Note: Descriptions are shown in the official language in which they were submitted.
METHOD AND SYSTEM FOR REDUCING OLEFIN CONTENT
OF PARTIALLY UPGRADED BITUMEN
[0001] FIELD
[0002] Systems and methods are provided for reducing or minimizing the
olefin content of
partially upgraded crude oils.
BACKGROUND
[0003] Oil sands are a type of non-traditional petroleum source that
remains challenging to
fully exploit. Due to the nature of oil sands, substantial processing can be
required at or near the
extraction site just to create bitumen / crude oil fractions that are suitable
for transport. However,
oil sands extraction sites are also often in geographically remote locations,
which can substantially
increase the construction and maintenance costs for any processing equipment
that is used at the
oil sands site.
[0004] Some options for preparing bitumen for transport can involve thermal
and/or catalytic
upgrading of at least a portion of the feed. This can include processes such
as visbreaking, coking,
or various types of hydroprocessing. While such thermal and/or catalytic
upgrading of bitumen
can be effective for improving the properties of the at least partially
upgraded bitumen, the
upgrading can also produce additional olefins at levels that are problematic
for some types of
transport. As a result, thermal and/or catalytic upgrading of bitumen is often
conventionally paired
with a hydrotreatment stage, so that olefin content generated during upgrading
can be reduced to
a desirable level. However, such hydrotreating requires a source of hydrogen,
which can be
difficult and/or expensive to provide at a bitumen upgrading site.
[0005] What is needed are improved systems and methods for thermal and/or
catalytic
upgrading of bitumen that produce an at least partially upgraded bitumen with
a low olefin content
while reducing or minimizing the need to transport additional hydrogen to the
upgrading site.
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100061 U.S. Patents 5,011805 and 4,935,566 describe methods for performing
catalytic
reforming on naphtha boiling range feeds to produce higher octane gasoline
and/or increased
amounts of aromatics.
100071 U.S. Patent 6,602,404 describes an example of catalytic reforming. A
naphtha and
kerosene boiling range feed to separate out a heavy naphtha portion. The heavy
naphtha portion is
reformed to produce aromatics with increased selectivity for formation of
xylenes. Other examples
of catalytic reforming processes include U.S. Patents 5,011,805 and 4,935,566.
100081 U.S. Patent 8,845,884 describes reforming a naphtha feed by
splitting the naphtha into a
light portion and heavy portion. The light portion and heavy portion are
reformed under different
conditions to allow for improved formation of C6 ¨ C8 aromatics in each
portion.
100091 U.S. Patent 4,615,791 describes an example of visbreaking of a resid
feedstock in the
presence of a hydrogen donor solvent.
SUMMARY
100101 In an aspect, a method for upgrading a heavy hydrocarbon feed is
provided. The method
can include exposing a heavy hydrocarbon feedstock comprising an API gravity
of 16 or less and
kinematic viscosity at 7.5 C of 500 cSt or more to a partial upgrading process
to form a partially
processed effluent. The partially processed effluent can include 1.1 wt% or
more of olefins, or 2.0
wt% or more. The method can further include separating, from the partially
processed effluent, a
first fraction and a second fraction. The first fraction can have a T95
distillation point of 750 F
(400 C) or less, and the second fraction can have a higher T95 distillation
point than the first
fraction. The first fraction can further include a weight percentage of
olefins that is greater than the
weight percentage of olefins in the partially processed effluent. The method
further includes
exposing at least a portion of the first fraction to a reforming process to
form at least a reformed
fraction and a hydrogen-containing fraction. The reformed fraction can include
less than 1.0 wt%
olefins. Additionally, the method can include blending at least a portion of
the reformed fraction
with the second fraction to form a partially upgraded product. The partially
upgraded product can
include an API gravity of 14 or more and a kinematic viscosity at 7.5 cSt of
500 cSt or less.
Optionally, the heavy hydrocarbon feedstock can correspond to a bitumen.
100111 In another aspect, a method for upgrading a feedstock is provided.
The method includes
separating an initial feedstock comprising an API gravity of 16 or less and a
kinematic viscosity at
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7.5 C of 500 cSt or more to form at least a light feedstock fraction and a
heavy feedstock fraction.
The light feedstock fraction can have a T95 distillation point of 500 C or
less and/or the heavy
feedstock fraction can have a T50 distillation point greater than 500 C. The
method further includes
exposing at least a portion of the heavy feedstock fraction to a partial
upgrading process to form a
partially processed effluent. The partially processed effluent can include 1.1
wt% or more of olefins.
The method can further include separating, from the partially processed
effluent, a first fraction and
a second fraction. The first fraction can have a T95 distillation point of 750
F (-400 C) or less and
the second fraction can have a higher T95 distillation point than the first
fraction. The first fraction
can further include a weight percentage of olefins that is greater than the
weight percentage of olefins
in the partially processed effluent. The method can further include exposing
at least a portion of the
first fraction and at least a portion of the light feedstock fraction to a
reforming process to form at
least a reformed fraction and a hydrogen-containing fraction. The reformed
fraction can include less
than 1.0 wt% olefins. Additionally, the method can include blending at least a
portion of the
reformed fraction with the second fraction to form a partially upgraded
product. The partially
upgraded product can include an API gravity of 14 or more and a kinematic
viscosity at 7.5 cSt of
500 cSt or less. Optionally, the T95 distillation point of the light feedstock
fraction can be 400 C or
less. Optionally, the initial feedstock can correspond to a bitumen feedstock.
