Hydrocarbon Processing - June 2022 - 36

Catalysts
Despite its popularity, the authors do not fully agree with using
this parameter to simulate the commercial-scale reactor for
multiple reasons, especially for scale-down applications (e.g.,
refinery catalyst benchmarking).
Two primary techniques are available to pack the catalyst
inside a commercial-scale reactor: sock loading and dense loading.
The catalyst amount for a fixed volume can differ by up to
20% by employing a different loading technique. In other words,
the difference in overall activity could be as high as 20%. This
discrepancy is particularly crucial for catalysts with extrudate
shapes, while the same effect is less pronounced for spherical
ones. It is not uncommon to see different catalyst vendors propose
a different catalyst loading technique for the same reactor.
Additionally, different catalysts have a unique loading density
from different designs and materials.
For these reasons, the authors recommend that every scientist/engineer
adhere to weight hourly space velocity [(WHSV),
m3
of feed/hr/kg of catalyst] to improve the similarity between
two different scales. Using a specific WHSV for each catalyst
vendor is the best option.
Care must be taken which catalyst weight basis is referred to
when specifying WHSV (e.g., wet or dry). Modern hydrotreating
catalysts usually contain the organic additive (typically
organic acid) to promote Type II active sites. Although this
organic additive decomposes during the catalyst activation, it
contributes 16 wt%-30 wt% of the fresh catalyst weight, depending
on the level of metal contents.
H2 partial pressure and H2
-to-oil ratio. In the authors'
experience, typical maximum pressures for laboratory-scale
units vary between 160 barg and 175 barg. Despite the use
of pure H2
[which also diminishes hydrogen sulfide (H2
being prevalent in laboratory-scale experiments
S) inhibition effects],
this pressure limitation still impacts the hydrogenation
level, N slip control and the deactivation rate in high-pressure
hydrocrackers and residue hydrotreaters (see TABLE 3 for typical
pressure ranges).
Additionally, this limit also affects some product properties
from poorer hydrogenation (e.g., cetane number or smoke
point). Theoretically, this constraint also impacts the cracking
activity, but the effect is only marginal. It is uncommon to see
poorer product qualities from a laboratory-scale experiment
compared with a commercial unit.
To compensate for lower H2
partial pressure, the H2
-to-oil
ratio can be proportionally increased during the test campaign.
Catalyst loading scheme. Various assumptions have been
used for the catalyst loading scheme, such as:
* Replacing the demetallization catalysts with the main
hydrotreating catalysts
* Excluding the demetallization catalysts.
The main argument to support these assumptions is that
the test campaign is relatively short, therefore demetallization
catalysts are not needed (e.g., negligible metal deactivation).
This reasoning might be valid if different main hydrotreating
catalysts are benchmarked for an R&D program. However, this
is not the case for the refinery catalyst benchmarking program,
where the ratio between the demetallization catalysts and the
main hydrotreating catalysts varies with catalyst vendors.
The catalyst vendor that proposes more demetallization
fraction will be given extra activity advantages during the test
campaign if the refiner adopts the first assumption. On the contrary,
the catalyst vendor with less demetallization fraction will
be less affected by excluding the demetallization catalysts if the
refiner goes with the second assumption. Some demetallization
catalysts have fairly high activity. Excluding them from the test
campaign can distort the results.
For example, the catalyst loading scheme with more demetallization
fraction tends to require a higher degree of reaction
temperature increment than the one with less demetallization
fraction, therefore a higher tendency of thermal cracking and
crossing aromatics saturation equilibrium.
For these reasons, it is recommended to include both the
TABLE 3. Typical process conditions of various hydrotreating and hydrocracking processes5
Application
H2
Hydrotreating
Petroleum fraction Reaction phase LHSV (h-1
Naphtha
Kerosene
Gasoil
VGO
Vapor
Residue
VGO
Hydrocracking
Residue
Vapor/Liquid
Vapor/Liquid
Vapor/Liquid
Vapor/Liquid
Vapor/Liquid
Vapor/Liquid
36 JUNE 2022 | HydrocarbonProcessing.com
3-8
2-5
1.5-4
1-2
0.2-0.5
0.5-1.5
0.1-0.5
)
partial
pressure, bara Temperature, °C H2/oil (Nm3
10-20
20-30
25-40
50-90
80-130
90-200
120-210
320
330
340
360
370-410
380-430
400-440
60
80
140
210
> 525
1,000-2,000
1,000-2,000
/m3
)
H2
consumption
(Nm3
/m3
2-10
5-15
20-40
50-80
100-175
150-300
150-300
)
For example, if the H2 partial pressure is off by 10%, the H2
-to-oil ratio cannot fully compensate for lower H2
-to-oil ratio as
-
to-oil ratio should be increased by the same proportion. Note:
A higher H2
partial pressure, but it will surely help.
For most cases, refiners use their actual H2
a target for their pilot plant testing campaign. In the authors'
experience, recycle gas flows are notoriously incorrect. The actual
gas molecular weight can significantly differ from the one
used in the distributed control system (DCS) calculation. This
flowmeter does not impact the material balance across the unit;
therefore, it is rarely corrected by the refinery. Moreover, the
recycle gas sample is seldom taken for units without an amine
scrubber due to a high H2
required when taking the sample to lower H2
an acceptable level. To calculate a realistic H2
S level; a cartridge of lead acetate is
S concentration to
-to-oil ratio, the
molecular weight difference must be considered (the uncorrected
recycle gas flow reading can be off by up to 20%).
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