Note: Descriptions are shown in the official language in which they were submitted.
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COMBINED HYDROTREATING PROCESS AND CONFIGURATIONS FOR SAME
Field of The Invention
The field of the invention is petrochemistry, and particularly hydrotreating
of various
hydrocarbonaceous feedstocks.
Background of The Invention
Hydrotreating is a type of hydroprocessing commonly used in many modern
refineries,
in which hydrogen is contacted in the presence of a catalyst with a
hydrocarbonaceous
feedstock to remove impurities, including oxygen, nitrogen, sulfur, and to
saturate
hydrocarbons. A frequently employed form of hydrotreating is
hydrodesulfurization, which is
used primarily to reduce the sulfur content from refinery intermediate
streams.
Hydrodesulfurization is typically used in combination with processes including
feed
pretreatment of catalytic reformers, fluidized-bed catalytic crackers, and
hydrocrackers, and
may also be used independently as a product quality improvement step for
naphtha, diesel, jet,
heating oil and residues, saturation of olefins, and polycyclic aromatics.
Hydrocracking is
another type of hydroprocessing commonly used in many modern refineries, in
which
hydrogen is contacted in the presence of a catalyst with a hydrocarbonaceous
feedstock to
produce lighter products (i. e., the average molecular weight decreases).
There are numerous
hydroprocessing configurations and processes known in the art, and continuous
efforts to
reduce energy consumption and capital cost, while improving product quality,
has led to
integration of hydrotreating and hydrocracking reactors in various processes.
For example, in one integration concept, a hydrotreater is combined with a
hydrocracker as disclosed in U.S. Pat. No. 3,328,290 to Hengstebeck that
describes a two-
stage hydrocracking process wherein fresh feedstock is combined with effluent
from the
hydrocracking stage and the combined streams are then introduced into a
hydrotreating stage.
A higher-boiling fraction is then separated from the hydrotreater effluent and
fractionated to
produce a light product and a heavier bottoms stream, which is then recycled
with hydrogen-
containing gas back to the hydrocracking stage.
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2
Another example U.S. Pat. No. 6,235,190 to Bertram describes an integrated
hydrotreating and hydrocracking process in which two hydrotreating catalysts
of different
activities are operated in series to provide improved product quality, wherein
the effluent
from a hydrotreating reactor is subjected to a hydrocracking process to
convert the
hydrotreated effluent to lighter products with a reduced aromatic hydrocarbon
content. In a
further example, U.S. Pat. No. 6,261,441 to Gentry et al., a combined
hydrotreating/hydrocracking process is described in which a hydrocracking
stage is followed
by a hydrodewaxing stage with a single feedstock and a bottoms fraction
recycle to produce a
naphtha product, a distillate boiling above the naphtha range, and a lubricant
product.
In yet another system, as described in U.S. Pat. No. 6,328,879 to Kalnes, two
independent feedstocks are hydrocracked in a catalytic hydrocracking process
that employs a
hydrocracking zone, a hydrotreating zone, and a high pressure product stripper
to produce
various products, wherein the products have a lower boiling point range than
the feedstocks.
Alternatively, more than one hydrotreater reactor, and or catalyst beds may be
employed for catalytic hydrogenation as described in U.S. Pat. No. 3,537,981
to Parker, or
U.S. Pat. No. 6,103,105 to Cooper. While Parker's process employs a first
hydrotreating
reactor coupled to a separator that is in series with a second hydrotreating
reactor, Cooper et
al. employ two serially connected hydrotreating catalyst beds without the use
of a separator.
However, both Coopers and Parkers hydrotreating configurations are typically
limited to only
a single feedstock.
Thus, although many integrated processes have provided at least some advantage
over
other known configurations and methods, all or almost all of the known
configurations and
methods are limited to processes in which hydrocracking is the objective, or
in which
hydrotreating of a single boiling range (e.g., naphtha, diesel, gasoil, resid)
feedstock is
considered. Consequently, all or almost all of the known hydrotreating
processes require
separate plants where more than one feedstock is employed. Therefore, there is
still a need to
provide improved configurations and methods for hydrotreating of petroleum
products.
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Summary of The Invention
The present invention is directed to configurations and methods for
hydroprocessing
plants, and especially for integrated hydrotreating plants in which at least
two feedstocks with
different boiling point ranges (e.g., gas oil and diesel oil) are
hydrotreated. Further especially
contemplated aspects include methods for controlling contemplated
configurations.