BRIEF DESCRIPTION OF THE DRAWING
100121 Figure 1 shows an example of a configuration for upgrading a heavy
hydrocarbon feed,
such as a bitumen feed.
DETAILED DESCRIPTION
100131 All numerical values within the detailed description and the claims
herein are modified
by "about" or "approximately" the indicated value, and take into account
experimental error and
variations that would be expected by a person having ordinary skill in the
art.
Overview
100141 In various aspects, systems and methods are provided for partial
upgrading of bitumen
(and/or other heavy hydrocarbon feeds) while reducing or minimizing the
hydrogen consumption
associated with the partial upgrading. The partial upgrading of the bitumen
can correspond to any
convenient type of catalytic and/or thermal upgrading. After the partial
upgrading, a naphtha and/or
distillate boiling range portion of the thermally upgraded effluent can be
passed into a catalytic
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Date Recue/Date Received 2020-09-03
reformer. The reformer can be operated under conditions that are suitable for
olefin saturation in
addition to some aromatic formation. The resulting naphtha and distillate
portions of the reformer
effluent, having a reduced or minimized content of olefins, can be combined
with one or more
additional portions of the partially upgraded effluent to form a partially
upgraded product.
100151 Thermal and/or catalytic methods of partial upgrading typically
result in formation of
olefins in the partially upgraded effluent, such as having an olefin content
of 1.1 wt% or more, or
2.0 wt% or more. The olefins generated during partial upgrading are typically
concentrated in the
naphtha and distillate boiling range portions of the partially upgraded
effluent. When visbreaking is
used for partial upgrading, the naphtha fraction of the partially upgraded
effluent can generally have
an olefin content of about 5.0 wt% to 15 wt%, while the distillate fraction
can have an olefin content
of about 1.0 wt% to 6.0 wt%. The vacuum gas oil and resid portions of the
partially upgraded
effluent can tend to have olefin contents that are low enough that separate
olefin saturation is not
necessary. For example, the olefins in the naphtha, distillate, and vacuum gas
oil fractions of
partially upgraded bitumens were characterized using hydrogen nuclear magnetic
resonance
spectroscopy (1-1-NMR). The partial upgrading was performed by visbreaking.
The naphtha
fractions included between 8.0 wt% to 10 wt% olefins. The distillate fractions
included up to 1.5
wt% olefins. The vacuum gas oil and fractions included up to 1.0 wt% olefins.
100161 Based on the above olefin contents, some type of treatment to reduce
olefin content is
necessary in order to achieve an olefin content of less than 1.0 wt% for the
overall partially upgraded
bitumen product composition in order to meet pipeline specifications. Because
the distillate fraction
can also include more than 1.0 wt% olefins, in some aspects it is desirable to
treat both the naphtha
and the distillate fractions. Optionally, a portion of the vacuum gas oil
fraction could also be treated.
While hydrotreatment (such as fixed bed or trickle bed hydrotreatment) can be
effective for
saturating such olefins, performing hydrotreatment requires a separate source
of hydrogen. At a
remote site, excess hydrogen is typically not readily available from other
processes.
100171 Instead of performing hydrotreatment, in various aspects of the
present disclosure, a
catalytic reforming stage can be used to saturate olefins within the naphtha
and/or distillate boiling
range portions of the partially upgraded bitumen. In addition to forming
aromatics, it has been
discovered that catalytic reforming can be used to saturate olefins within the
naphtha and distillate
fractions of a partially upgraded bitumen. Rather than requiring an external
source of hydrogen,
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Date Recue/Date Received 2020-09-03
catalytic reforming provides a method for saturating olefins and/or converting
within the naphtha
and/or distillate fractions while producing excess hydrogen. Without being
bound by any particular
theory, it is believed that olefins can be converted to aromatic ring
structures under the conditions
of a reforming process. Additionally, it is believed that the olefins can be
saturated "in-situ" by H2
generated in the reforming environment. This hydrogen is generated as
aromatics are formed from
naphthenes and/or as olefins are formed from paraffins within the catalytic
reforming process.
100181 Using a reforming stage instead of a hydrotreatment stage for olefin
reduction can allow
for other integration opportunities. For example, the hydrogen generated by
reforming can be used
to provide hydrogen to the partial upgrading process, when the partial
upgrading corresponds to
sodium desulfurization, visbreaking in the presence of hydrogen and/or a
hydrogen donor solvent,
or some type of hydroprocessing. As another example, any light ends (C4_)
compounds generated
during reforming can be used as fuel gas to provide heat for the partial
upgrading process.
100191 Still a further advantage of using reforming instead of
hydrotreatment for olefin
saturation is that the reformed naphtha and distillate fractions can have an
increased content of
aromatics. This can increase the solvency of the naphtha and distillate
fractions, thus potentially
reducing the amount of upgrading that is needed to achieve a desired set of
transport properties.
100201 Yet another potential advantage is that the reforming stage may
provide a further
viscosity reduction for the portions of the partially upgraded effluent that
are exposed to the
reforming conditions. In some aspects, the kinematic viscosity at 7.5 C for
the partially upgraded
product can be lower than the kinematic viscosity at 7.5 C for the partial
upgrading effluent by 10
cSt or more.
Definitions
100211 In this discussion, the relative severity of visbreaking processes
can be compared by
referring to a severity index. Severity (or severity index, SI) is a function
of reaction time and
temperature used during visbreaking. It provides an indication of the severity
of the reaction and
can be used to compare results of reactions carried out at different
conditions. The severity index is
defined as:
(1) S/ = t exp[¨ ¨RE (¨T1 ¨ ¨7010)1
100221 In Equation (1), t is the reaction time in seconds, E is the
activation energy associated
with bitumen thermal cracking, R is the universal gas constant and T is the
reaction temperature.
