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02 Naphtha Hydro Treating [Compatibility Mode]_opt

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A description of petrolem - naphtha hydro-treating.
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Naphtha Hydrotreating Unit Naphtha Hydrotreating Unit Prepared by : Mohamed Fathy Mohamed
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Page 1: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Naphtha Hydrotreating UnitNaphtha Hydrotreating UnitNaphtha Hydrotreating UnitNaphtha Hydrotreating Unit

Prepared by :

Mohamed Fathy Mohamed

Page 2: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NaphthaNaphthaNAPHTHA HYDROTREATING

Naphtha is a complex mixture of liquidhydrocarbons, with boiling ranges of about 38 to205 °C and with vapour pressures of about 0.69bar.bar.

Crude distillation, catalytic cracking, delayedcoking and visbreaking units produce naphthawith low octane number and contains deferenttypes of contaminants at the same time .

Page 3: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Octane no. ImprovementOctane no. ImprovementNAPHTHA HYDROTREATING

As more demand for high Gasoline Octane no. tomatch with modern motor.

Chemical structure modification is achieved onan expensive Platinum catalyst at Catalytican expensive Platinum catalyst at Catalyticreforming and Isomerization unit.

Sulfur, Nitrogen, Oxygen and other impurities inNaphtha work as a poisonous for Pt catalystactivity.

Hydrotreating is used to prepare a cleanfeedstock to protect catalyst used in naphthareforming.

Page 4: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

History of Naphtha HydrotreatingHistory of Naphtha HydrotreatingNAPHTHA HYDROTREATING

1897 : Paul Sabatier, “French chemist” discovered thefixation of hydrogen on hydrocarbon (ethylene, benzene)double bonds using nickel containing catalyst.

1903 : Wilhelm Normann, ”German chemist” applied 1903 : Wilhelm Normann, ”German chemist” appliedcatalytic hydrogenation to Saturate Organic acids.

1950's : First catalytic reforming process wascommercialized. At the same time, the catalytichydrodesulfurization of the naphtha feed to suchreformers was also commercialized.

Currently : All petroleum refineries world-wide have oneor more HDS units.

Page 5: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Naphtha Hydro-

Straight Run Naphtha

Catalytic cracking Naphtha.

Delayed Coking Naphtha.

Catalytic Reforming

UnitHydro-treatingVisbreaking Naphtha.

LightNaphtha

Isomerization

Gasoline

FCC Naphtha

Page 6: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Catalytic Reforming UnitCatalytic Reforming Unit

Using expensive Platinium catalyst on chlorinated alumina. Dehydrogenation of Nahthenes , Dehydrocyclization & Isomerization of

Paraffins.

NAPHTHA HYDROTREATING

Page 7: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Light Naphtha IsomerizationLight Naphtha Isomerization

Using Pt catalyst on highly chlorinated alumina. Isomerization of Pentane and Hexane

NAPHTHA HYDROTREATING

Page 8: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Impurities RemovalImpurities Removal

Sulfur Removal Nitrogen Removal Oxygen Removal

NAPHTHA HYDROTREATING

Oxygen RemovalMetallic Compounds Unsaturated Products Halide Removal

Page 9: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Sulfur RemovalSulfur Removal

Mercaptans:

Sulfides:

NAPHTHA HYDROTREATING

Disulfide:

Cyclic sulfide:

Page 10: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Sulfur RemovalSulfur Removal

Thiophenes:

NAPHTHA HYDROTREATING

Benzothiophenes:

Dibenzothiophenes

Page 11: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Sulfur RemovalSulfur Removal

Distribution of sulfur compounds in the cuts from distillation of a crude with 1.2%wt sulfur.