In one aspect of the inventive subject matter, contemplated plants include an
interbed
separator that receives a first feed (e.g., hydrotreated gas oil) and a second
feed (e.g., diesel
oil), wherein the first feed preheats and vaporizes at least part of the
second feed, thereby
producing a preheated and at least partially vaporized second feed, and
wherein at least a
portion of the first feed is provided by a first hydrotreating reactor, and
wherein at least a
portion of the preheated and at least partially vaporized second feed is fed
into a second
hydrotreating reactor that produces a product.
Especially contemplated interbed separators include at least a partial vapor
liquid
equilibrium stage, preferably at least two vapor liquid equilibrium stages,
and may have a
configuration of a trayed column or a packed column. It is further preferred
that contemplated
interbed separators may receive a hydrogen rich stream, which may be recycled
in the plant,
and/or which may be a makeup hydrogen stream. Contemplated interbed separators
are
typically operated at a pressure similar to the operating reactor pressure of
about 500 psi to
about 2400 psi.
In particularly preferred aspects of the inventive subject matter, at least a
portion of
the second feed is fed into the second hydrotreating reactor, at a rate
effective to control light-
end recovery of the hydrotreated first feed in the interbed separator. The
remaining portion of
the second feed may then be employed to regulate a temperature in the second
hydrotreating
reactor.
In another aspect of the inventive subject matter, first and second
hydrotreating
reactors are operated at conditions under which the hydrotreating reactor feed
will exhibit less
than 10% conversion, and more preferably less than 8% conversion. Thus,
contemplated
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second hydrotreating reactors are preferably operated at a pressure of between
about 700 psi
and about 2400 psi.
Furthermore, it is contemplated that configurations according to the inventive
subject
matter may be realized in a new plant. However, the interbed separator and the
second
hydrotreating reactor may -also be integrated as an upgrade into an existing
hydroprocessing
plant.
In a further aspect of the inventive subject matter, a method of hydrotreating
includes
one step in which a first hydrotreating reactor, a second hydrotreating
reactor, and an interbed
separator that receives a first feed and a second feed are provided. In
another step, the
interbed separator is fluidly coupled to the first and second hydrotreating
reactors. In a still
further step, the hydrotreated first feed is used to preheat and vaporize at
least part of the
second feed, thereby producing a preheated and at least partially vaporized
second feed, and
in another step, at least a portion of the preheated and at least partially
vaporized second feed
is mixed with another part of the second feed and fed into the second
hydrotreating reactor.
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4a
According to still another aspect of the present invention, there is
provided a system for integrated hydrotreating of a first and a second
feedstock
with different boiling point ranges comprising: an interbed separator that is
configured to produce a separator liquid and to receive a first
hydrocarbonaceous
feed and a second hydrocarbonaceous feed, wherein the first feed has a higher
boiling point range than the second feed, and wherein the first feed has a
temperature that is effective to preheat and vaporize at least part of the
second
feed, thereby producing a preheated and at least partially vaporized second
feed;
a first hydrotreating reactor configured to provide at least a portion of the
first feed;
and a second hydrotreating reactor configured to accept at least a portion of
the
preheated and at least partially vaporized second feed to produce a liquid
product, wherein the system is further configured such that the liquid product
and
the separator liquid are separately withdrawn from the system.
According to yet another aspect of the present invention, there is
provided a method of hydrotreating at least two distinct hydrocarbonaceous
feeds
to form at least two distinct hydrotreated products, comprising: providing a
first
hydrotreating reactor, a second hydrotreating reactor, and an interbed
separator
that receives a first hydrocarbonaceous feed and a second hydrocarbonaceous
feed, wherein the first hydrocarbonaceous feed has a higher boiling point
range
than the second hydrocarbonaceous feed; fluidly coupling the interbed
separator
to the first and second hydrotreating reactors; using the first feed to
preheat and
vaporize at least part of the second feed, thereby producing a preheated and
at
least partially vaporized second feed; and feeding at least a portion of the
preheated and at least partially vaporized second feed into the second
hydrotreating reactor; and separately withdrawing a hydrotreated first
hydrocarbonaceous fluid from the interbed separator and a hydrotreated second
hydrocarbonaceous fluid from the second hydrotreating reactor.