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Date Recue/Date Received 2020-09-03
The severity index equals the time required in seconds at 427 C (700 K) to
achieve the same degree
of reaction (e.g. pitch conversion). For conversion of bitumen, E can
generally be set to a value
between 50 kcal/mol to 55 kcal/mol.
100231 In this discussion, a hydrogen donor solvent refers to a solvent
that can be added to
bitumen during processing to allow for higher severity while reducing or
minimizing coking. The
hydrogen donor solvent can have a higher hydrogen to carbon ratio (i.e., a
higher hydrogen content)
than the bitumen. For bitumen processing, a recycle fraction from a partially
upgraded effluent, such
as a recycled naphtha, distillate and/or vacuum gas oil fraction, can be a
suitable hydrogen donor
solvent. In some aspects, it is noted that addition of a hydrogen donor
solvent can potentially provide
an additional benefit by acting as a diluent for the feed. This can improve
flow properties, such as
kinematic viscosity and/or density, which could facilitate cracking.
100241 In this discussion, a fuel gas is defined as a fraction that
includes a sufficient amount of
Ci ¨ C4 components to be suitable for combustion as a fuel, such as about 5.0
vol% or more of Ci ¨
C4 components, or 10 vol% or more, or 20 vol% or more. Fuel gas can optionally
include a variety
of other components, such as nitrogen, carbon dioxide, water, and/or other
typical components of
air; other fuel components such as hydrogen or carbon monoxide; and/or other
components that are
gases at 25 C and 100 kPa-a.
100251 In this discussion, unless otherwise specified, "conversion" of a
feedstock or other input
stream is defined as conversion relative to a conversion temperature of 566 C
(1050 F). Once-
through conversion refers to the amount of conversion that occurs during a
single pass through a
reactor / stage / reaction system. Total conversion refers to the net products
from the reactor / stage
/ reaction system, so that any recycle streams are included in the calculation
of the total conversion.
It is noted that in all aspects described herein, the amount of conversion at
524 C is lower than the
corresponding conversion at 566 C.
100261 In this discussion, a "Cx" hydrocarbon refers to a hydrocarbon
compound that includes
"x" number of carbons in the compound. A stream containing "Cx ¨ Cy"
hydrocarbons refers to a
stream composed of one or more hydrocarbon compounds that includes at least
"x" carbons and no
more than "y" carbons in the compound. It is noted that a stream comprising G
¨ Cy hydrocarbons
may also include other types of hydrocarbons, unless otherwise specified.
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Date Recue/Date Received 2020-09-03
[0027] In this discussion, "Tx" refers to the temperature at which a weight
fraction "x" of a
sample can be boiled or distilled. For example, if the temperature at which 40
wt% of a sample has
vaporized (i.e., boiled) at atmospheric pressure is 343 C, the sample can be
described as having a
T40 distillation point of 343 C. In this discussion, boiling points can be
determined by a convenient
method based on the boiling range of the sample. This can correspond to ASTM
D2887, or for
heavier samples ASTM D7169.
[0028] In various aspects of the invention, reference may be made to one or
more types of
fractions generated during distillation of a petroleum feedstock, intermediate
product, and/or
product. Such fractions may include naphtha fractions, distillate fuel
fractions, and vacuum gas oil
fractions. Each of these types of fractions can be defined based on a boiling
range, such as a boiling
range that includes at least 90 wt% of the fraction, or at least 95 wt% of the
fraction. For example,
for naphtha fractions, at least 90 wt% of the fraction, or at least 95 wt%,
can have a boiling point in
the range of 85 F (29 C) to 350 F (177 C). It is noted that 29 C roughly
corresponds to the boiling
point of isopentane, a C5 hydrocarbon. For a distillate fuel fraction, at
least 90 wt% of the fraction,
or at least 95 wt%, can have a boiling point in the range of 350 F (177 C) to
650 F (343 C). For a
vacuum gas oil fraction, at least 90 wt% of the fraction, or at least 95 wt%,
can have a boiling point
in the range of 650 F (343 C) to 1050 F (566 C). Fractions boiling below the
naphtha range can
sometimes be referred to as light ends. Fractions boiling above the vacuum gas
oil range can be
referred to as vacuum resid fractions or pitch fractions.
[0029] In this discussion, the boiling range of components in a feed,
intermediate product,
and/or final product may alternatively be described based on describing a
weight percentage of
components that boil within a defined range. The defined range can correspond
to a range with an
lower boiling temperature bound, such as components that boil at less than 177
C (referred to as
177 C-); a range with a upper boiling temperature bound, such as components
that boil at greater
than 566 C (referred to as 566 C+); or within or outside of a range with both
a lower bound and an
upper bound, such as 343 C ¨ 566 C.
[0030] Preparing heavy hydrocarbon feeds for pipeline transport often
involves achieving target
values for a plurality of separate properties. First, the viscosity of the
processed heavy hydrocarbon
feed needs to be suitable or roughly suitable for pipeline transport. This can
correspond to, for
example, having a kinematic viscosity at 7.5 C of 360 cSt or less, or 350 cSt
or less, such as down
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Date Recue/Date Received 2020-09-03
to 250 cSt or possibly still lower. Second, the density of the processed heavy
hydrocarbon feed
needs to be suitable or roughly suitable for pipeline transport. This can
correspond to, for example,
having an API Gravity of 18 or more, or 190 or more. Third, an olefin content
of the processed
heavy hydrocarbon feed also needs to be sufficiently low, such as having an
olefin content of 1.0
wt% or less. In some aspects, a relaxed set of properties may be sufficient to
satisfy transport
standards, so that having an API gravity of 14 or more and/or a kinematic
viscosity at 7.5 C of 500
cSt or less is sufficient.
