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Jul 06, 2014 Hydrocracking is essentially the combination of two processes: hydrogenation and cracking. Therefore, hydrocracking utilizes a bifunctional catalyst. The catalysts (highly active noble metals used for hydrogenation e.g. Pt and Pd) used in hydrocracking are very susceptible to poisoning and great care must be taken to remove sulfur from the feedstock. In a catalytic hydrocracking process wherein stream of mineral oil feedstock is contacted in admixture; with hydrogen, and under hydrocracking conditions, with a hydrocracking catalyst comprising a minor proportion of a Group VIII noble metal hydrogenating component deposited upon a zeolitic alumino-silicate molecular sieve cracking base having.
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Figure 1 – Basic Process Flow Diagram for Two stages Hydrocracking UnitsAccording to the feed stream quality (contaminant content), is necessary hydrotreating reactors installation upstream of the hydrocracking reactors, these reactors act like guard bed to protect the hydrocracking catalyst.The principal contaminant of hydrocracking catalyst is nitrogen, which can be present in two forms: Ammonia and organic nitrogen.Ammonia (NH3), produced during the hydrotreating step, have temporary effect reducing the activity of the acid sites, mainly damaging the cracking reactions. In some cases, the increase of ammonia concentration in the catalytic bed is used like an operational variable to control the hydrocracking catalyst activity. Figure 4 – Typical Arrangement for Two Stage Hydrocracking Units with Intermediate Gas SeparationIn this case, the catalytic deactivation process is minimized by the reduction in the NH3 and H2S concentration in the hydrocracking reactor.Like cited earlier, the hydrocracking units demand high capital investments, mainly to operate under high hydrogen partial pressures, it’s necessary to install larger hydrogen production units, which is another high costly process. However, face of the crescent demand for high-quality derivates, the investment can be economically attractive.The Residue Hydrocracking Units have severity even greater than units dedicated to treating lighter feed streams (gas oils).
Not to be confused with.Hydrodesulfurization ( HDS) is a chemical process widely used to remove (S) from and from, such as,. The purpose of removing the sulfur, and creating products such as, is to reduce the ( SO2) emissions that result from using those fuels in automotive, railroad, gas or oil burning, residential and industrial, and other forms of fuel.Another important reason for removing sulfur from the streams within a is that sulfur, even in extremely low concentrations, the catalysts ( and ) in the units that are subsequently used to upgrade the of the naphtha streams.The industrial hydrodesulfurization processes include facilities for the capture and removal of the resulting ( H2S) gas. In, the hydrogen sulfide gas is then subsequently converted into byproduct or ( H2SO4). In fact, the vast majority of the 64,000,000 metric tons of sulfur produced worldwide in 2005 was byproduct sulfur from refineries and other hydrocarbon processing plants.An HDS unit in the petroleum refining industry is also often referred to as a hydrotreater. Schematic diagram of a typical Hydrodesulfurization (HDS) unit in a petroleum refineryThe liquid feed (at the bottom left in the diagram) is pumped up to the required elevated pressure and is joined by a stream of hydrogen-rich recycle gas. The resulting liquid-gas mixture is preheated by flowing through a. The preheated feed then flows through a where the feed mixture is totally and heated to the required elevated temperature before entering the reactor and flowing through a fixed-bed of catalyst where the hydrodesulfurization reaction takes place.The hot reaction products are partially cooled by flowing through the heat exchanger where the reactor feed was preheated and then flows through a water-cooled heat exchanger before it flows through the pressure controller (PC) and undergoes a pressure reduction down to about 3 to 5 atmospheres.
The resulting mixture of liquid and gas enters the gas separator at about 35 °C and 3 to 5 atmospheres of absolute pressure.Most of the hydrogen-rich gas from the gas separator vessel is recycle gas, which is routed through an for removal of the reaction product H2S that it contains. The H2S-free hydrogen-rich gas is then recycled back for reuse in the reactor section. Any excess gas from the gas separator vessel joins the from the stripping of the reaction product liquid.The liquid from the gas separator vessel is routed through a stripper tower. The bottoms product from the stripper is the final desulfurized liquid product from hydrodesulfurization unit.The overhead sour gas from the stripper contains hydrogen, and, perhaps, some and heavier components. That sour gas is sent to the refinery's central gas processing plant for removal of the hydrogen sulfide in the refinery's main unit and through a series of distillation towers for recovery of propane, butane and or heavier components. The residual hydrogen, methane, ethane, and some propane is used as refinery fuel gas. The hydrogen sulfide removed and recovered by the amine gas treating unit is subsequently converted to elemental sulfur in a unit or to sulfuric acid in a or in the conventional.Note that the above description assumes that the HDS unit feed contains no.
If the feed does contain olefins (for example, the feed is a naphtha derived from a refinery fluid catalytic cracker (FCC) unit), then the overhead gas from the HDS stripper may also contain some, and, or heavier components.It should also be noted that the amine solution to and from the recycle gas contactor comes from and is returned to the refinery's main amine gas treating unit.Sulfur compounds in refinery HDS feedstocks The refinery HDS feedstocks (naphtha, kerosene, diesel oil, and heavier oils) contain a wide range of sulfur compounds, including, organic and, and many others.