According to a further aspect of the present invention, there is
provided a system for integrated hydrotreating of a first and a second
feedstock
with different boiling point ranges, comprising: an interbed separator that
receives
a first hydrocarbonaceous feed and a second hydrocarbonaceous feed, and that
forms a first hydrotreated liquid, wherein the first feed preheats and
vaporizes at
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4b
least part of the second feed, thereby producing a preheated and at least
partially
vaporized second feed; wherein the at least a portion of the first feed is
provided
by a first hydroprocessing reactor, and wherein at least a portion of the
preheated
and at least partially vaporized second feed is fed into a second
hydroprocessing
reactor that produces a hydrotreated product; wherein the first
hydrocarbonaceous
feed has a higher boiling point range than the second hydrocarbonaceous feed;
and wherein the interbed separator is further configured to allow withdrawal
of the
first hydrotreated liquid and wherein the second hydroprocessing reactor is
configured to allow withdrawal of the hydrotreated product.
According to yet a further aspect of the present invention, there is
provided a system for integrated hydrotreating of a first and a second
feedstock
with different boiling point ranges comprising: an interbed separator that
receives
a first hydrocarbonaceous feed and a second hydrocarbonaceous feed, wherein
the first feed preheats and vaporizes at least part of the second feed,
thereby
producing a preheated and at least partially vaporized second feed; wherein at
least a portion of the first feed is provided by a first hydroprocessing
reactor, and
wherein at least a portion of the preheated and at least partially vaporized
second
feed is fed into a second hydroprocessing reactor that produces a product;
wherein the first hydrocarbonaceous feed has a higher boiling point range than
the
second hydrocarbonaceous feed; and wherein a third hydrocarbonaceous feed is
fed into the second hydroprocessing reactor, and wherein the second
hydrocarbonaceous feed has a higher boiling point range than the third
hydrocarbonaceous feed.
Brief Description of The Drawing
Figure 1 is a schematic view of an exemplary configuration of a prior
art hydrotreating plant.
Figure 2 is a schematic view of an exemplary configuration of a
hydrotreating plant according to the inventive subject matter.
Figure 3 is a schematic detail view of streams relating to the interbed
separator according to the inventive subject matter.
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4c
Detailed Description
Various known configurations and processes for desulfuration and/or
denitrification utilize a process that employs a hydrotreating reactor in
which a
hydrocarbonaceous feed is reacted with hydrogen in the presence of a catalyst
to
form H2S and/or NH3 from sulphur-
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and/or nitrogen-containing compounds in the feedstock. Prior Art Figure 1
depicts a typical
configuration 100 for such plants. Here, a single feedstock (e.g., diesel) 110
is passed through
a heater 120 and subsequently fed into a hydrotreating reactor 130. Hydrogen
(separately [via
line 141], or in combination [via line 142] with the feedstock) is added to
the catalyst in the
5 hydrotreating reactor and the hydrotreated product 112 is (after a cooling
step in cooler 180)
separated in separator 150 into a gaseous portion 112A, which predominantly
comprises
hydrogen, hydrogen sulfide, and light non-condensable hydrocarbons and a
liquid portion
112B, which comprises hydrotreated diesel, some wild naphtha, and remaining
sour gas. The
hydrogen from the gaseous portion is typically purified in an absorber 152
with an amine-
containing solvent, and recycled (supra) into the hydrogen reactor via
compressor 160. The
hydrotreated product 112C can then be retrieved from column 170 along with
typical products
such as wild naphtha 112D and sour gas 112E. While such configurations work
relatively
well for a single type of feedstock (e.g., vacuum gas oil, gas oil, diesel,
naphtha, etc.), known
plants with multiple feedstocks (e.g., gas oil and diesel) generally require
multiple and
separate hydrotreating configurations, which add significant cost to
construction and
operation of such plants.
In their efforts to improve configurations and methods for hydrotreating
hydrocarbonaceous feeds, the inventors have discovered that multiple
feedstocks (i.e.,
feedstocks with different boiling point ranges - e.g., gas oil and diesel) can
be hydrotreated in
an integrated configuration, in which an interbed separator is fluidly coupled
to a first and a
second hydrotreating reactor, and in which a single hydrogen recycling loop
(e.g., comprising
a cooler or heat exchanger, a liquid/gas separator, an amine stripper, and a
compressor) can be
employed for two (or more) hydrotreating reactors each treating different
feeds.
