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Naphtha Hydrotreating UnitNaphtha Hydrotreating UnitNaphtha Hydrotreating UnitNaphtha Hydrotreating Unit
Prepared by :
Mohamed Fathy Mohamed
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 .
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.
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.
NAPHTHA HYDROTREATING
Naphtha Hydro-
Straight Run Naphtha
Catalytic cracking Naphtha.
Delayed Coking Naphtha.
Catalytic Reforming
UnitHydro-treatingVisbreaking Naphtha.
LightNaphtha
Isomerization
Gasoline
FCC Naphtha
Catalytic Reforming UnitCatalytic Reforming Unit
Using expensive Platinium catalyst on chlorinated alumina. Dehydrogenation of Nahthenes , Dehydrocyclization & Isomerization of
Paraffins.
NAPHTHA HYDROTREATING
Light Naphtha IsomerizationLight Naphtha Isomerization
Using Pt catalyst on highly chlorinated alumina. Isomerization of Pentane and Hexane
NAPHTHA HYDROTREATING
Impurities RemovalImpurities Removal
Sulfur Removal Nitrogen Removal Oxygen Removal
NAPHTHA HYDROTREATING
Oxygen RemovalMetallic Compounds Unsaturated Products Halide Removal
Sulfur RemovalSulfur Removal
Mercaptans:
Sulfides:
NAPHTHA HYDROTREATING
Disulfide:
Cyclic sulfide:
Sulfur RemovalSulfur Removal
Thiophenes:
NAPHTHA HYDROTREATING
Benzothiophenes:
Dibenzothiophenes
Sulfur RemovalSulfur Removal
Distribution of sulfur compounds in the cuts from distillation of a crude with 1.2%wt sulfur.
NAPHTHA HYDROTREATING
Nitrogen RemovalNitrogen Removal
Pyridines:
NAPHTHA HYDROTREATING
Quinoline:
Isoquinolines:
Pyrroles:
Nitrogen RemovalNitrogen Removal
Indoles:
NAPHTHA HYDROTREATING
Carbazoles:
Methylamine:
OxygenOxygen RemovalRemoval
Phenols:
NAPHTHA HYDROTREATING
OxygenOxygen RemovalRemoval
Naphthenic acids:
NAPHTHA HYDROTREATING
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
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.
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.
NAPHTHA HYDROTREATING
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.
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
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
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
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
Hydrotreating ProcessHydrotreating ProcessNAPHTHA HYDROTREATING
2. Fluidized Naphtha Hydrotreating
Maintain catalyst in its active form.
Limited Applications due to its complicated design.
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.
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.
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.
Hydrotreating ProcessHydrotreating ProcessNAPHTHA HYDROTREATING
Distillate hydrotreating processes incorporated in a refinery flow scheme
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
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
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
NAPHTHA HYDROTREATING
Process VariablesProcess VariablesNAPHTHA HYDROTREATING
Temperature Reactor Pressure
Hydrogen to Hydrocarbon Ratio Hydrogen to Hydrocarbon Ratio Space Velocity
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 .
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
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.
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
Hydrogen to Hydrocarbon RatioHydrogen to Hydrocarbon Ratio
Effect of injecting hydrogen between two catalystbeds
NAPHTHA HYDROTREATING
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
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
NAPHTHA HYDROTREATING
Reaction Mechanisms for aliphatic Hydrocarbons.
Reactions KineticsReactions Kinetics
1) Elimination
2) Substitution
NAPHTHA HYDROTREATING
Reaction Mechanisms for Aromatic Hydrocarbons.
Reactions KineticsReactions Kinetics
1) Hydro-desulfurization of dibenzothiophene
2) Denitrogenation of Quinoline
NAPHTHA HYDROTREATING
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
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
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
Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING
Catalyst sulfiding The active phase of hydrotreating catalysts is
produced by sulfurizing the oxide form.
Reactions:
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
Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING
Hydrotreating reactorsand its internals :
Catalyst of Naphtha HydrotreatingCatalyst of Naphtha HydrotreatingNAPHTHA HYDROTREATING
Weight Average Catalytic Bed Temperature (WABT) :Bed Temperature (WABT) :
NAPHTHA HYDROTREATING