NAPHTHA HYDROTREATING

Page 12: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Nitrogen RemovalNitrogen Removal

Pyridines:

NAPHTHA HYDROTREATING

Quinoline:

Isoquinolines:

Pyrroles:

Page 13: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Nitrogen RemovalNitrogen Removal

Indoles:

NAPHTHA HYDROTREATING

Carbazoles:

Methylamine:

Page 14: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

OxygenOxygen RemovalRemoval

Phenols:

NAPHTHA HYDROTREATING

Page 15: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

OxygenOxygen RemovalRemoval

Naphthenic acids:

NAPHTHA HYDROTREATING

Page 16: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Metallic CompoundsMetallic Compounds

Impurities Source Main CutCatalyst Poison

Maximum content (%wt)

Ni,V CrudeDistillates Residues

Strong, deposit inside catalyst and plugging

10

Strong, deposit at top As Crude AllStrong, deposit at top

of reactor0.2-2

Hg Crude NaphthaSlight, only slightly

retainedTraces

NaCl Crude ResiduesStrong, deposit at top of reactor, generates

pressure loss1

Fe Crude and corrosion

AllSlight, deposit at top of reactor, generates

pressure loss1

Si Anti-foaming agents

DistillatesVery slight, deposit inside catalyst and

plugging0.1-0.5

Pb Recycled gasoline GasolineStrong, deposit at top

of bed5-10

Page 17: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Unsaturated ProductsUnsaturated Products

Linear olefin:

NAPHTHA HYDROTREATING

Cyclic olefin:

Aromatics Saturation: the-main unsaturated compounds present in oil,The number of aromatic rings increases with the distillation temperatureof the cut.

Page 18: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Halide RemovalHalide Removal

Organic halides can be decomposed in the Naphtha Hydrotreating Unit to the corresponding hydrogen halide, which is either absorbed in the reactor effluent water wash or taken overhead in the stripper gas.

Page 19: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Page 20: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Hydrotreating ProcessesHydrotreating Processes

The Naphtha Hydrotreating Process is :

Catalytic refining process employing a selectedcatalyst and a hydrogen-rich gas stream

NAPHTHA HYDROTREATING

Decompose organic sulfur, oxygen and nitrogencompounds contained in hydrocarbon fractions.

In addition, hydrotreating removes Organo-metallic compounds and saturates olefiniccompounds.

Page 21: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Feeds and Products for Hydrotreating UnitFeeds and Products for Hydrotreating Unit

NAPHTHA HYDROTREATING

Straight Run Naphtha

Coker Naphtha

Off Gas to Amine Treat

LPG to Amine TreatNAPHTHA

HYDROTREATING

UNIT

FCC Naphtha

Hydrocracked Naphtha

H2 Make up from CRU

LPG to Amine Treat

Light Naphtha to Isomerization

Heavy Naphtha to Platforming

Sour water to Water Stripper

Visbreaking Naphtha

Page 22: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Feed Surge Drum 02-V-01

Charge Heater 02-H-01

Reactor 02-R-01

Product Condenser 02-E-02

Stripper Receiver 02-

V-04

Stripper Condenser

02-E-05

Sour Gas To U-12

R.C.Suction Drum 02-V-03

02-K-01

P=3.7 bargT=102 oC

T=301 oC

P=45.5 bargT=325 oC

T=120 oC

T=55 oC

T=99 oC

T=50 oC

P=7.1 bargT=48 oC

Hydrotreating ProcessHydrotreating ProcessNAPHTHA HYDROTREATING

Unit 03

Combined Feed Exchanger 02-E-01

Separator 02-V-02

Stripper 02-T-01

Stripper Feed Bottom Exchanger 02-E-

03

V-04

HC

K

CD

U

DC

U

Tank-08-09

HP Steam

Condensate

Stripper Reboiler 02-E-04

Sour water to U15

Recycle Gas

Makeup H2 Gas from CCR

T=343 oC

P=52.3 bargT=77 oC

T=154 oC

T=201 oC

P=10.4barg

Page 23: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Naphtha Splitter03-T-01

Naphtha Splitter Condenser 03-E-03

Naphtha Splitter Receiver 03-V-01

Hydrotreated Light Naphtha

Sour Water to U15

P=0.7 bargT=72 oC

P=1.9 bargT=124 oC

T=86 oC

Naphtha splitter feed-Bottom Exchange 03-E-

01

Unit 02Naph. Splitter.

Bottom Cooler 03-E-02

Naph. Splitter OV.HD Cooler 03-

E-04Naph. Splitter Reboiler Heater 03-

H-01

Hydrotreated Heavy Naphtha

CCR Feed Penex Feed51-TK-8

51-TK-9

T=159 oC

T=148 oC

P=

10.3

bar

gT

=12

4 o C

Page 24: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Hydrotreating ProcessHydrotreating ProcessNAPHTHA HYDROTREATING

1. Fixed Bed Reactor

Feed System

Reactor System

Wash Water System

Separator System

Recycle Gas

Fractionation section

Stripper Section

Naphtha Splitter Section

Page 25: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Hydrotreating ProcessHydrotreating ProcessNAPHTHA HYDROTREATING

2. Fluidized Naphtha Hydrotreating

Maintain catalyst in its active form.