Consequently, in a particularly preferred aspect of the inventive subject
matter, a plant
may comprise an interbed separator that. receives a first feed and a second
feed, wherein the
first feed preheats and vaporizes at least part of the second feed, thereby
producing a
preheated and at least partially vaporized second feed, wherein at least a
portion of the first
feed is provided by a first hydrotreating reactor, and wherein at least a
portion of the
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preheated and at least partially vaporized second feed is fed into a second
hydrotreating
reactor that produces a product.
Figure 2 depicts an exemplary configuration of a hydroprocessing plant 200, in
which
two different hydrocarbonaceous feedstocks are hydrotreated using an
integrated
configuration with a single hydrogen recycle loop. Here, gas oil 210A (first
hydrocarbonaceous feedstock) is heated in heater 220 and then introduced into
the
hydrotreating reactor 230A to produce a hydrotreated product 212 (which is the
first feed for
the interbed separator). The hydrotreated product 212 is then fed into the
interbed separator
(hot separator) 240. It should be recognized that the hydrotreated product 212
may pass
through equipment (e.g., heat exchangers, etc.) prior to entering the interbed
separator 240.
The interbed separator 240 also receives diesel feed 21 OB (the second feed
for the interbed
separator, which may be preheated) and which is preferably at least partially
(i.e., at least 10-
50%, more typically 50 to 80%, most typically, 80 to 100%) in the liquid
phase. A vapor
feed 290, typically hydrogen (or hydrogen-containing) may further be fed into
the interbed
separator, wherein the vapor feed may be partially recycled within the plant.
Alternately, the
vapor feed (or hydrogen containing feed) may be at least in part make-up
hydrogen.
Within the separator the second feed is at least partially vaporized (or
further
vaporized) and heated by direct contact with the hydrotreated product 212.
Additionally, the
interbed separator 240 separates the feeds into products in which the more
volatile
components will exit the separator with the vaporized second feed 210', and
the less volatile
components will exit with the somewhat cooled hydrotreated separator product
212'. The
interbed separator will include at least a partial vapor liquid equilibrium
stage, or more
preferably two or more vapor liquid equilibrium stages, and may have a
configuration of a
frayed column or a packed column. The liquid hydrotreated product 212' is then
fed into
column 270A that separates the liquid hydrotreated product 212' into treated
products
including but not limited to gas oil, wild naphtha, and sour gas. The
vaporized second feed
210' is then mixed with additional diesel feed via line 2108' and introduced
(as combined
second feed) into the second hydrotreating reactor 230B, which may or may not
receive
additional feed streams. It should be appreciated that a portion of the
lighter boiling range
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components will be recovered from the first product 212' and further
hydrotreated in the
second reactor.
The so hydrotreated second feed 210" (here: mostly hydrotreated diesel) is
then cooled
in cooler 280 and separated in separator 250 into a liquid portion and a
gaseous portion
(predominantly comprising HZS,= hydrogen, and light non-condensable
hydrocarbons). The
hydrogen in.the gaseous portion can be purified via absorber 252, which may
use
conventional solvents. The compressor 260 compresses this hydrogen-containing
recycle gas
stream to a suitable pressure for re-introduction into the system (e.g., at
first reactor and/or
into first feed or feedstock). The liquid portion of the second hydrotreated
feed 210" is then
fed into column 270B that separates the hydrotreated products into treated
products which can
include, but are not limited to, low sulfur diesel, wild naphtha, and sour
gas.
As also used herein, the term "interbed separator" refers to a separator that
is fluidly
coupled to at least two hydroprocessing reactors such that the interbed
separator receives an at
least partially hydrotreated first feed and a second feed (which may or may
not have been
previously hydrotreated),.wherein first and second feeds have different
boiling point ranges
(e.g., gas oil and diesel oil). Typically, contemplated interbed separators
are operated hot (i.e.,
300 to 750 F), and it is especially contemplated that the interbed separator
further may
receive a vapor or a hydrogen-containing feed.
Figure.3 depicts an especially preferred configuration of the streams around
the
interbed separator 340 and the second reactor in which a portion 31 OB' of the
second feed
31OB, and an additional third feed. 395C is fed to the second reactor (via
combined stream
310'), bypassing the interbed separator, to produce a hydrotreated product
310". The rate of
the substantially liquid phase stream 31 OB" (of the second feed) is
determined to allow for the
desired light end recovery 312' from the first hydrotreated feed stock 312.
