575
Hydrotreating and Desulfurization
there are catalysts that are relatively inexpensive and can be used in the first reactor to remove a
large percentage of the metals. Subsequent reactors downstream of the first reactor would use normal hydrodesulfurization catalysts. Since the catalyst materials are proprietary, it is not possible to
identify them here. However, it is understood that such catalysts contain little or no metal promoters,
that is, nickel, cobalt, molybdenum. Metals removal on the order of 90% has been observed with
these materials.
Thus, one method of controlling demetallization is to employ separate smaller guard reactors
just ahead of the fixed-bed hydrodesulfurization reactor section. The preheated feed and hydrogen pass through the guard reactors that are filled with an appropriate catalyst for demetallization that is often the same as the catalyst used in the hydrodesulfurization section. The
advantage of this system is that it enables replacement of the most contaminated catalyst (guard
bed), where pressure drop is highest, without having to replace the entire inventory or shut down
the unit. The feedstock is alternated between guard reactors while catalyst in the idle guard
reactor is being replaced.
When the expanded-bed design is used, the first reactor could employ a low-cost catalyst (5% of
the cost of Co/Mo catalyst) to remove the metals and subsequent reactors can use the more selective
hydrodesulfurization catalyst. The demetallization catalyst can be added continuously without taking the reactor out of service and the spent demetallization catalyst can be loaded to more than 30%
vanadium, which makes it a valuable source of vanadium.
21.3 COMMERCIAL PROCESSES
Hydrotreating technology is one of the most commonly used refinery processes, designed to remove
contaminants such as sulfur, nitrogen, condensed ring aromatics, or metals. The feedstocks used in
the process range from naphtha to vacuum resid, and the products in most applications are used as
environmentally acceptable clean fuels. Hydrotreating technology has a long history of commercial application since the 1950s, with more than 500 licensed units placed in operation worldwide.
Furthermore, recent regulatory requirements to produce ultra-low-sulfur diesel (ULSD) and gasoline have created a very dynamic market as refiners must build new or revamp their existing assets
to produce the low-sulfur, even no-sulfur fuels.
The petroleum industry often employs two-stage processes in which the feedstock undergoes
both hydrotreating and hydrocracking. In the first, or pretreating, stage the main purpose is conversion of nitrogen compounds in the feed to hydrocarbons and to ammonia by hydrogenation and mild
hydrocracking. Typical conditions are 340°C–390°C (650°F–740°F), 150–2500 psi (1–17 MPa), and
a catalyst contact time of 0.5–1.5 h; up to 1.5% w/w hydrogen is absorbed, partly by conversion of
the nitrogen compounds but chiefly by aromatic compounds that are hydrogenated.
It is most important to reduce the nitrogen content of the product oil to <0.001% w/w (10 ppm).
This stage is usually carried out with a bifunctional catalyst containing hydrogenation promoters, for example, nickel and tungsten or molybdenum sulfides, on an acid support, such as
silica- alumina. The metal sulfides hydrogenate aromatics and nitrogen compounds and prevent
deposition of carbonaceous deposits; the acid support accelerates nitrogen removal as ammonia
by breaking carbon-nitrogen bonds. The catalyst is generally used as 1/8 × 1/8 in. (0.32 × 0.32 cm)
or 1/16 × 1/8 in. (0.16 × 0.32 cm) pellets, formed by extrusion.
Most of the hydrotreating cracking is accomplished in the first stage. Ammonia and some gasoline are usually removed from the first-stage product, and then the remaining first-stage product,
which is low in nitrogen compounds, is passed over the second-stage catalyst. Again, typical conditions are 300°C–370°C (600°F–700°F), 1500–2500 psi (10–17 MPa) hydrogen pressure, and
0.5–1.5 h contact time; 1%–1.5% w/w hydrogen may be absorbed. Conversion to gasoline or jet
fuel is seldom complete in one contact with the catalyst, so the lighter oils are removed by distillation of the products and the heavier, higher-boiling product combined with fresh feed and recycled
over the catalyst until it is completely converted.
