Hydrotreating units

Acid gases are mainly hydrogen sulfide (H2S) originating essentially from hydrotreating units off-gas. Smaller quantities are also produced in thermal and catalytic cracking units. 

Hydrotreating units in the past were built with one reactor, to meet the 500 ppm S specification however, a second reactor is needed to cope with the actual requirements. Several attempts have been made also to change the operating conditions to improve performance of the units and to achieve the stipulated level of desulfurization. From a co-current fluid-dynamics, the first modification went into countercurrent feeding. In a countercurrent reactor, where hydrogen is fed at one end and the feed in the other, the most difficult to-desulfurize compounds, will react under the higher hydrogen concentration. The countercurrent operation introduces some other problems, such as hot spots and vapor-liquid contact. 

Sulfur is removed from a number of refinery process off-gas streams (sour gas) to meet the sulfur oxide emissions limits of the Clean Air Act and to recover salable elemental sulfur. Process off-gas streams, or sour gas, from the coker, catalytic cracking unit, hydrotreating units, and hydroprocessing units can contain high concentrations of hydrogen sulfide mixed with light refinery fuel gases. 

Product yields (Table 8-1) indicate that there is no coke. The distillates produced by this process are generally lower in the content of olefin hydrocarbons than the other thermal cracking process, comparatively easy to desulfurize in hydrotreating units, and compatible with straight run distillates. 

Hydrotreating reaction models are nicely exemplified by the Amoco Easy-Hard lump model of Figure 5. The global paths and the kinetics reported in this figure were taken from the review by Beaton and Bertolacini (3), which summarizes experimental results, the modelling, and commercialization of Amoco s hydrotreating unit In short, the subdivisions of resid into hard and easy fractions and gas oil into reactant and product fractions were required to account for kinetic nonlinearities. The seven lumps and 14 rate constants provided significant flexibility and were able to describe the kinetics of several relevant product fractions. 

Coker naphtha hydrotreating units with a range of silica contamination. 

The naphtha feed is first sent to a UOP naphtha hydrotreating unit (1) to remove sulfur and nitrogen compounds and then sent to a OCR Platforming unit (2) to reform paraffins and naphthenes to aromatics. 

For the hydrogen enrichment of uents from hydrotreating units, Monsanto s Prism TM process, using gas containing 60 to 75 per cent H2 (=15,006 m /h) available at 3.5 to 5.5.10 Paabsolute,fumishesaproductwithapurityof92to98percentvolume,witha yield of 80 to 90 per cent at 2.10 Pa absolute. 

Fina developed the technology which was practiced in their own refineries before they decided to license it in cooperation with Akzo Nobel to other companies. Akzo Nobel has successfully marketed the technology with eleven licenses sold today in Europe, North America and Japan. The process scheme is identical to typical hydrotreating units. Process conditions are similar to what is practiced in LGO or VGO hydrotreating or mild hydrocracking units. Catalysts applied in the process are only available under license. 

The objective of this process is the deep desulfurization of middistillate types of feedstocks. Exxon licensed hydrotreating units in the past, but decided that a new technology had to be developed for deep desulfurization of diesel oil. Main differences from the existing technology is the different desulfurization kinetics for deep desulfurization and the importance of a good... 

The process can be operated at moderate pressures, 50 - 70 bar at reactor outlet. Temperatures have to be low (below 320 °C) to achieve deep hydrogenation. Space velocities are low (below 0,5 hr ) if low product aromatic contents of e.g. 5 vol% are required. The first step of the process is not different from a typical diesel hydrotreating unit. Five different catalyst types in staged loading can be used to obtain the required desulfurization and hydrogenation level. Catalysts are only available under license. At the spring NPRA meeting of 1995 it was announced that 13 companies have taken a license. This impressive success is for an important... 

The INT-RI catalyst can be used in fixed bed hydrotreating units to improve the residue quality, from a high sulfur residual to a low sulfur fuel oil [6]. Tests were performed to demonstrate the technical feasibility of directly processing these residues, using atmospheric residue of Cerro Negro and Iranian Gach Saran crude oils as feedstocks. These residues are characterized by a higher content of asphaltenes and Conradson Carbon than the deasphalted oils [5,6]. Therefore, the effect of these two variables on the performance of the catalyst, can be evaluated. 

It is well-known that a new generation of hydrotreating catalysts prepared with a silica promoted alumina support has been developed and are in use in a number of commercial hydrotreating units. Improved and more flexible operation should be possible especially in thermally cracked feedstocks with these catalysts having a higher HDS activity and resistance to carbon deposition than conventional CoMo or NiMo catalysts. 

An example in Figure 7 presents the gas-liquid mixed phase activation for the presulfided catalyst (60 t) in a 120,000 BPSD Distillate Hydrotreating unit. The activation reactions started at 140 °C with exotherm of delta T of 39 °C at the maximum, which subsided within... 

It is probable that a combination of a lower temperatures (450 C) and higher pressures to those employed in this initial study will represent the optimum conditions for maintaining catalyst surface area. In order to prevent possible reduction of the promoter to the corresponding metal (Ni/Co), hydropyrolysis should be carried out in the presence of a small amount of hydrogen sulphide to help maintain the catalyst to remain in a reasonably fiilly sulfided form. Hydropyrolysis for the virtual complete carbon removal would need to be carried out off-line since the combination of temperature, pressure and flow rate required cannot be achieved in hydrotreating units. In terms of potential applications, carbon-supported catalysts may represent the major area since these cannot be regenerated oxidatively. 

Soft coke accounts for typically about one-third of the carbon on deactivated catalysts from gas oil hydrotreating units. The soft coke is highly polar in nature, but possesses significant aliphatic character. 

TABLE 9.3. Process Stream Data for the Diesel Hydrotreating Unit... 

FIGURE 10.17. Modifications to the diesel hydrotreating unit (the base case design as shown in Figure 9.14). 

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