The term "light-end
recovery " as used herein refers to the recovery of components in a component
mixture,
wherein the boiling point of the components is in the upper third, and more
typically upper
fourth (or even higher) of the boiling point range of the mixture. The
remaining portion of the
second feed stock 31OB' may be additionally preheated in a heat exchanger or
heater 3 10C,
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before being directed to the second reactor. It should be recognized that the
third feed may be
any hydrocarbonaceous feedstock, and may include naphtha, jet, diesel, or gas
oil boiling
range material. It should also be recognized that additional (forth, fifth,
etc.) feed streams can
be fed to the second reactor, bypassing the interbed separator. In this
exemplary configuration
the third feed stock 395C is Cycle Oil from an FCC unit. In this preferred
configuration the
second reactor operates at a steady feed rate while allowing for good
operating flexibility in
the operation of the interbed separator, and good light end recovery control.
It should also be
recognized that the reactor 330B may operate in a two-phase (vapor/liquid) or
preferably
trickle flow regime. Interbed separator 340 produces treated gas reactor
product 212'.
To maintain a particular inlet temperature to the second reactor 330B, the
feed
temperatures of heated streams 310B' and/or 395C' can be adjusted via
integrated (using
internal streams within the plant or stripping or fractionation sections) or
external heat
sources. This ability to adjust the feed temperature of the portion of the
feed that bypasses the
interbed separator is especially advantageous, since directing a portion of
the feed to the
second hydrotreating reactor will resolve difficulties associated with the
heat balance (e.g.,
the hydrogen stream 390 would have to be temperature controlled (e.g., as hot
hydrogen
stripping gas) to circumvent heat imbalance). The amount of the second feed
that bypasses
the interbed separator (e.g., by direct feeding into the hydrotreater
downstream of the interbed
separator) will also depend on the relative volumetric rates of the first and
second reactor feed
stocks. As the volumetric rate of the second reactor feed increases, relative
to the first reactor
feed, the percentage of the second reactor feed bypassing the interbed
separator will typically
increase.
Still further, it should be recognized that the portion of the second feed (or
an alternate
third feed) that bypasses the interbed separator (e.g., via direct feed into
the second
=hydrotreater) may be preheated or temperature controlled. Consequently, it
should be
recognized that temperature control of the portion of the second feed may be
employed to
control the inlet temperature of the second hydrotreating reactor over a
relatively wide range
(e.g., +/- 75 degrees F). Therefore, the portion of the second feed that
bypasses the interbed
separator may typically be in a range of between about 20 vol% (or less) to
about 80 vol% (or
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more) of the entire volumetric rate of the second feed. Most typically,
however, the amount of
the portion of the second feed that bypasses the interbed separator will be
about 35-65 vol%.
Preferably, the additional feeds (third, forth, etc.) will be at least
partially liquid phase (below
its dew point, prior to the addition of makeup or recycle gas, if any, at the
conditions
(temperature and pressure) when first fed into the recycle loop, or when
measured at the
reactor inlet temperature, and pressure). Thus, it should be recognized that
in some of the
contemplated configurations, and especially in those in which a portion of the
second or third
feed are in liquid phase and fed into the second hydrotreating reactor, the
second
hydrotreating reactor is operated in a two-phase, or preferably trickle flow
regime.
It should further be especially recognized that in preferred aspects of the
inventive
subject matter both hydrotreating reactors are operated under conditions
effective to reduce
the concentration of sulfur- and/or nitrogen-containing compounds in the
feeds.
Consequently, it should be recognized that in preferred configurations both
feedstocks are
substantially not (i.e., less than 10%, more typically less than 8%) converted
to lower boiling
point products. In particularly preferred aspects, the second feedstock
comprises diesel, and
the diesel contains after hydrotreating and column separation less than 50
ppm, more
preferably less than 25 ppm, and most preferably less than 10 ppm sulfur-
containing products.
Thus, contemplated configurations may be employed for production of two
products
having different boiling ranges and different product specifications. For
example, an existing
gas oil hydrotreating plant upstream of a FCC unit may be upgraded, with
relatively low
capital investment, to include a second reactor (or reactor section) for
producing high quality
low sulfur diesel fuel. It should be especially recognized that in such
configurations the
required capacity increase for the existing heater, heat exchanger train and
coolers will be
moderate to insignificant since additional heat can leave the system via the
product from the
interbed separator to be used as stripper preheat.
