Note: Descriptions are shown in the official language in which they were submitted.
CA 02848789 2014-04-14
PROCESS FOR TREATING MINED OIL SANDS DEPOSITS
FIELD OF THE INVENTION
The invention relates to a method for improving a heavy hydrocarbon to a
lighter more fluid product and,
more specifically, to a hydrocarbon product that is refinery-ready and that
meets pipeline transport criteria
without requiring the addition of diluents.
BACKGROUND
Refining of sweet crude resources requires less capital input and less cost
expenditure than processing
heavy sour crudes. However, the processing of heavy sour crude has become an
increasingly important
option to meet the world's demand for hydrocarbon-based fuels. Heavy sour
crude may be derived from
bitumen. Bitumen is a form of petroleum that exists in the semi-solid or solid
phase in natural deposits.
Bitumen is a thick, sticky form of crude oil, having a viscosity greater than
10,000 centipoises under
reservoir conditions, an API gravity of less than 10* API and typically
contains over 15 wt% C5-asphaltenes.
Most, if not all, commercial upgraders for processing heavy crude have been
built to convert heavy viscous
hydrocarbons into crude products that range from light sweet to medium sour
blends. Heavy oil upgraders
basically achieve this conversion by using high intensity conversion
processes. These processes may release
up to 20% by weight of the feedstock as a coke byproduct and another 5% as off-
gas product. Alternatively,
these processes require significant hydro-processing such as ebullated bed
hydrocracking and fixed bed
hydro-treating to maximize the conversion of the heavy components in the
feedstock to lighter, lower
sulfur liquid products.
Various processes have been used to convert and/or condition oil sands bitumen
into pipeline
transportable and refinery acceptable crude. Of note, thermal cracking,
catalytic cracking, solvent
deasphalting and various combinations thereof (for example, visbreaking and
solvent deasphalting) have
been proposed to convert bitumen to hydrocarbon streams having characteristics
suitable for pipeline
transport and use as a refinery feedstock. Some examples of these
methodologies are presented below.
In U.S. Patent No. 4,454,023 ("the '023 Patent"), a process for the treatment
of heavy viscous hydrocarbon
oil is disclosed. The process involves the steps of: visbreaking the oil;
fractionating the visbroken oil; solvent
deasphalting the non-distilled portion of the visbroken oil in a two-stage
deasphalting process to produce
separate asphaltene, resin, and deasphalted oil fractions; mixing the
deasphalted oil ("DAO") with the
visbroken distillates; and recycling and combining resins from the
deasphalting step with the initial
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CA 02848789 2014-04-14
feedstock. While the '023 Patent provides a means for upgrading lighter
hydrocarbons (API gravity>15), the
API of a typical composition of Canadian bitumen is lower than this. In
addition, thermal cracking will
generally result in over-cracking and coking of the hydrocarbon stream. There
is added complexity and cost
associated with the two-stage solvent deasphalting system (e.g. separation of
the resin fraction from the
deasphalted oil, and recycling of the resin stream).
U.S. Patent No. 4,191,636 describes a process in which heavy oil is
continuously converted into asphaltenes
and metal-free oil. The process involves hydrotreating the heavy oil to crack
asphaltenes selectively and
remove heavy metals such as nickel and vanadium simultaneously. The liquid
products are separated into a
light fraction and a heavy fraction of an asphaltene- and heavy metal-
containing oil. The light fraction is
recovered as a product and the heavy fraction is recycled to the hydrotreating
step. It is not clear whether
this process would be effective for the catalytic conversion of Canadian
bitumen (API gravity<10).
Accordingly, there is an on-going need to develop cost-effective and efficient
ways to process heavy
hydrocarbons such as Canadian bitumen.
While there have been various processes disclosed for separating and treatment
of a hydrocarbon feed
source, there is still a need to identify processes that are suitable for
handling heavy hydrocarbon feeds,
such as Canadian bitumen. The present invention provides a low complexity, low
severity, yet reliable
operational procedure to separate and convert Canadian bitumen to produce a
pipelineable product
without the need for external diluent. The methods disclosed herein achieve
this result by performing a
lower complexity separation than typically used, while minimizing the
conversion steps typically seen in
producing refinery-type streams (e.g. minimizing the conversion steps decrease
the complexity with a
corresponding decrease in cost). In this way, much of the virgin portion of
the feed bitumen can be used in
the final product blend.