100311 In this discussion, a stage is defined as a portion of a reaction
system. A stage can include
one or more reactors and/or other process elements. For example, a partial
upgrading stage can
include a single reactor or a plurality of reactors. If separations may be
conventionally performed
between reactors within a stage, such separations may optionally be present,
unless otherwise
specified. More generally, if other flow management features are
conventionally present within a
stage, such features may also optionally be present, unless otherwise
specified. For example, a
reforming stage can often include recycle of a portion of the overhead gas
from the reforming
effluent in order to introduce hydrogen into the reforming reaction
environment.
Reforming Stage and Integration for Partial Upgrading of Bitumen
100321 In various aspects, a catalytic reforming stage can be used to
reduce or minimize the
olefin content in a portion of a partially upgraded bitumen feed (or more
generally, a partially
upgraded heavy hydrocarbon feed). Depending on the nature of the partial
upgrading and the nature
of the bitumen, several options are available for selecting the portion of the
partially upgraded
bitumen for reforming. The portion of the partially upgraded bitumen used as
the input for
reforming can correspond to a naphtha boiling range portion, a distillate
boiling range portion, or a
combination thereof. Optionally, the input can include a portion of vacuum gas
oil boiling range
material. Generally, this can correspond to having an input flow to reforming
with a T5 distillation
point of 29 C or more and a T95 distillation point of 400 C or less. If vacuum
gas oil boiling range
components are not desired, the T95 distillation point can be lower, such as
370 C or less, or 343 C
or less. In aspects where only a naphtha boiling range portion is reformed,
the T5 distillation point
can be 29 C or more and the T95 distillation point can be 204 C or less (if
heavy naphtha is
included), or 177 C or less. In aspects where only a distillate boiling range
portion is reformed, the
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Date Recue/Date Received 2020-09-03
T5 distillation point can be 177 C or more and the T95 distillation point can
be 400 C or less, or
370 C or less, or 343 C or less.
100331 In aspects where the input flow to reforming includes a distillate
boiling range portion,
the input flow can correspond to an input flow having an unusually high
boiling range for a
reforming process, due to the presence of components that boil above 260 C, or
the presence of
components that boil above the kerosene boiling range (i.e., above 300 C). For
example, 10 wt%
or more of the input flow can correspond to components with a boiling point
above 260 C, or 20
wt% or more, or 30 wt% or more. In some aspects, 10 wt% or more of the input
flow can correspond
to components with a boiling point greater than 300 C, or 20 wt% or more, or
30 wt% or more. It
is noted that this could be similarly described as an input flow with a T90
distillation point greater
than 260 C (or 300 C), or a T80 distillation point greater than 260 C (or 300
C), or a T70 distillation
point greater than 260 C (or 300 C).
100341 Due to the high sulfur content of bitumen feeds, the naphtha and
distillate fractions from
partial upgrading can also have relatively high sulfur contents. The amount of
sulfur can vary
depending on the type of partial upgrading. Depending on the aspect the sulfur
content of the
naphtha fractions can range from 10 wppm to 1500 wppm, with values of 100 wppm
or more being
more typical of most partial upgrading methods. Partially upgraded distillate
fractions can include
still higher sulfur contents.
100351 In reforming, a multi-functional catalyst is employed which contains
a metal
hydrogenation-dehydrogenation (hydrogen transfer) component, or components,
substantially
atomically dispersed upon the surface of a porous, inorganic oxide support,
such as alumina. For
conventional reforming of low sulfur naphtha fractions, noble metal catalysts
(such as platinum
catalysts) are currently employed. However, platinum metal catalysts can foul
rapidly under
exposure to high sulfur content feeds resulting in a significant loss of
reforming activity. In an
embodiment of the present invention, the reformer feed from the process
configurations described
herein can have a sulfur content of 100 wppm or more, and a non-noble active
metal catalyst, such
as a catalyst comprising nickel as the active metal, may be preferably
utilized in the reforming stage.
100361 A reforming process can be defined as the total effect of the
molecular changes, or
hydrocarbon reactions. The naphthene portion of the naphtha stream is
dehydrogenated to the
corresponding aromatic compounds, the normal paraffins are isomerized to
branched chain
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Date Recue/Date Received 2020-09-03
paraffins, and various aromatics compounds are isomerized to other aromatics.
Additionally, based
on the presence of both hydrogen and a catalyst with hydrogenation /
dehydrogenation activity,
olefins can be saturated. The high boiling components in the naphtha stream
are also hydrocracked
to lower boiling components. Specifically, these molecular changes are
produced by
dehydrogenation of cyclohexanes and dehydroisomerization of alkylcyclopentanes
to yield
aromatics; dehydrocyclization of paraffins and olefins to yield aromatics;
saturation of olefins;
isomerization of n-paraffins; isomerization of alkylcycloparaffins to yield
cyclohexanes;
isomerization of substituted aromatics; and cracking reactions which produce
gas.
100371 In a reforming process, one or a series of reactors, providing a
series of reaction zones,
are employed. A reforming reactor can generally include a fixed bed, or beds,
of catalyst, which
receive feed. Any convenient reactor configuration can be used, such as
downflow or radial flow.
