Heavy Naphtha Platforming & CCR Technology #Download no.1

Post recommended by Eng. Mohamed Fathy, the author of this post and special thanks for his efforts in enrichment our blog

CCR / PLATFORMING


Function Of Unit
Converts low octane number naphtha into high octane gasoline product on continuous basis as basis as the catalyst is continuously regenerated in the CCR section.


Involved Reactions
Dehydrogenation of Naphthenes
Isomerisation of Naphthenes and Paraffins 
Dehydrocyclization of Paraffins
Hydrocracking 
Demethylation 
Dealkylation of Aromatics


Platforming Catalyst
 Platforming catalyst is Bifunctional type which has:
• Acidfunction
–  Responsible for Naphthenes Isomerisation and provided by Chloride Injection


• Metalfunction
– Responsible for Dehydrogenation and Dedydrocyclization provided by the metalsites



Platforming Reactions

Unit Feed Stocks

 Hydrotreated heavy naphtha having the following specs.:

Total Sulfur : <0.5 wt-ppm

Total Nitrogen: <0.5 wt-ppm

Distillation End Point : 204 °C (max)

 Lead: 20 wt-ppb (max)

Arsenic: 1 wt-ppb (max)

Iron: 1 wt-ppm(max)

Copper + Heavy Metals: 25 wt-ppb (max)

Fresh Feed Quality

 Feed with high EP (above 204 °C) are difficult to reform and cause high catalyst coking rate.

Sulphur content above 0.5 ppm will cause temporary poisoning for platinum and lower catalyst activity. 

Higher nitrogen content (above 0.5 ppm) will cause loss of acid site activity although hydrogen production will increase.

Product Specifications 

Plateformer Material Palance

ProcessFlow Diagram

Platforming Section

PLATFORMING UNIT

Plate Exchanger Advantages

Less capital outlay.

lower installation cost (piping, space,…..) 

Higher thermal efficiency

Extensive heat exchange area in a single compact unit 

Low pressure drop

Range between 0.35-1.5 barg

Low operating cost

less fouling, fewer flanges, accessibility for maintenance through top and bottom manway

PLATE HEAT EXCHANGER SIMPLIFIED OPERATIONS

PLATE HEAT EXCHANGER

DISTRIBUTION HEADER DETAILED DESIGN

Platforming Process Variables

Reactor 

Temperature

• Reactor Inlet

– Is the major parameter used to meet product quality requirements

• Temperature Difference

– Represents amount of reactions performed in each reactor

Liquid Hourly Space Velocity

 LHSV(hr-1) =  { volume of feed (/hr) } / { volume of catalyst in Reactors }

**The higher space velocity (lower Residence Time), the lower product RON.

**Increased Reactor Temperatures will offset this effect.

Reactor Pressure

 Decreasing reactor pressure will :

•Increase hydrogen and reformate yield

•Decrease temperature requirement to achieve target Octane Number

•Increase catalyst coking rate

Hydrogen/Hydrocarbon Ratio

 Increasing Hydrogen/Hydrocarbon Ratio will :

•Increase temperature requirement to achieve target RON

•Decrease catalyst cokingrate

H2/HC Ratio = { RG Purity X Recycle Gas Rate, Kmol/hr } / { Fresh Feed, Kmol/hr }

Reactor

The catalyst flows by gravity out from Reactor bottom to the top of the next reactor. Through catalyst Transfer pipe Catalyst continues to flow through each reactor flow through each reactor until it again reaches the bottom of the last reactor. 

This completes the transfer circuit. Catalyst flow between the reactors is through equally-spaced transfer lines designed to ensure uniform catalyst flow through the catalyst bed.

Heavy Naphtha Platforming & CCR Technology #Download no.1

2:12:00 PM Hydroprocessing, Hydrotreating, Naphtha Treating

Naphtha Hydrotreating

Post recommended by Eng. Mohamed Fathy, the author of this post and special thanks for his efforts in enrichment our blog

Naphtha

Naphtha is a complex mixture of liquid hydrocarbons, with boiling ranges of about 38 to 205 °C and with vapour pressures of about 0.69 bar.

Crude distillation, catalytic cracking, delayed coking and visbreaking units produce naphtha with low octane number and contains deferent types of contaminants at the same time .

