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The Chemistry and Technology of Petroleum
Hydrocarbons, especially aromatic hydrocarbons, can react in the presence of strong acids to
form coke. This coke is a complex polynuclear aromatic material that is low in hydrogen. Coke can
deposit on the surface of a catalyst, blocking access to the active sites and reducing the activity of
the catalyst. Coke poisoning is a major problem in fluid catalytic cracking catalysts, where coked
catalysts are circulated to a fluidized bed combustor to be regenerated. In hydrocracking, coke
deposition is virtually eliminated by the catalyst’s hydrogenation function.
However, the product referred to as coke is not a single material. The first products deposited
are tarry deposits that can, with time and temperature, continue to polymerize. Acid catalyzes
these polymerizations. The stable product would be graphite, with very large aromatic sheets
and no hydrogen. This product forms only with very high-temperature aging, far more severe
than that found in a hydrocracker. The graphitic material is both more thermodynamically stable
and less kinetically reactive. This kinetic stability results from the lack of easily hydrogenated
functional groups.
In a well-designed hydrocracking system, the hydrogenation function adds hydrogen to the tarry
deposits. This reduces the concentration of coke precursors on the surface. There is, however, a slow
accumulation of coke that reduces activity over a 1–2 year period. Refiners respond to this slow
reduction in activity by raising the average temperature of the catalyst bed to maintain conversions.
Eventually, however, an upper limit to the allowable temperature is reached and the catalyst must
be removed and regenerated.
Catalysts carrying coke deposits can be regenerated by burning off the accumulated coke. This
is done by service in rotary or similar kilns rather than leaving catalysts in the hydrocracking reactor, where the reactions could damage the metals in the walls. Removing the catalysts also allows
inspection and repair of the complex and expensive reactor internals, discussed in the following.
Regeneration of a large catalyst charge can take weeks or months, so refiners may own two catalyst
loads, one in the reactor, one regenerated and ready for reload.
The thermal reactions also convert the metal sulfide hydrogenation functions to oxides and may
result in agglomeration. Excellent progress has been made since the 1970s in regenerating hydrocracking catalysts; similar regeneration of hydrotreating catalysts is widely practiced.
After combustion to remove the carbonaceous deposits, the catalysts are treated to disperse
active metals. Vendor documents claim more than 95% recovery of activity and selectivity in these
regenerations. Catalysts can undergo successive cycles of use and regeneration, providing long functional life with these expensive materials.
Hydrocracking allows refiners the potential to balance fuel oil supply and demand by adding
vacuum gas oil cracking capacity. Situations where this is the case include (1) refineries with no
existing vacuum gas oil cracking capacity, (2) refineries with more vacuum gas oil available than
vacuum gas oil conversion capacity, (3) refineries where addition of vacuum residuum conversion
capacity has resulted in production of additional feedstocks boiling in the vacuum gas oil range
(e.g., coker gas oil), and (4) refineries that have one of the two types of vacuum gas oil conversion
units but could benefit from adding the second type. In some cases, a refiner might add both gas oil
cracking and residuum conversion capacity simultaneously.
Those refiners who do choose gas oil cracking as part of their strategy for balancing residual
fuel oil supply and demand must decide whether to select a hydrocracker or a fluid catalytic
cracking unit. Although the two processes have been compared vigorously over the years, neither
process has evolved to be the universal choice for gas oil cracking. Both processes have their
advantages and disadvantages, and process selection can be properly made only after careful consideration of many case-specific factors. Among the most important factors are (1) product slate
required, (2) amount of flexibility required to vary the product slate, (3) product quality (specifications) required, and (4) the need to integrate the new facilities in a logical and cost-effective
way with any existing facilities.
As illustrated earlier, for various forms of more conventional hydrocracking, the type of catalyst
used can influence the product slate obtained. For example, for a mild hydrocracking operation at
The Chemistry and Technology of Petroleum
Hydrocarbons, especially aromatic hydrocarbons, can react in the presence of strong acids to
form coke. This coke is a complex polynuclear aromatic material that is low in hydrogen. Coke can
deposit on the surface of a catalyst, blocking access to the active sites and reducing the activity of
the catalyst. Coke poisoning is a major problem in fluid catalytic cracking catalysts, where coked
catalysts are circulated to a fluidized bed combustor to be regenerated. In hydrocracking, coke
deposition is virtually eliminated by the catalyst’s hydrogenation function.
However, the product referred to as coke is not a single material. The first products deposited
are tarry deposits that can, with time and temperature, continue to polymerize. Acid catalyzes
these polymerizations. The stable product would be graphite, with very large aromatic sheets
and no hydrogen. This product forms only with very high-temperature aging, far more severe
than that found in a hydrocracker. The graphitic material is both more thermodynamically stable
and less kinetically reactive. This kinetic stability results from the lack of easily hydrogenated
functional groups.
In a well-designed hydrocracking system, the hydrogenation function adds hydrogen to the tarry
deposits. This reduces the concentration of coke precursors on the surface. There is, however, a slow
accumulation of coke that reduces activity over a 1–2 year period. Refiners respond to this slow
reduction in activity by raising the average temperature of the catalyst bed to maintain conversions.
Eventually, however, an upper limit to the allowable temperature is reached and the catalyst must
be removed and regenerated.
Catalysts carrying coke deposits can be regenerated by burning off the accumulated coke. This
is done by service in rotary or similar kilns rather than leaving catalysts in the hydrocracking reactor, where the reactions could damage the metals in the walls. Removing the catalysts also allows
inspection and repair of the complex and expensive reactor internals, discussed in the following.
Regeneration of a large catalyst charge can take weeks or months, so refiners may own two catalyst
loads, one in the reactor, one regenerated and ready for reload.
The thermal reactions also convert the metal sulfide hydrogenation functions to oxides and may
result in agglomeration. Excellent progress has been made since the 1970s in regenerating hydrocracking catalysts; similar regeneration of hydrotreating catalysts is widely practiced.
After combustion to remove the carbonaceous deposits, the catalysts are treated to disperse
active metals. Vendor documents claim more than 95% recovery of activity and selectivity in these
regenerations. Catalysts can undergo successive cycles of use and regeneration, providing long functional life with these expensive materials.
Hydrocracking allows refiners the potential to balance fuel oil supply and demand by adding
vacuum gas oil cracking capacity. Situations where this is the case include (1) refineries with no
existing vacuum gas oil cracking capacity, (2) refineries with more vacuum gas oil available than
vacuum gas oil conversion capacity, (3) refineries where addition of vacuum residuum conversion
capacity has resulted in production of additional feedstocks boiling in the vacuum gas oil range
(e.g., coker gas oil), and (4) refineries that have one of the two types of vacuum gas oil conversion
units but could benefit from adding the second type. In some cases, a refiner might add both gas oil
cracking and residuum conversion capacity simultaneously.
Those refiners who do choose gas oil cracking as part of their strategy for balancing residual
fuel oil supply and demand must decide whether to select a hydrocracker or a fluid catalytic
cracking unit. Although the two processes have been compared vigorously over the years, neither
process has evolved to be the universal choice for gas oil cracking. Both processes have their
advantages and disadvantages, and process selection can be properly made only after careful consideration of many case-specific factors. Among the most important factors are (1) product slate
required, (2) amount of flexibility required to vary the product slate, (3) product quality (specifications) required, and (4) the need to integrate the new facilities in a logical and cost-effective
way with any existing facilities.
As illustrated earlier, for various forms of more conventional hydrocracking, the type of catalyst
used can influence the product slate obtained. For example, for a mild hydrocracking operation at