Hydroprocessing

Within the treating units, there are those processes that remove the impurities of the molecules. Usually these processes are done downstream of distillation and before entering the real refinery processes of the conversion units. Inside the crude oil there is a percentage of sulfur that varies according to the area of origin, together with it there are also other contaminants that must be removed before continuing with the other processes as they damage the catalysts and corrode the equipments. In the Table 2.4 you can see the difference in the consumption of hydrogen to purify crude oil from different fields around the world.

Hydrotreating processes have become increasingly important due to the continuous decrease of the sulfur concentration limits within the fuel. A premise must be made. Within hydroprocessing, the processes of hydrotreating, hydrodesulfurization and hydrocracking can be distinguished. The first two are the processes responsible for removing impurities

Figure 2.12: Isomerization using an aluminum chloride catalyst. [40]

Chapter 2

from the incoming feedstock; hydrodesulfurization is specific for the removal of sulfur, while hydrotreating removes other compounds called heteroatoms such as nitrogen and other metals. Hydrocracking does not compete with catalytic cracking units because they normally use gasoil distillates as raw materials, while hydrocracking uses raw materials that usually contain refracting gasoils derived from cracking and coking operations. Hydrocracking is therefore something more than a substitute for catalytic cracking.

The hydrotreatment processes have two purposes:

• Finishing: to meet the final qualification (content of contaminants);

• Purification: from poisons for downstream catalytic process.

Hydrotreating belongs to the class of conversions processes involving reaction with hydrogen. The term hydrotreating is limited to hydrogenolysis and hydrogenation reactions in which removal of hetero-atoms (especially S, N, O, metals) and some hydrogenation of the double bonds and of the aromatic rings take place. In hydrotreating the molecule size is not drastically altered. The equilibrium constants are large and positive for all reactions considered under practical reaction conditions (350-425 °C, shaded area).

Table 2.4: Hydrogen consumption during hydrotreating for various feedstocks.

All the hydrotreating reactions are exothermic with ΔH°<<0, and this has an impact on

The process cannot occur at lower temperatures since the kinetics reaction would be too slow (benzothiophenes exhibit a low reactivity) neither at higher temperatures since the conversion would be disfavoured by thermodynamics and by coke formation. So, we have a range of temperature at which we can operate to have an equilibrium between thermodynamic, kinetics, reactor size and costs. The hydrogenation reactions also involve the compounds with double bonds (such as olefins, aromatics). Depending on the catalyst and the operating conditions, these hydrogenation reactions occur before or after the desulfurization. There are some problems:

• Additional consumption of H2.

• Reduction of the octane number: hydrotreats the FCC gasoline coming out of the FCC, which is often high in sulfur (1-2 octane points less).

• Exothermic character.

The reaction occurs only in the presence of catalysts. They consist of mixed Co-Mo oxides or Ni-Mo oxides (more active but less selective) supported on γ-Al2O3that, under reaction conditions, are converted into sulphides.

The hydrodesulfurization units (HDS) allow to remove the sulphur compounds from the products (gas oils, kerosene). The HDS process is a catalytic type with a fixed bed under hydrogen pressure; the organic sulphur contained in the charge reacts through an exothermic reaction with hydrogen to form H2S; the streams produced are sent to an H2-rich gas separation section (which is recycled), to a H2S-rich gas separation section, which goes to subsequent treatment, and to a product separation section. In the reaction there is also a mild cracking of the feed which leads to the formation of by-products, such as Fuel Gas and Naphtha; the H2S formed is separated from the recycle gas by means of an amino scrub (HDS). Desulphurization is more intense; the temperature of exercise is higher (variable between 350 and 410 °C, in a pressure range indicatively between 35-40 kg/cm²). The outgoing products are desulphurized diesel oil, gas fuel, kerosene and gasoline. The Table 2.5 summarizes the general operating conditions of hydrocracking processes.

Hydrocracking is a catalytic oil refinery process of growing importance. Heavy gas oils and vacuum oils are converted into lighter products, i.e. naphtha, kerosene, and diesel oil. Factors contributing to its growing use are the increasing demand for transportation fuels and the decline in heavy fuel oil market. As the name implies, hydrocracking involves the cracking of a relatively heavy oil fraction into lighter products in the presence of H2 (contrasts the formation of unsaturated species and so coking). This distinguishes the process from the FCC process, which does not have hydrogen in the feed, and from the hydrotreating process, in which virtually no C-C bond breaking take place. Although at first sight one might expect that hydrocracking competes with fluid catalytic cracking, this is not the case; both processes work in team. The catalytic cracker takes the more easily cracked alkane-rich atmospheric and vacuum gas-oils as feedstocks, while the hydrocracker mainly uses more aromatic feeds, such as FCC cycle oils and distillates from thermal cracking processes. Hydrocracking can be viewed as a combination of hydrogenation and catalytic cracking. The former reaction is

Chapter 2

exothermic while the latter is endothermic. Since the heat required for cracking is less than the heat released by the hydrogenation reaction, the overall hydrocracking process is exothermic.

Table 2.5: Summary of the operating condition of hydrocracking processes.

As in hydrotreating, mixed metal sulphides (mainly NiS/MoS2 and NiS/WS2) are used to supply the hydrogenation function. Noble metals are also used. Practically no aromatics are present in the product mixture, since they are progressively converted, coke formation is much less than in the FCC process. Catalyst life is much longer, and catalyst is replaced every 1.5-2 years. The Figure 2.13 shows different possible configurations for hydrotreatment and hydrocracking.

Conditions Products

Solid acid catalyst (silica–alumina with rare earth metals, various other options)

Lower-molecular-weight paraffins

Temperature: 260°C–450°C Some methane, ethane, propane, and butane Pressure: 65–200 bar Hydrocarbon distillates (full range depending

on the feedstock) Frequent catalysts renewal for heavier

feedstocks

Residual tar (recycle)

Gas oil: catalyst life up to 3 years Contaminants (asphaltic constituents) deposited on the catalyst as coke or metals Heavy oil/tar sand bitumen: catalyst life less

than 1 year

Feedstocks Variations

Refractory (aromatic) streams Fixed bed (suitable for liquid feedstocks) Coker oils, cycle oils, gas oils Ebullating bed (suitable for heavy feedstocks) Residua (as a full hydrocracking or

hydrotreating option)

In some cases, asphaltic constituents (S, N, and metals) removed by deasphalting