Limited Applications due to its complicated design.

Page 26: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

MERCAPTAN OXIDATION “MEROX”.

Other Naphtha treating UnitsOther Naphtha treating Units

Low operating cost and investment requirement.

Ease of operation.

Limited Mercaptan treating not less than 5ppm.

Page 27: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Objectives of Hydrotreating ProcessesObjectives of Hydrotreating Processes

Meeting finished product specifications

Kerosene hydrotreating:

a) Reduces mercaptans, sulfur, aromatics,

b) Improves smoke point.

NAPHTHA HYDROTREATING

b) Improves smoke point.

Gas oil hydrotreating:

a) Reduces sulfur, nitrogen, aromatics, olefins,

b) Improves cetane number, thermal stability.

Lube oil hydrofinishing:

a) Reduces sulfur, Conradson carbon (CCR),

b) Improves colour, oxidation stability.

Page 28: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Objectives of Hydrotreating ProcessesObjectives of Hydrotreating Processes

Preparing the feed for other refinery processes.

Naphtha hydrotreating : is a pre-treatment for isomerization and catalytic reforming processes. The objective is to reduce sulfur, nitrogen (<0.5

NAPHTHA HYDROTREATING

The objective is to reduce sulfur, nitrogen (<0.5 ppm wt), and olefins (< 0.1% wt).

Vacuum distillates: such as straight run,visbreaking, coking and deasphalted oil arehydrotreated as pre-treatment for FCC and hydro-crackers. Improves hydrogen content, crackability, results increased conversion, reducedimpurities in products, lower SOx and NOx

emissions in gases exiting the regenerator.

Page 29: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Hydrotreating ProcessHydrotreating ProcessNAPHTHA HYDROTREATING

Distillate hydrotreating processes incorporated in a refinery flow scheme

Page 30: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Petroleum CutCut Point

,CSpace

velocity,hr-1

H2Pressure,

bar

Temperature at Start of

Run

H2/HC ratio , nm3/m3

Typical operating conditions, for Distillate andResidue hydrodesulfurization.

Hydrotreating ProcessHydrotreating Process

,C velocity,hr-1bar Run

, nm3/m3

Naphtha 70 -180 1.0 – 5.0 14 260-300 100

Kerosene 160–240 1.0 – 4.0 28 300-340 150

Gas Oil 230-350 1.0 – 3.0 35 320-350 150-300

Vacuum Gas Oil

350-550 0.72 – 2.0 55 360-380 300-500

Atmospheric residue

350+ 0.3 - 0.5 100 - 130 360-380 1000

Vacuum residue

550+ 0.15 - 0.3 120 - 160 360-380 1000

Page 31: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Hydrotreating Capacity Worldwide.

Hydrotreating ProcessHydrotreating Process

Regions Capacity (Mt/year)

United States 320

Europe 180Europe 180Asia/Pacific 140

Rest of the world 260Total 900

Naphtha Residuals VGO Distillate

> 200

23

54

200

No. of

un

its

Page 32: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Hydrotreating ProcessHydrotreating Process

Egypt has eight petroleum refining companies distributedaround the country. In Cairo, Alexandria, Suez, Asyut andTanta. Six of eight companies have constructed a naphthahydrotreating unit.

Barrel/Day

0

5000

10000

15000

20000

25000

30000

35000

Midor Alexandria Suez Ameria Cairo Asyut

Barrel/Day

Page 33: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Page 34: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Process VariablesProcess VariablesNAPHTHA HYDROTREATING

Temperature Reactor Pressure

Hydrogen to Hydrocarbon Ratio Hydrogen to Hydrocarbon Ratio Space Velocity

Page 35: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

TemperatureTemperature

The treating severity increases directly withtemperature to decrease the content ofsulfur, nitrogen, oxygen, and metallic compoundsin the treated product.

NAPHTHA HYDROTREATING

in the treated product.

