

the vented air. The RSSR are withdrawn from the separator androuted to fuel storage or to a hydrotreater unit.

Conventional Merox process unit for sweetening jet

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Conventional Merox process unit for sweetening jetfuel or kerosene

l

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The conventional version of this process uses air and caustic soda

(NaOH) to sweeten kerosene feedstock

The caustic soda pre-wash to reduce the naphthenic acids

Air is injected into the feedstock upstream of the reactor

The operating pressure is chosen to assure that the air required

for sweetening will be completely dissolved at the operating

temperature

The water wash removes trace quantities of caustic soda and

water soluble surfactant.

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Kerosene MEROX


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Deethanizer DebutanizerDepropanizer50/169

C2

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Deethanizer 51/169

26.9bar

Partialcondenser

(-6.67 C)

98% of the C 3 in the deethanizerfeed is recovered in the bottomproduct:

= %

The bottom product contains 0.8mole % C

?bar

Partial or totalcondenser ?

( ? C)

1 C10/11

C3 +

Total condenser Total condenserC2

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Depropanizer 52/169

20bar

Deethanizer

26.9bar

Debutanizer

7.6bar

C3 +

C3

C4 +

C4

C5 +

C1 C 10/11

7 Th di ill i f h Li h E d f d il

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The light ends unit is the only process in a refinery configuration that is

designed to separate almost pure components from the crude oil, in

particularly, the butanes and propanes to satisfy a market of portable

cooking fuel and industrial fuels.

That these products can be suitably compressed and stored in small, easily

handled containers at ambient temperatures p

The introduction of the No Lead in gasoline program during the late 1960s

set the scene for the need of Octane sources additional to the Aromatics

provided by high severity catalytic reforming.

A source of such high-octane additives is found in some isomers of C 4 and

C 5 the need for light end processes which included the separation of i-C 4

from the C 4 stream and also i-C 5 from the light naphtha stream.

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The light ends of crude oil is considered as those fractions in the crude

that have a boiling point below cyclo-hexane.

The light ends distillation units however include the separation of the light

naphtha cut, which is predominately pentanes and cyclopentanes, from

heavy naphtha which contains the hexanes and heavier hydrocarbons

necessary for the catalytic reformer feed.

The feed to the light ends distillation process is usually the full range

naphtha distillate from the atmospheric crude distillation unit overhead

condensate drum.

In many cases the distillates from stabilizing cracker and reformer

products are added to the crude unit overhead distillate to be included in

the light end unit feed.55/169



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In this configuration the total feed to the unit is debutanized in

the first tower . The C 4s and lighter HC are totally condensed and

collected in the columns overhead drum. Part of this condensate is

returned to the tower top tray as reflux.

The remainder is routed to a depropanizer column. The bottomproduct from the debutanizer is the full range naphtha product.

This enters a naphtha splitter column where it is fractionated to give

an overhead distillate of LN and a bottom product of HN.The de-propanizer separates the debutanizer overhead distillate to

give a C 3 fraction as an overhead distillate stream and the C 4

fraction as the bottom product.56/169


7 Th di till ti f th Li ht E d f d il

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The overhead distillate is fractionated in a de-ethanizer column to produce a

rich propane stream (propane LPG) as the bottom product.

The overheads from this column is predominately hydrocarbons lighter than

propane.

This stream is only partially condensed to provide reflux for the tower.

The uncondensed vapor is normally routed to the refinerys fuel gas system.

The products from the light ends unit are as follows:

Naphtha Splitter Light Naphtha (overhead distillate)

Heavy Naphtha (bottom product Reformer feed)De-propanizer Butane LPG (bottom product)

De-ethanizer Propane LPG (bottom product)

Fuel Gas (overhead vapor).

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7 Th di till ti f th Li ht E d f d il

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Cold feed

The condition of the feed entering the tower is very important to

the tower operation. Ideally the feed should enter the tower at

as close to a calculated feed tray temperature as possible .

If the feed is well below its bubble point on entering the tower,

several trays below the feed tray are taken up for heat transfer

before effective mass transfer can begin.

This could prevent the specified product separation occurring and

tray efficiency in this section of the tower falls off dramatically.

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7 Th di till ti f th Light E d f d il

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Hot feed

This situation is probably the more serious regarding feed condition. If

the feed enters at a temperature far above its bubble point its resulting

enthalpy will be such as to reduce the reboiler duty.

This will occur automatically as the tower must always be in heat

balance. The tower controls will maintain the product quantity and split.

However, if the reboiler duty is drastically reduced insufficient stripper

vapors will be available for the stripping function Poor separation will

result. As a rule of thumb the stripping vapor to the bottom tray must be

at least 70% mole of the bottom product make.

In super fractionation such as a de-isopentanizer this figure would be at

least 80

100% of bottoms make.59/169

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Saturated gases come from: CDU, CCR, HTU

Saturated gas plant is often referred to as LPG Recovery unit

Objective of the LPG recovery unit:

Collecting C 3/C 4 rich streams

Recovering the C 3/C 4 fractionTreating the recovered LPG to commercial specifications

Feedstock Collection:

LPG from catalytic reforming unit,LPG from Naphtha Hydrotreating Unit,

LPG from GO HDS unit and VGO HDS unit and C 5/C 6

Isomerization Unit

7. SAT GAS PROCESSING PLANT

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Sweetening

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Absorber/Deethanizer section

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LPG Recovery Debutanizer section

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The debutanizer is reboiled, usingsteam under FRC reset by column

sensitive tray temperature control

TopThe sensitive plate plate

h i h

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Sensitive Plate

Top

Bottom

FEED

whose temperature is themost sensitive in an almostsymmetric way to changesof material balance

Column sensitive tray temperature control

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Column sensitive tray temperature controlIn case of: The sensitive tray in

a. The stripping section b. The rectifying section


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LPG wash section


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Depropanizer section

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1 FCCU gas recovery section

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1. FCCU gas recovery section

De-butanizer section

separates LPG fromgasoline

LPG Amine Absorber removes H 2S by counter-

current absorption with DEA


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Secondary absorber recovers gasoline lightfractions from the overhead gas from the primary

absorber C-1907 70/169


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Depropanizer section

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2 Delay coker gas recovery section

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2. Delay coker gas recovery section

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3. Unsaturated LPG sweetening unit

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As liquid LPG sour cut, originated from upstream Delayed Coker

Unit, is rich mainly with RSHs

Treating to remove sulphur in order to meet product specifications

The LPG cut mercaptans removal process, fed with liquid LPG from

the Delayed Coker Unit.The relevant sweet LPG cut will be sent to Delayed Coker unit

C3/C4 Splitter section.

The Unsaturated LPG Sweetening unit includes 3 sections:LPG reaction section

Caustic regeneration section

Air compression package77/169


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LPG

reactionsection

Caustic Prewash:

NaOH+H 2S NaSH+H 2OExtraction:

RSH+NaOH NaSR+H 2O


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Caustic regeneration section: 4NaSR + O 2 + 2H 2O 2RSSR + 4NaOH

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