Hydrotreating and Desulfurization
there are catalysts that are relatively inexpensive and can be used in the first reactor to remove a
large percentage of the metals. Subsequent reactors downstream of the first reactor would use normal hydrodesulfurization catalysts. Since the catalyst materials are proprietary, it is not possible to
identify them here. However, it is understood that such catalysts contain little or no metal promoters,
that is, nickel, cobalt, molybdenum. Metals removal on the order of 90% has been observed with
these materials.
Thus, one method of controlling demetallization is to employ separate smaller guard reactors
just ahead of the fixed-bed hydrodesulfurization reactor section. The preheated feed and hydrogen pass through the guard reactors that are filled with an appropriate catalyst for demetallization that is often the same as the catalyst used in the hydrodesulfurization section. The
advantage of this system is that it enables replacement of the most contaminated catalyst (guard
bed), where pressure drop is highest, without having to replace the entire inventory or shut down
the unit. The feedstock is alternated between guard reactors while catalyst in the idle guard
reactor is being replaced.
When the expanded-bed design is used, the first reactor could employ a low-cost catalyst (5% of
the cost of Co/Mo catalyst) to remove the metals and subsequent reactors can use the more selective
hydrodesulfurization catalyst. The demetallization catalyst can be added continuously without taking the reactor out of service and the spent demetallization catalyst can be loaded to more than 30%
vanadium, which makes it a valuable source of vanadium.
21.3 COMMERCIAL PROCESSES
Hydrotreating technology is one of the most commonly used refinery processes, designed to remove
contaminants such as sulfur, nitrogen, condensed ring aromatics, or metals. The feedstocks used in
the process range from naphtha to vacuum resid, and the products in most applications are used as
environmentally acceptable clean fuels. Hydrotreating technology has a long history of commercial application since the 1950s, with more than 500 licensed units placed in operation worldwide.
Furthermore, recent regulatory requirements to produce ultra-low-sulfur diesel (ULSD) and gasoline have created a very dynamic market as refiners must build new or revamp their existing assets
to produce the low-sulfur, even no-sulfur fuels.
The petroleum industry often employs two-stage processes in which the feedstock undergoes
both hydrotreating and hydrocracking. In the first, or pretreating, stage the main purpose is conversion of nitrogen compounds in the feed to hydrocarbons and to ammonia by hydrogenation and mild
hydrocracking. Typical conditions are 340°C–390°C (650°F–740°F), 150–2500 psi (1–17 MPa), and
a catalyst contact time of 0.5–1.5 h; up to 1.5% w/w hydrogen is absorbed, partly by conversion of
the nitrogen compounds but chiefly by aromatic compounds that are hydrogenated.
It is most important to reduce the nitrogen content of the product oil to <0.001% w/w (10 ppm).
This stage is usually carried out with a bifunctional catalyst containing hydrogenation promoters, for example, nickel and tungsten or molybdenum sulfides, on an acid support, such as
silica- alumina. The metal sulfides hydrogenate aromatics and nitrogen compounds and prevent
deposition of carbonaceous deposits; the acid support accelerates nitrogen removal as ammonia
by breaking carbon-nitrogen bonds. The catalyst is generally used as 1/8 × 1/8 in. (0.32 × 0.32 cm)
or 1/16 × 1/8 in. (0.16 × 0.32 cm) pellets, formed by extrusion.
Most of the hydrotreating cracking is accomplished in the first stage. Ammonia and some gasoline are usually removed from the first-stage product, and then the remaining first-stage product,
which is low in nitrogen compounds, is passed over the second-stage catalyst. Again, typical conditions are 300°C–370°C (600°F–700°F), 1500–2500 psi (10–17 MPa) hydrogen pressure, and
0.5–1.5 h contact time; 1%–1.5% w/w hydrogen may be absorbed. Conversion to gasoline or jet
fuel is seldom complete in one contact with the catalyst, so the lighter oils are removed by distillation of the products and the heavier, higher-boiling product combined with fresh feed and recycled
over the catalyst until it is completely converted.