Optionally, each reactor is provided with a preheater, or interstage heater,
because the net effect of
the reactions which take place is typically endothermic. A naphtha and/or
distillate feed, with
hydrogen, and/or hydrogen-containing recycle gas, is passed through the
preheat furnace then to the
reactor, and then in sequence through subsequent interstage heaters and
reactors of the series. The
product from the last reactor is separated into a liquid fraction and a
vaporous fraction, the former
usually being recovered as a C5+ liquid product. The latter is rich in
hydrogen and usually contains
small amounts of normally gaseous hydrocarbons. A portion of the hydrogen-rich
overhead can be
recycled to the process to minimize coke production.
100381 The input flow to catalytic reforming can contain 20 vol% to 80 vol%
paraffins, 20 vol%
to 80 vol% naphthenes, and 5 vol% to 20 vol% aromatics. The input flow is
brought into contact
with a catalyst system, such as the catalysts described above, in the presence
of hydrogen. The
reactions typically take place in the vapor phase at a temperature varying
from about 343 C (650 F)
to 538 C (1000 F), or 400 C to 538 C, or 400 C to 500 C. Reaction zone
pressures may vary from
100 to 5000 kPa-g, preferably 500 to 2500 kPa-g. It is noted that due to the
relatively high sulfur
content of partially upgraded bitumen, as well as the potential presence of
other contaminants, some
increase in reaction severity may be needed to compensate for the reaction
environment. On the
other hand, the reforming process is being performed primarily for olefin
removal and H2
production. This can require lower severity conditions than a reforming
reaction for improving the
octane of naphtha.
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Date Recue/Date Received 2020-09-03
100391 The input flow is generally passed over the catalyst at a weight
hourly space velocity of
0.1 to 20 hr-1, preferably from about 1 to 10 w/hr/w. The hydrogen to
hydrocarbon mole ratio within
the reaction zone is maintained between about 0.5 and 20, preferably between
about 1 and 10.
100401 The reformed effluent can have various properties that are modified
relative to the input
flow to the reforming stage. In some aspects, the olefin content of the
reformed effluent can be 1.0
wt% or less, or 0.8 wt% or less, or 0.5 wt% or less, or 0.2 wt% or less, such
as down to 0.05 wt%
or possibly still lower. While aromatics will also be formed, any convenient
amount of aromatics
can be generated during reforming, so long as the desired olefin reduction
occurs. This can be in
contrast to some conventional reforming conditions, where the goal is to
increase the aromatic
content of the input flow to reforming. Depending on the aspect, the aromatics
content of the
reformed effluent can be greater than the aromatics content of the input flow
to the reforming stage
by 1.0 wt% to 20 wt%, or 1.0 wt% to 10 wt%, or 5.0 wt% to 20 wt%.
100411 Figure 1 shows an example of how a reforming stage can be integrated
into a system for
partial upgrading of bitumen (or another type of heavy hydrocarbon feed). In
the example shown
in Figure 1, a heavy hydrocarbon feed such as bitumen 105 is passed into a
partial upgrading
reaction system 110. Any convenient type of partial upgrading stage can be
used. Examples of
suitable partial upgrading include, but are not limited to, visbreaking
(optionally in the presence of
a hydrogen donor solvent), sodium desulfurization, slurry hydrocracking, other
types of thermal
cracking, and/or various types of hydroprocessing. In the example shown in
Figure 1, the partial
upgrading stage is heated 179 using a fired heater 170. The fuel for fired
heater 170 can optionally
correspond to fuel gas stream 162.
100421 The partial upgrader 110 can produce a partially upgraded effluent
115. In the example
shown in Figure 1, the partially upgraded effluent 115 is then separated 120
into a lower boiling
fraction 125 including the naphtha and distillate boiling range portions from
the partially upgraded
effluent, and a higher boiling fraction 145 that includes the vacuum gas oil
and resid portions. It is
understood that in other aspects, any other convenient choice could be made
for separating 120 the
partially upgraded effluent. For example, some or all of the distillate could
be included in the higher
boiling portion 145, or some of the vacuum gas oil could be included in the
lower boiling portion
125. In still other aspects, separate naphtha and distillate fractions could
be formed (not shown), to
allow for exposure of the naphtha fraction and distillate fraction to separate
reforming conditions.
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Date Recue/Date Received 2020-09-03
Due to the nature of the reforming conditions, inclusion of vacuum resid
and/or heavier portions of
the vacuum gas oil could result in excessive coke formation and/or fouling
under catalytic reforming
conditions.
100431 In aspects where only heavier portions of the initial bitumen feed
are passed into the
partial upgrading stage, a portion of the feed to reforming stage 130 can
correspond to virgin naphtha
and/or virgin distillate that have been separated from the bitumen prior to
the partial upgrading stage.
While virgin naphtha and virgin distillate typically include only minimal
olefin content, such virgin
naphtha and/or distillate fractions could allow for further aromatics
production which are beneficial
to the flow characteristics of the final pipeline product.
100441 The lower boiling portion 125 can then be passed into reforming
stage 130. The
reforming stage produces a reformed effluent 135 and a reformer overhead
stream 132. The
reformed effluent 135 can then be recombined with higher boiling fraction 145
in blending stage
150 to form a partially upgraded product 155 with an olefin content that is
suitable for transport,
such as an olefin content of 1.0 wt% or less that is suitable for pipeline
transport. It is noted that any
portion of initial feed 105 that bypasses (not shown) the partial upgrading
stage 110 can also be
incorporated into the partially upgraded product 155. Optionally, a diluent
can also be added to the
partially upgraded product 155 in blending stage 150 to assist with satisfying
other transport
specifications.
