Hydrotreatment plant

Munoz, J.A.D., Alvarez, A., Ancheyta, J., Rodriguez, M.A., Marroqum, G. 2005. Process heat integration of a heavy crude hydrotreatment plant. Catal. Today 109(1 ) 214-218. Ring, Z.E., Missen, R.W. 1991. Trickle-bed reactors tracer study of liquid holdup and wetting efficiency at high temperature and pressure. Can. J. Chem. Eng. 69(4) 1016-1020. 

The cat products become feed to other units, such as alkylation and polymerization plants. High boiling liquid products are used to make lubes, and the gas goes into the refinery fuel systems. Cat cracking feed stocks come from atmospherie and vacuum stills, phenol extraction plants, hydrotreaters, deasphalters and cokers. 

Pilot plant tests were made to hydrotreat the whole SRC-II process product blends to remove nitrogen, sulfur, oxygen, and metals using fixed catalyst beds. 

Two proprietary Chevron catalysts were used in different pilot plant simulations of the syncrude hydrotreater ICR 106 and ICR 113. The ICR 106 catalyst contains nickel, tungsten, silica, and alumina and the ICR 113 catalyst contains nickel, molybdenum, silica, and alumina. An equal volume of inert, nonporous alumina was placed on top of the catalysts. This alumina served as a preheating zone. These catalysts operated satisfactorily for over one-half year (4000 hours) with the Illinois H-Coal syncrude. 

Figure 2. Hydrogen consumption vs. product nitrogen in the hydrotreat-ing of whole shale oil with ICR 106. Small pilot plant (O), about 1850 psia. Large pilot plant (U), about 1550 psia (A), approximately 1800 psia and (V), about 1650 psia.

Approximate yields for the hydrotreating and FCC processes are shown in Table X. The whole-oil hydrotreater data are based on results from the large-scale feed preparation run. The FCC data are described above. Since 41 LV % of the raw shale oil is fed to the FCC as hydrotreated 650° F+ bottoms, the FCC pilot plant yields were multiplied by 0.41 and reported as yield to raw shale oil. 

Hydrotreatment was carried out over a commercial UOP black oil conversion catalyst in bench-scale units of 200-800 mL catalyst capacity. Temperature range was 375°-450°C and the pressure range was 2000-3000 psig. Weight hourly space velocity (WHSV) varied from 0.1 to 1.0 depending on the heptane-insoluble content of the feed. A flow diagram of a typical plant is shown in Figure 1. The stripper bottoms usually... 

Hvdroaen Plant Natural gas (or refinery gas) and steam react catalytically to form carbon dioxide and hydrogen. The carbon dioxide is removed by absorption, and the hydrogen is used in hydrotreaters and the hydrocracker. 

To remove sulfur, the kerosene and diesel sidecuts are fed to hydrotreaters or hydrodesulfurizers (HDSs). Light gas-oil is fed to a hydrocracker to convert it to diesel and lighter products. The HDS units and hydrocracker consume hydrogen supplied by the catalytic reformer and a hydrogen manufacturing plant. 

One of the causes of catalyst deactivation is coking of the active phase or the support. The coke may even block the catalyst pores if large quantities are formed. Figure 7.22 represents the cross-section of a hydrotreatment catalyst sphere recovered from an industrial plant, A carbon-rich deposit with a thickness of approximately 10-20 pm forms an extremely dense barrier that prevents the reagents from reaching the active sites. This coke barrier , which could be produced during abnormal operation of the plant, explains the significant deactivation of this catalyst. 

Figure 7.22 Secondary electron images. Cross-section of a hydrotreatment catalyst sphere recovered from an industrial plant. A coke deposit around the edge of the sphere is evident.

With the exception of these newer hydrotreatment processes, all other processes used in modern base oil plants are physical separation techniques, i.e. all the essential constituents of the finished base oil were present in the original crude oil and processing methods are used to concentrate the desirable components by removing the less desirable components as by-products. 

Further processing of the hydrocracker residue is needed and Fig. 1.12 indicates the extra steps. Extraction and hydrotreatment are desirable to remove traces of polycyclic aromatics and improve product quality. De-waxing is essential because the hydrocracker residue is invariably waxy and distillation is needed to adjust boiling range and viscosity of the base oil. The economics of making special base oils from fuel hydrocracker residue are determined both by the hydrocracker operation and the additional processing at a conventional base oil plant, which is often at a separate site. 

Sun s extraction processes still produced a base stock with some color and color increased with base stock viscosity. Obviously an extraction process can only go so far in removing polyaromatics. Many plants built later put in a second-stage hydrotreater to stabilize products by conversion of the polyaromatics to polycyclic naphthenes rather than by separation. Hydrotreatment also has the capability to give water white base stocks, which many customers prefer. Sun did investigate this finishing route as well but do not appear to have pursued it commercially.17... 

Commercially, two plants used the BP process, one a converted 2000 bpd hydrotreater that came online in 1977,39 and the second a grass-roots plant built in 1983, but apparently shutdown in 1986.40 To the outside observer, the process seemed to suffer from the disadvantages shared with the urea process, namely that it could not handle the full scope of a refinery lube slate and incurred VI losses, and these may have been the reasons it (apparently) did not become more widespread. 

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