Current processes used in industry include combinations of diluent recovery
(DRU) + vacuum distillation
(VDU) + delayed coking + hydrotreating and/or DRU + VDU + heavy oil stripper +
residue hydrocracking +
hydrotreating and/or some combination of the first two. These processes
produce a synthetic crude oil
with API's above 30 which requires more processing than what is required to be
sent in pipelines. The
process according to an embodiment of the present invention yields a 19-21 API
product (which meets
pipeline specification) from a less complex process.
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SUMMARY OF THE INVENTION
According to a first aspect of the invention, a process is provided for
converting a heavy hydrocarbon
stream into a pipelineable product, said process comprising:
(a) using a froth treatment process to separate bitumen present in
the heavy hydrocarbon
stream from water creating a solvent/bitumen stream and a water-rich stream;
(b) extracting the solvent/bitumen stream to generate multiple
product streams comprising:
i) a bitumen bottoms stream;
ii) a virgin heavy vacuum gas oil stream;
iii) a light virgin vacuum gasoil stream; and
iv) a light virgin atmospheric gas oil stream;
(c) converting, in a conversion unit, a portion of the heavy vacuum
gas oil stream and/or
bitumen bottoms obtained from step (b) to produce a stream of lighter
hydrocarbons; and
(d) blending a portion or all of the virgin heavy vacuum gas oil
stream, the light virgin vacuum
gasoil stream, the light virgin atmospheric gas oil stream from step (b) and
the stream of lighter
hydrocarbons produced in step (c) to create a pipelineable product.
Preferably, the process further comprises the step of recovering solvent from
step (b) for reuse in the froth
treatment step. Also preferably, the conversion is performed thermally and/or
catalytically.
Preferably, the process further comprises the step of mining bitumen-rich soil
deposits to obtain the
bitumen for the process. More preferably, the process further comprises the
extraction of bitumen from
soil deposits using a water extraction process to create a water/bitumen
stream and a soil rich stream; and
forwarding the water/bitumen stream to the froth treatment process of step
(a).
Preferably, the pipelineable product has over 20vol% of 950 F (510 C) and
heavier boiling range material
and less than 15vol% of 350 F (177 C) and lighter boiling range material.
Preferably, the process further comprises the addition of heavier heavy virgin
gas oil to the stream in the
conversion unit during the conversion step (c). Also preferably, the process
further comprises the addition
of light virgin gas oil to the stream in the conversion unit during the
conversion step (c).
According to another aspect of the invention, a process is provided for
converting mined bitumen into a
pipelineable product, the process comprising:
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(a) adding hot water to the mined bitumen to obtain a heavy hydrocarbon
stream;
(b) separating the bitumen in the heavy hydrocarbon stream bitumen from the
water using a
paraffinic solvent to create a solvent/bitumen stream and a water stream
containing asphaltenes
and solids;
(c) extracting the solvent/bitumen stream from step (b) to generate two
product streams
comprising:
i) a heavy bitumen stream; and
ii) a light virgin atmospheric gas oil stream;
(d) distilling the heavy bitumen stream in (c) to produce
i) a virgin light vacuum gas oil;
ii) a heavy vacuum gas oil stream and
iii) a bottoms stream;
(e) treating a portion of the heavy vacuum gas oil stream in a
fixed bed hydrocracker to
produce a stream of lighter hydrocarbons;
(f) blending the light virgin atmospheric gas oil stream from step (c), the
first virgin light
vacuum gas oil from step (d), a portion of the heavy vacuum gas oil stream;
and the stream of
lighter hydrocarbons from step (e)to create a pipelineable product.
Preferably, the pipelineabfe product has over 20vol% of 950 F (510 C) and
heavier boiling range material
and less than 15vol% of 350 F (177 C) and lighter boiling range material.
Preferably, the process further comprises a step to process a portion of the
bottoms stream from step (d)
through the use of a solvent deasphalting unit to create an additional stream
to be sent to the
hydrocracker.
Preferably, the process further comprises adjusting the amount of heavy virgin
gas oil feed into the fixed
bed hydrocracker.