Still further, it should be recognized that the concept of bypassing a portion
of the
second feedstock around the interbed separator (e.g., by feeding into the
hydrotreater
downstream of the interbed separator) may also be employed in alternative
integrated
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configurations and methods, and especially contemplated alternative
configurations include
those in which a first hydrocracking reactor is serially coupled to a second
hydrotreating
reactor (see e.g., U.S. Pat. No. 6,328,879 to Kalnes.
Still further, it should be recognized that the concept of bypassing a portion
of the
5 second feedstock around the interbed separator may also be extended to
alternative integrated
configurations and methods, and especially contemplated alternative
configurations include
those in which a first hydrotreating reactor is serially coupled to a second
hydrocracking
reactor.
Among other advantages, adding a fluid portion of the third feed to the second
reactor,
10 without passing through an interbed separator, will allow processing of a
higher boiling point
range material (i.e. similar to the first feedstock) without loss of the
higher boiling range
fraction of the third feedstock in a separator. Moreover, potential
difficulties associated with
the heat balance may be reduced, if not entirely avoided.
It should be especially appreciated that the terms "hydrocracking" and
"hydrotreating"
are not referring to the same type of hydroprocess occurring in the reactor.
As used herein, the
term "hydrocracking reactor" as used herein refers to a reactor in which a
hydrocarbon-
containing feed is converted to lighter products (i.e., the average molecular
weight decreases),
wherein the term "conversion" or "converted" means that a particular
percentage of fresh feed
changes to middle distillate, gasoline and lighter products (see e.g.,
"Hydrocracking Science
And Technology." by J. Schemer and A. J. Gruia; Marcel Decker, Inc.). Thus,
contemplated
hydrocracking reactors will have a conversion of at least 15%, more typically
at least 30%,
and most typically at least 50%. In contrast, the term "hydrotreating reactor"
refers to a
reactor in which a hydrocarbon-containing feed is reacted with hydrogen in the
presence of a
catalyst under conditions that (a) result in less than 15% conversion, and
more typically less
than 10% conversion, and (b) result in the formation of H2S and/or NH3 from
sulfur- and
nitrogen-containing compounds in the hydrocarbon-containing feed.
With respect to the first, second, and third hydrocarbonaceous feedstocks (21
OA,
21 OB, and 395 C) it should be appreciated that various hydrocarbonaceous
feedstocks are
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considered suitable for use herein, and in especially contemplated aspects the
first
hydrocarbonaceous feedstock comprises gas oil or any petroleum fraction with a
boiling point
range higher than diesel and the second hydrocarbonaceous feedstock comprises
diesel, or
any fraction with a boiling point range lower than the first feedstock. In a
still further
especially contemplated aspect, the third hydrocarbonaceous feedstock may
comprise any
feedstock regardless of boiling range. Suitable hydrocarbonaceous feedstocks
include crude
or partially purified petroleum fractions, including light gas oil, heavy gas
oil, straight run gas
oil, deasphalted oil, kerosene, jet fuel, cycle oil from an upstream FCC
(fluid catalytic
cracking) reactor etc. While not limiting to the inventive subject matter, it
is generally
preferred that suitable first and second hydrocarbonaceous feedstocks have
different boiling
point ranges, wherein the first hydrocarbonaceous feedstock typically has a
boiling point
range that is higher (at least 5 degrees centigrade, more typically at least
10 degrees
centigrade, and most typically at least 25 degrees centigrade as measured from
the mid
volume boiling point in the boiling point range) than the second boiling point
range. Suitable
first and second feed will typically have at least one different
physicochemical parameter
(e.g., molecular composition, boiling point range, etc.). The design rates of
the sum of the
first feedstock to that of the second plus third (plus, fourth, fifth, etc)
will typically be such
that the sum of the feeds to the first reactor is greater than the sum of
feeds the second reactor.
The sum of the feeds rates to the second reactor may typically be in a range
of between about
25 liquid vol% (or less) when measured at standard conditions to about 90
liquid vol% (or
more) of the sum of the feed rates to the first reactor. In the most preferred
design the sum of
the rates to the second reactor will be between about 40 liquid vol% to about
80 liquid vol%.
Suitable interbed separators particularly include hot separators, wherein such
hot
separators are further configured to receive at least part of the second feed
and possibly a
vapor feed, typically hydrogen containing, which may or may not be optional.