100451 In the example shown in Figure 1, the reformer overhead stream 132
can be passed into
a gas separation unit 160. This can allow for separation of a hydrogen-
enriched stream 161 from a
fuel gas stream 162. The hydrogen-enriched stream can correspond to a stream
containing 30 vol%
or more of H2, or 50 vol% or more, such as up to 90 vol% or possibly still
higher. The balance of
the hydrogen-enriched stream can be other components from the reforming
reaction environment,
such as nitrogen, water, and/or Ci ¨ C4 hydrocarbons. The fuel gas 162 can
have a lower hydrogen
content than the hydrogen-enriched stream 161. In aspects where partial
upgrading stage 110
benefits from having hydrogen in the reaction environment, hydrogen-enriched
stream 161 can be
used to provide at least part of such hydrogen. In aspects where hydrogen is
not needed for operation
of partial upgrading stage 110, the hydrogen can be used for other purposes,
or can be used as a
second fuel stream for heater 170. Optionally, the hydrogen-enriched stream
161 can form part of
the recycled hydrogen (not shown) that is returned to reforming stage 130.
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Bitumen and Other Heavy Hydrocarbon Feedstocks
[0046] In various aspects, the initial feed to the partial upgrading stage
can correspond to a
bitumen and/or another type of heavy hydrocarbon feed. A bitumen feed can
correspond to a
bitumen formed from oil sands (or another heavy hydrocarbon feed) by any
convenient method.
Such methods include, but are not limited to, a paraffinic froth treatment
process, a naphtha froth
treatment, a cyclic steam stimulation (CSS) process, a liquid addition to
steam to enhance recovery
(LASER) process, a steam-assisted gravity drainage process (SAGD), solvent-
assisted steam-
assisted gravity drainage (SA-SAGD) process, a heated vapor extraction (VAPEX)
process, a cyclic
solvent process (CSP), or a combination thereof. Other examples of heavy
hydrocarbon feeds
include, but are not limited to, heavy crude oils, and heavy oils derived from
coal, and blends of
such feeds. In some aspects, heavy hydrocarbon feeds can also include at least
a portion
corresponding to a heavy refinery fraction, such as distillation residues,
heavy oils coming from
catalytic treatment (such as heavy cycle slurry oils or main column bottoms
from fluid catalytic
cracking), and/or thermal tars (such as oils from visbreaking, steam cracking,
or similar thermal or
non-catalytic processes). Heavy hydrocarbon feeds can be liquid or semi-solid.
Such heavy
hydrocarbon feeds can include a substantial portion of the feed that boils at
650 F (343 C) or higher.
For example, the portion of a heavy hydrocarbon feed that boils at less than
650 F (343 C) can
correspond to 5 wt% to 40 wt% of the feed, or 10 wt% to 30 wt% of the feed, or
5 wt% to 20 wt%
of the feed. In such aspects, the heavy hydrocarbon feed can have a T40
distillation point of 343 C
or higher, or a T30 distillation point of 343 C or higher, or a T20
distillation point of 343 C or
higher. Additionally or alternately, a substantial portion of a heavy
hydrocarbon feed can also
correspond to compounds with a boiling point of 566 C or higher. For example,
a heavy
hydrocarbon feed can have a T80 distillation point of 566 C or higher, or a
T70 distillation point of
566 C or higher, or a T60 distillation point of 566 C or higher, or a T50
distillation point of 566 C
or higher.
[0047] Density, or weight per volume, of the heavy hydrocarbon can be
determined according
to ASTM D287 - 92 (2006) Standard Test Method for API Gravity of Crude
Petroleum and
Petroleum Products (Hydrometer Method), and is provided in terms of API
gravity. In general, the
higher the API gravity, the less dense the oil. API gravity can be 16 or
less, or 12 or less, or 8 or
less. Additionally or alternately, the density at 15 C of the bitumen (or
other heavy hydrocarbon
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Date Recue/Date Received 2020-09-03
feed) can be 0.95 g/cm3 to 1.2 g/cm3, or possibly still higher. Further
additionally or alternately, the
kinematic viscosity of the feed at 7.5 C can be 500 cSt or greater. This can
be determined according
to the test method specified in ASTM D2170, although the temperature differs
from the test
specification.
100481 Heavy hydrocarbon feeds can be high in metals. For example, the
heavy hydrocarbon
feed can be high in total nickel, vanadium and iron contents. In one
embodiment, the heavy oil will
contain at least 0.00005 grams of Ni/V/Fe (50 ppm) or at least 0.0002 grams of
Ni/V/Fe (200 ppm)
per gram of heavy oil, on a total elemental basis of nickel, vanadium and
iron. In other aspects, the
heavy oil can contain at least about 500 wppm of nickel, vanadium, and iron,
such as at least about
1000 wppm.
100491 Contaminants such as nitrogen and sulfur are typically found in
heavy hydrocarbon
feeds, often in organically-bound form. Nitrogen content can range from about
0.1 wt% to about
3.0 wt% elemental nitrogen, or 1.0 wt% to 3.0 wt%, or 0.1 wt% to 1.0 wt%,
based on total weight
of the heavy hydrocarbon feed. Generally, the sulfur content can range from
0.1 wt% to 10 wt%
elemental sulfur, or 1.0 wt% to 10 wt%, or 0.1 wt% to 5.0 wt%, or 1.0 wt% to
7.0 wt%, based on
total weight of the heavy hydrocarbon feed. Sulfur will usually be present as
organically bound
sulfur.