Factors affect selecting treating temperature:a) Feed Quality Changes.b) Changes in Feed Rate.c) Catalyst End-Of-Run. Maximum temperature

catalyst can withstand , after this temprature , itwill not give the required product quality .

Page 36: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

TemperatureTemperature

When operating at too high temperature formaximum sulfur removal. Recombination ofhydrogen sulfide with small amounts of olefinscan result, producing mercaptans in the product

NAPHTHA HYDROTREATING

can result, producing mercaptans in the product

Page 37: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Reactor PressureReactor Pressure

As the partial pressure of hydrogen increases:

1) Rate of hydrogenation increases, the treatingreactions are brought to a greater degree of

NAPHTHA HYDROTREATING

reactions are brought to a greater degree ofcompletion.

2) Catalyst is generally effective for a longer timeowing to less formation of carbonaceousdeposits which deactivate the catalyst activity.

Page 38: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Hydrogen to Hydrocarbon RatioHydrogen to Hydrocarbon Ratio

Increasing the hydrogen charge rate:

1) Increases the rates of hydrogenation reactions.2) Reduce the tendency of coke formation on the

NAPHTHA HYDROTREATING

2) Reduce the tendency of coke formation on thecatalyst.

Calculation:

/h)(mFeedNaphtha

Fraction)(MolePurity 2H x /h)3(NmReactor toGasRecycle/HCH

32

Page 39: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Hydrogen to Hydrocarbon RatioHydrogen to Hydrocarbon Ratio

Effect of injecting hydrogen between two catalystbeds

NAPHTHA HYDROTREATING

Page 40: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Space VelocitySpace Velocity

The severity of the operation is determined by therelative volumes of fresh feed and catalyst.

Operating with low S.V. means low capacity of theunit, which has bad effect on flow distribution of

NAPHTHA HYDROTREATING

unit, which has bad effect on flow distribution offeed in the catalyst bed with the result of higherrate of cake formation

High S.V. will require increased temperature forthe same reaction severity with the result of highcoke formation.

Calculation:

)(mcatalyst ofvolume

/h)(mhour per chargeofvolumeS.V.

3

3

Page 41: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Relative reaction rates.

Reactions KineticsReactions Kinetics

Desulfurization 100

Olefin Saturation 80

Denitrification 20

Relative heats of reaction.

Olefin Saturation 100

Desulfurization 20

Denitrification 2

Page 42: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Reaction Mechanisms for aliphatic Hydrocarbons.

Reactions KineticsReactions Kinetics

1) Elimination

2) Substitution

Page 43: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Reaction Mechanisms for Aromatic Hydrocarbons.

Reactions KineticsReactions Kinetics

1) Hydro-desulfurization of dibenzothiophene

2) Denitrogenation of Quinoline

Page 44: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING

Page 45: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING

Catalyst Protection, Aging and Poisonous.

Catalyst sulfiding. Catalyst sulfiding. Regenerating the Catalyst. Reactors Technology weight Average Catalytic Bed

Temperature

Page 46: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING

Typical Composition of Hydrotreating Catalyst.

Species Range, wt% Typical, wt%

Cobalt Oxide 1 – 5 3Nickel Oxide 1 - 5 2.5

Molybdenum Oxide 6 – 25 12Aluminium Oxide Balance Balance

Page 47: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING

The primary causes of catalyst deactivation are:

1) Rate of carbon deposition on the catalyst.

2) The gradual accumulation of inorganic speciespicked up from the charge stock, ex:arsenic, lead, calcium, sodium, silicon andphosphorus

Page 48: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING

Catalyst sulfiding The active phase of hydrotreating catalysts is

produced by sulfurizing the oxide form.

Reactions:

Page 49: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING

Catalyst Regenerating : Hydrotreating catalysts become deactivated with

time mainly because of coke deposition Regeneration Reaction: Regeneration Reaction:

Lifetime of hydrotreating catalyst.

Petroleum Cut Life time , yrsGasoline/Kerosene 4 to 10

Gas Oil, Vacuum Gas Oil 2 to 6

Residue 3 months to 1 year

Page 50: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING

Hydrotreating reactorsand its internals :

Page 51: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING

Weight Average Catalytic Bed Temperature (WABT) :Bed Temperature (WABT) :

Page 52: 02 Naphtha Hydro Treating [Compatibility Mode]_opt

NAPHTHA HYDROTREATING


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