In a particularly
preferred alternative aspect of the inventive subject matter, it is
contemplated that the
concentration of the hydrogen in the hydrogen-containing feed may vary
substantially, and
while the hydrogen concentration in some configurations may be between about
50vol% and
95vo1% (and even more), the concentration of hydrogen may also be lower (e.g.,
between
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1 vol% and 50vol%), or even be substantially zero. In such cases, where the
hydrogen
containing feed is substantially free from hydrogen (i.e., less than 1vol%),
it is preferred that
the stream may predominantly comprise light-end-materials (i.e., materials
that will leave the
separator as a gaseous component). It is also recognized that the vapor feed
may be fed from
its source without additional preheat. Typically the vapor source will be from
a make-up gas
compressor, or from a recycle gas compressor. As such the temperature of the
vapor to the
interbed separator can be from 80 F to 350 F, more typically be in the range
of 125 F to
300 F, and most typically in the range from 150 F=to 275 F. Addition vapor
preheat is
possible and advantageous only to the extent that it may improve the plant
thermal efficiency,
but may also add additional capital cost.
It should be especially recognized that suitable interbed separators are
preferably
operated at a pressure that is at or close to the pressure in the first
hydrotreating reactor and at
a pressure that is at or above the pressure of the second hydrotreating
reactor. Consequently,
suitable interbed separators will typically be operated at between about 500-
2400 psi.
However, where suitable it should be appreciated that the pressure may also be
less than 700
psi and especially contemplated lower pressures are generally between 700 to
400 psi, and
even less. Similarly, where hydrotreating conditions allow, interbed
separators may also be
operated at a pressure above 2400 psi, and suitable higher pressures include
pressures
between 2400 to 4000 psi, and even higher. Due to the relatively high partial
pressure of
hydrogen in the separator (the hydrogen may be hydrogen that is recycled
within the plant), it
is contemplated that the effective hydrocarbon vapor partial pressure is less
than 200 psi, and
more typically within a range of between about 80psi to 180psi, and most
typically within a
range of between about 30psi to 150psi.
In a particularly contemplated aspect of the inventive subject matter, it is
contemplated that the interbed separator is operated such that the temperature
of the
hydrogenated product from the first hydrotreating reactor will evaporate at
least part of the
second feed. Thus, in especially preferred configurations, the at least part
of the hydrogenated
product will be in a gaseous, or vapor phase, and at least part of the second
feed (e.g., at least
50%, more typically at least 75%, even more typically at least 85%, and most
typically at least
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13
80% or 100%) will be vaporized by the heat of the first feed. Consequently, it
should be
appreciated that the energy required to operate the second hydrotreating
reactor will
predominantly be provided by the heat and pressure of the first hydrotreating
reactor.
With respect to particular temperatures, it is contemplated that the first
reactor will
preferably operate at about 650 F, the interbed separator will preferably
operate at a
temperature of between about 650 F and about 600 F, and the second reactor
will preferably
operate at a temperature of about 600 F. However, it should be recognized that
depending on
the particular feed of the first and second reactors, the pressures and
temperatures may vary
accordingly. With respect to the temperature regulation in the second
hydrotreater, it should
be recognized that the temperature in the second hydrotreating reactor may be
regulated by
feeding at least a portion of the second feed, or an additional feed to the
second reactor.
Additionally, it should be appreciated that the products from the first
reactor (i.e., the
first feed) preheat and vaporize at least part of the second feed.
Consequently, it is
contemplated that the so produced vapor will comprise a portion of one or both
feeds
(typically in the same boiling range), and that the so produced vapor is fed
in contemplated
configurations to the second reactor (which may contain one or more catalyst
beds). It is also
contemplated that the liquid remnants from the interbed separator first feed,
somewhat cooled
from vaporizing the second feed, can be fed directly to the first feed product
stripper without
additional stripper preheat. It is also contemplated that an intermediate
pressure (a pressure
set between the operating pressure of the interbed separator, and the pressure
of the stripper)
flash drum in the feed stream to the stripper may be included to provide a
means for safely
letting down the pressure and to recover dissolved hydrogen from the stripper
feed. It is also
contemplated that the liquid remnants from the interbed separator first feed
stock may pass
through equipment other than an intermediate pressure flash drum (e.g., heat
exchangers,
pumps, etc.), en route to the first feed product stripper.