100501 Heavy hydrocarbon feeds can be high in n-pentane asphaltenes and/or
n-heptane
asphaltenes. In some aspects, the heavy hydrocarbon feed can contain 5.0 wt%
or more of n-pentane
asphaltenes, or 10 wt% or more, or 15 wt% or more, such as up to 30 wt% or
possibly still higher.
Additionally or alternately, the heavy hydrocarbon feed can contain 3.0 wt% or
more of n-heptane
asphaltenes, or 5.0 wt% or more, or 10 wt% or more, such as up to 25 wt% or
possibly still higher.
In other aspects, the heavy hydrocarbon feed can correspond to a feed that is
at least partially derived
from performing a froth treatment on oil sands, such as a paraffinic froth
treatment. In such aspects,
the amount of n-heptane asphaltenes can be 15 wt% or less, or 10 wt% or less,
or 5.0 wt% or less,
such as down to 1.0 wt% or possibly still lower. In yet other aspects, a
modified froth treatment can
be used that allows an increased amount of asphaltenes to be retained in the
bitumen after froth
treatment. In such aspects, the amount of n-heptane asphaltenes can be 5.0 wt%
to 20 wt%, or 5.0
wt% to 15 wt%, or 10 wt% to 20 wt%
- 14 -
Date Recue/Date Received 2020-09-03
100511 Still another method for characterizing a heavy hydrocarbon feed is
based on the
Conradson carbon residue of the feedstock, or alternatively the micro carbon
residue content. The
Conradson carbon residue / micro carbon residue content of the feedstock can
be 5.0 wt% to 50
wt%, or 5.0 wt% to 30 wt%, or 10 wt% to 40 wt%, or 20 wt% to 50 wt%.
100521 In some optional aspects, rather than performing partial upgrading
on the bitumen and/or
heavy hydrocarbon feed, a fractionation can be performed so that only a
portion of the feed is
exposed to the partial upgrading conditions. In aspects where fractionation is
performed prior to
partial upgrading, the fractionation stage can include components for
performing an atmospheric
distillation, a vacuum distillation, one or more flash separations, or a
combination thereof.
Optionally, one or more solvent deasphalting units can also be used. As an
example, a separation
can be performed on a heavy hydrocarbon feed to form a lower boiling (lighter)
fraction and a higher
boiling (heavier) fraction. The heavier fraction can have a T50 distillation
point of 400 C or more,
or 500 C or more. Additionally, the T50 distillation point of the lighter
fraction can be lower than
the T50 distillation point of the heavier fraction. The lighter fraction can
have a T95 distillation
point of 500 C or less, or 400 C or less. Additionally, the T95 distillation
point of the heavier
fraction can be higher than the T95 distillation point of the lighter
fraction.
Example of Partial Upgrading Conditions - Visbreaking
100531 In various aspects, the partial upgrading process can correspond to
visbreaking
(including visbreaking in the presence of a hydrogen donor solvent),
hydroprocessing (such as slurry
hydrocracking), coking (such as fluidized coking), or desulfurization (such as
sodium
desulfurization). In order to illustrate the concepts described herein,
additional details are provided
for using visbreaking as the method of partial upgrading.
100541 Visbreaking is a thermal upgrading process where a feed is exposed
to thermal cracking
temperatures, but for a period of time where coking of the feed is reduced or
minimized. Since the
tendency to form coke can vary with the nature of a feed, the desired severity
of a visbreaking
process can vary based on the feed. In some aspects, the severity of
visbreaking that can be
performed without resulting in coking can be increased by adding a donor
solvent to the visbreaking
environment.
[0055] In most hydrocarbon processes, there is a tradeoff between reaction
temperature and
residence time of reactants. Because visbreaking is a well-known and widely
practiced process,
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Date Recue/Date Received 2020-09-03
however, correlations have been developed so that it is possible to express
precisely the severity of
the visbreaking process. An expression of the "severity" of a particular
visbreaking operation does
not mean that a certain degree of conversion can be predicted or obtained or
that a certain amount
of coke or sediment will be formed; rather it means that it is possible to
predict that if all other
reaction parameters are unchanged (e.g., feed composition, reactor pressure)
except for the
temperature and residence time in the reactor, two operations can be compared
and it can be
determined whether one process is more severe than the other. Equations and
tables have been
developed for comparing reaction severities. Typical of such presentations is
the discussion of
"soaking factor" in Petroleum Refinery Engineering¨Thermocracking and
Decomposition Process-
-Equation 19-23 and Table 19-18, in Nelson--Modern Refining Technology,
Chapter 19. The
"soaking factor" corresponds to the severity index as defined above.
100561 In this discussion, severity index refers to the severity of the
operation, expressed as the
equivalent number of seconds of residence time in a reactor operating at 427 C
(800 F). It is noted
that other definitions of severity index are possible based on different
temperatures of operation. In
very general terms, the reaction rate doubles for every 12 C to 13 C increase
in temperature. Thus,
60 seconds of residence time at 427 C is equivalent to a severity index of 60,
and increasing the
temperature to 456 C would make the operation five times as severe, i.e. a
severity index of 300.
Expressed in another way, 300 seconds at 427 C is equivalent to 60 seconds at
456 C, and the same
product mix and distribution should be obtained under either set of
conditions.
