Naphtha hydrotreating

Technology to Improve HSD Quality[1-2,17-19]
DHDS(35+bar pressure)	When one sulfur reduction is required
DHDT(85+bar pressure)	Large sulfur reduction & high cetane gain coupled with T-95 point improvement
Hydrocracker	For middle distillate maximisation along with cetane improvement & very high sulfur reduction

 

• Hydrotreating^[1-2]
  • Remove hetero atoms and saturate carbon-carbon bonds Sulfur, nitrogen, oxygen, and metals removedOlefinic & aromatic bonds saturated
  • Reduce average molecular weight & produce higher yields of fuel products
  • Minimal cracking
  • Minimal conversion – 10% to 20% typical
  • Products suitable for further processing or final blending
  • Reforming, catalytic cracking, hydrocracking
• Hydrocracking
• Severe form of hydroprocessing
• Break carbon-carbon bonds
• Drastic reduction of molecular weight
• 50%+ conversion
• Products more appropriate for diesel than gasoline

Hydroprocessing Catalysts

Hydrotreating Desired function Cobalt molybdenum : sulfur removal and olefin saturation Nickel molybdenum: nitrogen removal & aromatic saturation Reactor configurationFixed bed – temperature to control final sulfur content Selective catalysts for sulfur removal without olefin saturation Maintaining high octane rating Hydrocracking Crystalline silica alumina base with a rare earth metal deposited in the lattice Platinum, palladium, tungsten, and/or nickel Feed stock must first be hydrotreated Catalysts deactivate and coke does form even with hydrogen present Hydrocrackers require periodic regeneration of the fixed bed catalyst systems Channeling caused by coke accumulation a major concern Can create hot spots that can lead to temperature runaways Reactor configuration Ebullient beds – pelletized catalyst bed expanded by upflow of fluids Expanded circulating bed – allows continuous withdrawal of catalyst for regeneration

General Effects of Process Variables[1-2,12-16]

Reactor inlet temperature and pressure Increasing temperature increases hydrogenation but decreases the number of active catalyst sites Temperature control is used to offset the decline in catalyst activity Increasing pressure increases hydrogen partial pressure and increases the severity of hydrogenation Recycle hydrogen Require high concentration of hydrogen at reactor outlet Hydrogen amount is much more than stoichiometric High concentrations required to prevent coke laydown & poisoning of catalyst Particularly true for the heavier distillates containing resins and asphaltenes Purge hydrogen Removes light ends and helps maintain high hydrogen concentration

Naphtha hydrotreated primarily for sulfur removal Mostly mercaptans (RSH) and sulfides (R2S) Some disulfides (RSSR), and thiophenes (ring structures) Cobalt molybdenum on alumina most common catalyst Chemical hydrogen consumption typically 50 to 250 scf/bbl For desulfurization containing up to 1 wt% sulfur — 70 to 100 scf/bbl Significant nitrogen and sulfur removal — 250 scf/bbl

• Liquid hourly space velocity ~ 2
• Hydrogen Recycle about 2000 scf/bbl
• Stripper overhead vapour to saturate gas plant
  • Recovery of light hydrocarbons and remove H2S
• Fractionator Pentane/hexane overhead to isomerization
• Bottom to reformer

Hydrotreating[1-2,30-35]

Sulphur is converted to hydrogen sulphide H2S Added hydrogen breaks carbon-sulphur bonds & saturates remainining hydrogen carbons Creates some light ends Heavy distillates makes more light ends from breaking more complex sulphur molecules Form of sulphur bonds Sulphur is naphtha Mercaptans(Thiols) and sulfides In heavier feeds,more sulphur as Disulphides and Thiopenes Nitrogen is converted to ammonia(NH3) Pyridines and Pyyroles are nitrogen containing componds Nitrogen removal minor in naphtha hydrotreating As the feeds become heavier de-nitrogenation becomes more significant,such as heavy distillate and gas oil hydrotreating Nitrogen removal requires about 4 times as much hydrogen as equivalents of sulphur remova

Naphtha Hydrotreating-Hydrogen Consumption[1-2,30-35]

For desulphurisation containing upto 1 wt% sulphur 70 to 100 scf/bbl Higher nitrogen levels increase hydrogen consumption proportionately Signifant nitrogen and sulphur removal-250 scf/bbl

This is chemical hydrogen consumption Add for mechanical loss and loss with the light hydrocarbon vapours

Naphtha Hydrotreating - Process[1-2,30-35]

Feed & hydrogen fed to furnace Vapors passed down - flow over the catalyst bed Outlet vapors about 370°C Outlet cooled and flashed at 370°C to separate light ends Exchange with feed(for heat integration) Final exchange with cooling water Single stage flash adequate Bulk of flash gas recycled Flashed liquid fed to stripper for removal of light ends of hydrogen sulphide and sour water

Distillate Hydrotreating

In general , all liquid distillate Streams contain sulfur compounds that must be removed needs the treatment. Saturation of aromatics in diesel is essential to improve the cetane number.

Distillate Hydrotreating-Hydrogen Consumption[1-2,30-35]

Light distillate hydrotreating (kerosene and jet fuel) requires more hydrogen than Naphtha hydrotreating.

Heavy distillate (diesel) hydrotreating consumption quite variable

Can consume considerable quantities of hydrogen at higher severity Hydrogen consumption and operating pressure are a function of the stream being treated, the degree of sulfur and nitrogen removal, olefin saturation, aromatic ring saturation,…..

Typical conditions – 300oC – 425oC ; 300 psig and greater Modest temperature rise since reactions are exothermic

Hydrogen recycle rate starts at 2,000 scf/bbl; Consumption of 100 to 400 scf/bbl Conditions highly dependent upon feedstock Distillate (jet fuel & diesel) with 85% - 95% sulfur removal 300 psig & hydrogen consumption of 200-300 scf/bbl Saturation of diesel for cetane number improvement over 800 scf/bbl hydrogen & up to 1,000 psig

Fig:6.17 Typical Distillate Hydrotreater for Base Metal Catalyst

https://www.slideshare.net/hels92/chapter-6a-hydrotreating

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https://nptel.ac.in/courses/103/102/103102022/