By integration of two hydrotreating reactors into contemplated configurations,
costs
for construction and operation of contemplated plants will be significantly
reduced. For
example, it is contemplated that the cost for a hydrogen recycle compressor in
contemplated
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configuration will be substantially lower than the cost for two independent
recycle
compressors. Additionally, it is contemplated that a common set of
fractionation columns
(herein referred to as a gas plant) designed to separate light hydrocarbon
fractions can be used
downstream of the product stripper columns can be installed for substantially
less cost than
for two independent gas plants. In yet another aspect of the inventive subject
matter, it should
be appreciated that the energy required to operate the second hydrotreating
reactor will
predominantly be provided by the heat and pressure of the first hydrotreating
reactor.
Consequently, it is contemplated that a second heater for the second reactor
may be omitted.
Furthermore, it should be recognized that the product of the second
hydrotreating
reactor (here: being lower boiling point material) is well suited to sponge
(i.e., at least
partially remove) light hydrocarbon components that are not condensable at
typical
hydrotreating operating conditions (temperatures and pressures). Removing
these non-
hydrogen components from the recycle gas purifies the hydrogen rich recycle
gas to the first
reactor section. Compounds that will be removed (sponged by the products from
the second
reactor) from the recycle gas include methane, ethane, propane, and butanes.
Purification of
the hydrogen rich recycle gas will advantageously remove essentially inert,
light end
components and increase the hydrogen partial pressure thereby reducing the
size of the
equipment(e.g., reactors), and the amount of hydrotreating catalyst required.
In a still further aspect, it should be recognized that by fluidly coupling
the first
reactor to the second reactor, the second reactor is operating at a
significantly higher pressure
than a typical standalone design designed only to treat the lighter second
feed, thereby
significantly reducing the amount of required catalyst for the second reactor.
This reduction in
catalyst amount in the second reactor greatly offsets the additional costs
associated for
designing the second reactor at the higher pressure.
Dimensions and capacities of contemplated hydrotreating reactors will
typically
depend at least in part on the particular feedstock, and the overall
throughput capacity of the
hydrogenation plant. Thus, it is contemplated that all known hydrotreating
reactors are
suitable for use herein. Consequently, the nature of the catalyst may vary
considerably.
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However, preferred hydrotreating catalysts may include those comprising
cobalt,
molybdenum and/or nickel distributed on a carrier (e.g., alumina extrudate).
It should also be appreciated that suitable configurations may include
additional
hydrotreating reactors (i.e., a third reactor, a fourth reactor, etc.) and
separators, wherein each
5 of the additional reactors are fluidly coupled to an existing or preceding
reactor via a
separator that receives the product of the existing or preceding reactor, and
that removes at
least one component of an additional feedstock for the additional reactor.
With respect to the
components (e.g., piping, hydrotreating reactor, compressor, heat exchanger,
etc.) in
contemplated configurations, it is contemplated that all known and
commercially available
10 components may be employed. Furthermore, contemplated configurations may be
realized in
a new plant, however, it is especially preferred that a separator and a second
hydrotreating
reactor are integrated as an upgrade into an existing hydrotreating plant.
Consequently, a method of operating a plant may comprise a step in which a
first
hydrotreating reactor, a second hydrotreating reactor, and an interbed
separator that receives a
15 first feed and a second feed are provided. In a further step, the interbed
separator is fluidly
coupled to the first and second hydrotreating reactors. In a still further
step, the first
hydrotreated feed is used to preheat and vaporize at least part of the second
feed, thereby
producing a preheated and at least partially vaporized second feed, and in yet
another step, at
least a portion of the preheated and at least partially vaporized second feed
is mixed with the
remaining second feed and is fed into the second hydrotreating reactor. With
respect to the
first and second hydrotreating reactors, the interbed separator, the feeds and
feedstocks, the
hydrotreated product, and the hydrotreated product, the same considerations as
described
above apply.
Thus, specific configurations and methods of improved hydrotreating have been
disclosed. It should be apparent, however, to those skilled in the art that
many more
modifications besides those already described are possible without departing
from the
inventive concepts herein. The inventive subject matter, therefore, is not to
be restricted
except in the spirit of the appended claims. Moreover, in interpreting both
the specification
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and the claims, all terms should be interpreted in the broadest possible
manner consistent with
the context. In particular, the terms "comprises" and "comprising" should be
interpreted as
referring to elements, components, or steps in a non-exclusive manner,
indicating that the
referenced elements, components, or steps may be present, or utilized, or
combined with other
elements, components, or steps that are not expressly referenced.