Octane no. Improving

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

Chemical structure modification is achieved on an expensive Platinum catalyst at Catalytic reforming and Isomerization unit.

Sulfur, Nitrogen, Oxygen and other impurities in Naphtha work as a poisonous for Pt catalyst activity.

Hydrotreating is used to prepare a clean feedstock to protect catalyst used in naphtha reforming.

History of Naphtha Hydrotreating

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

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

1950's : First catalytic reforming process was commercialized. At the same time, the catalytic hydrodesulfurization of the naphtha feed to such reformers was also commercialized.

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

Impurities Removal

Sulfur Removal

Mercaptans:

Sulfides:

 Disulfide:

Cyclic sulfide:

Thiophenes:

Benzothiophenes:

  Dibenzothiophenes:

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

Nitrogen Removal

Pyridines:

Quinoline:

 Isoquinolines:

Pyrroles:

Indoles:

Carbazoles:

Methylamine:

Oxygen Removal

Phenols:

Naphthenic acids:

Metallic Compounds

Unsaturated Products

Linear olefin:

Cyclic olefin:

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

Halide 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.

Hydrotreating Processes

The Naphtha Hydrotreating Process is :

Catalytic refining process employing a selected catalyst and a hydrogen-rich gas stream .

Decompose organic sulfur, oxygen and nitrogen compounds contained in hydrocarbon fractions.

 In addition, hydrotreating removes Organo metallic compounds and saturates olefinic compounds.

Feeds and Products For Hydrotreating Unit

Hydrotreating Process

Naphtha Splitter Unit

Other Naphtha Treating Units

MERCAPTAN OXIDATION “MEROX”.

Low operating cost and investment requirement.

Ease of operation.

Limited Mercaptan treating not less than 5ppm.

Distillate hydrotreating processes incorporated in a refinery flow scheme

Hydrotreating Capacity Worldwide

Process Variables

Temperature

The treating severity increases directly with temperature to decrease the content of sulfur, nitrogen, oxygen, and metallic compoundsin the treated product.

Factors affect selecting treating temperature:

1- Feed Quality Changes.

2- Changes in Feed Rate.

 3-Catalyst End-Of-Run.Maximum temperature  catalyst can withstand , after this temprature , it  will not give the required product quality . catalyst can withstand , after this temprature , it will not give the required product quality .

When operating at too high temperature for maximum sulfur removal. Recombination of hydrogen sulfide with small amounts of olefins can result, producing mercaptans in the product

Reactor Pressure

As the partial pressure of hydrogen increases:

1) Rate of hydrogenation increases, the treating reactions are brought to a greater degree ofreactions are brought to a greater degree of completion.

2) Catalyst is generally effective for a longer time owing to less formation of carbonaceous deposits which deactivate the catalyst activity.

Increasing the hydrogen charge rate:

1) Increases the rates of hydrogenation reactions.

2) Reduce the tendency of coke formation on the2) Reduce the tendency of coke formation on the catalyst. Calculation:

Hydrogen to Hydrocarbon Ratio:

Effect of injecting hydrogen between two catalyst beds

Ratio Space 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 unit, which has bad effect on flow distribution of feed in the catalyst bed with the result of higher rate of cake formation High S.V. will require increased temperature for the same reaction severity with the result of high coke formation.

Calculation:

Reactions Kinetics

Relative reaction rates.

Desulfurization         100

Olefin Saturation      80

Denitrification Relative heats of reaction.

Olefin Saturation        100

Desulfurization             20

Denitrification               2

Catalyst Of Naphtha Hydrotreating

 Typical Composition of Hydrotreating Catalyst.

The primary causes of catalyst deactivation are:

1) Rateof carbon deposition on the catalyst.

2) The gradual accumulation of inorganic metal species picked up from the charge stock, ex: arsenic, lead, calcium, sodium, silicon and phosphorus

Catalyst sulfiding

The active phase of hydrotreating catalysts is produced by sulfurizing the oxide form.

 Reactions:

Catalyst Regenerating :

Hydrotreating catalysts become deactivated with time mainly because of coke deposition

Regeneration Reaction:

Life time of hydrotreating catalyst.

Hydrotreatingreactors and its internals :

Weight Average Catalytic  Bed Temperature (WABT) : 

Naphtha Hydrotreating

1:12:00 PM Hydroprocessing, Hydrotreating, Naphtha Treating