100571 The visbreaking process conditions which may be used can vary widely
based on the
nature of the heavy oil material, the optional hydrogen-donor material and
other factors. In general,
the visbreaking can be carried out at temperatures ranging from 350 C to 485
C, preferably 400 C
to 440 C, at residence times ranging from 1 to 60 minutes, preferably 15 to 45
minutes. Expressed
as severity index, the partial upgrading can be performed at a severity index
of 250 to 5000, or 400
to 2500, or 250 to 2500, or 1000 to 2500, or 400 to 1000, or 250 to 1000, or
500 to 800. It is noted
that these severity ranges correspond to severities for process conditions
corresponding to various
types of visbreaking, visbreaking in the presence of hydrogen and/or a
hydrogen donor, and/or other
types of milder partial upgrading. The severity for a partial upgrading
process based on coking can
correspond to a severity index greater than 5000.
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Date Recue/Date Received 2020-09-03
100581 The severity index for the partial upgrading can be selected, for
example, in order to
achieve a desired density and/or a desired kinematic viscosity for the
partially upgraded product.
For example, the severity index can be selected to achieve an API gravity for
the partially upgraded
product of 14 or more, or 16 or more, or 18 or more, or 19 or more.
Additionally or alternately,
the severity index can be selected to achieve a kinematic viscosity at 7.5 C
of 500 cSt or less, or
400 cSt or less, or 360 cSt or less, or 350 cSt or less.
100591 The limit of severity is determined primarily by product quality.
Visbreaking is a
relatively inexpensive process, and once a visbreaker has been installed, it
does not cost much more
to run it at high severity in order to achieve the maximum viscosity reduction
possible with a given
feed stock. However, the two limiting factors in the visbreaker operation are
the formation of coke
(which tends to plug the coil and/or soaking drum used in the visbreaker and
also take the product
out of specification) and sediment formation in the product. Sediment
formation is a complicated
phenomenon. As a generalization, it can be stated that, if the composition of
an oil is changed
enough, the asphaltic materials may no longer dissolve in the product and
hence settle out as
sediment. The problem becomes worse when cutter stocks or blending stocks of a
less aromatic
nature are added to the visbreaker product; the asphaltics or other materials
that would remain
dissolved in the visbreaker product are no longer soluble upon blending the
visbreaker product with
other, less aromatic materials.
100601 The pressure employed in a visbreaker can usually be sufficient to
maintain most of the
material in the reactor coil and/or soaker drum in the liquid phase. Normally
the pressure is not
considered as a control variable, although attempts are made to keep the
pressure high enough to
maintain most of the material in the visbreaker in the liquid phase. Some
vapor formation in the
visbreaker is not harmful, and is frequently inevitable because of the
production of some light ends
in the visbreaking process. Some coil visbreaker units operate with 20-40%
vaporization material at
the visbreaker coil outlet. Lighter solvents will vaporize more and the vapor
will not do much good
towards improving the processing of the liquid phase material. Accordingly,
liquid phase operation
is preferred, but significant amounts of vaporization can be tolerated.
100611 In general, the pressures commonly encountered in visbreakers range
from 170 to 10450
kPa, or 1480 to 8500 kPa. Such pressures will usually be sufficient to
maintain liquid phase
conditions and the desired degree of conversion.
- 17 -
Date Recue/Date Received 2020-09-03
100621 In some aspects, a hydrogen donor solvent can be used. In a partial
upgrading
environment, a suitable donor solvent can be a recycled portion of the
partially upgraded effluent,
such as a recycled distillate portion and/or a recycled vacuum gas oil
portion. If a hydrogen donor
solvent is used, the hydrogen donor solvent can correspond to 0.1 wt% to 50
wt% of the total flow
into the visbreaker.
100631 In some aspects, the visbreaking can be performed in the presence of
hydrogen gas. In
such aspects, the visbreaking can be performed in the presence of hydrogen
partial pressures ranging
from 0.4 MPa-g to 13.9 MPa-g (-50 to ¨2000 psig) and treat gas rates of from
89 m3/m3 to 890
m3/m3 (-500 to ¨5000 scf/B).
100641 In other aspects, any convenient type of partial upgrading can be
performed. For
example, if slurry hydrocracking or another type of hydroprocessing is used,
the desired goals of
partial upgrading can be similar. Thus, the hydroprocessing conditions can be
selected to achieve
an API gravity of 14 or more, or 16 or more, or 18 or more, or 19 or more
and/or a kinematic
viscosity at 7.5 C of 500 cSt or less, or 400 cSt or less, or 360 cSt or less,
or 350 cSt or less. This
can correspond to, for example, performing partial upgrading with total
conversion relative to 566 C
of 40 wt% to 90 wt%, or 40 wt% to 70 wt%, or 70 wt% to 90 wt%.
100651 When numerical lower limits and numerical upper limits are listed
herein, ranges from
any lower limit to any upper limit are contemplated. While the illustrative
embodiments of the
invention have been described with particularity, it will be understood that
various other
modifications will be apparent to and can be readily made by those skilled in
the art without
departing from the spirit and scope of the invention. Accordingly, it is not
intended that the scope
of the claims appended hereto be limited to the examples and descriptions set
forth herein but rather
that the claims be construed as encompassing all the features of patentable
novelty which reside in
the present invention, including all features which would be treated as
equivalents thereof by those
skilled in the art to which the invention pertains.
100661 The present invention has been described above with reference to
numerous
embodiments and specific examples. Many variations will suggest themselves to
those skilled in
this art in light of the above detailed description. All such obvious
variations are within the full
intended scope of the appended claims.
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