Preferably, the process further comprises adjusting the amount of a light
virgin gas oil feed into the fixed
bed hydrocracker.
Preferably, the process further comprises the recovery of the solvent from
step (c) for reuse in the process.
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According to another aspect of the invention, a process is provided for
producing a pipelineable product
from mined bitumen, the process comprising:
(a) adding hot water to the mined bitumen to obtain a heavy hydrocarbon
stream;
(b) separating the bitumen in the heavy hydrocarbon stream from the water
using a naphtha-
based solvent to create a solvent/bitumen stream and a water stream containing
asphaltenes;
(c) extracting the solvent/bitumen stream to generate a heavy bitumen
stream and a light
virgin atmospheric gas oil stream;
(d) distilling the heavy bitumen stream produced in step (c) in a solvent
deasphalting unit to
produce a virgin deasphalted oil stream and a heavy bitumen bottoms stream
containing
asphaltenes and solids;
(e) processing the heavy bitumen bottoms stream obtained in step (d) in a
thermal conversion
unit to remove solids and produce a stream of lighter hydrocarbons;
(f) processing a portion of the stream of lighter hydrocarbons produced in
step (e) in a
hydrotreating unit to produce a stream of hydrotreated lighter hydrocarbons;
(g) blending the light virgin atmospheric gas oil stream, the virgin
deasphalted oil stream, the
stream of lighter hydrocarbons and the stream of hydrotreated lighter
hydrocarbons to create a
pipelineable product.
Preferably, pipelineable product has over 20vol% of 950 F (510 C) and heavier
boiling range material and
less than 10 vol% of 350 F (177 C) and lighter boiling range material.
Preferably, the solids removed at step (d) are further processed in a metals
recovery unit to recover
precious metals such as vanadium, and titanium.
According to one aspect, a process for converting heavy crude oils to a
lighter hydrocarbon crude is
disclosed. The heavy crude may be an type of bitumen, preferably mined
Canadian Oil Sands bitumen, or
steam-assisted well-based bitumen (e.g. SAGD sourced bitumen). The light crude
produced from the
process is suitable for pipeline transport and can be used as a refinery
feedstock. The process generally
consists of the following steps:
(a) feeding a bitumen-rich stream (25) to a froth treatment process (30) to
produce a substantially
water-free diluted bitumen stream (35);
(b) separating (40) diluted bitumen to recover the diluent (43) for reuse in
the froth treatment
process and to produce
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i) a light hydrocarbon component (41) for direct product blending (1);
ii) a virgin atmospheric gas oil (45) for direct product blending (1);
iii) a heavy vacuum gas oil or a combination of virgin light and heavy vacuum
gas oils (49);
a nd
iv) a bitumen bottoms component (47) for direct product blending (1);
(c) converting the heavy vacuum gas oil or combination from (b)(iii) to
produce a product (65) for
blending (1) ; and
(d) blending of the product streams (b)(i), (b)(ii), (b)(iv) and (c) to
produce a final product (95).
The final product (95) is blended to meet pipeline specifications. Pipeline
specifications typically include but
are not limited to viscosity of less than or equal to 300 cSt at ambient
conditions, basic sediment and water
(BS&W) of less than or equal to 0.5 vol% and no olefins measured in the
product.
Optionally, the process further comprises processing a portion of stream (65)
in a dehexanizer to generate
make-up solvent for froth treatment and sending the remaining product from the
dehexanizer to product
blending (1).
As a person skilled in the art would appreciate, there may be additional
processing steps included in the
process. For example, optionally, preceding the fixed bed hydrocracking, there
may be a solvent
deasphalting step (e.g. carried out in a SDA unit) to extract heavy gas oils
from the bottoms resulting from
the vacuum step.
The light hydrocarbon stream produced as a result of step (b) can be used
directly for product blending
because generally the light hydrocarbon stream meets pipeline specifications
(e.g. less than 350 cSt).
Removing the light hydrocarbons after stage (b) of the process described above
is useful because their
presence would add unnecessary volume to the subsequent steps. Also, this
light hydrocarbon could be
degraded in the subsequent steps.
According to a second aspect, a process for converting heavy crude oil to a
lighter hydrocarbon crude is
disclosed. The starting heavier crude may be bitumen, such as Canadian Oil
Sands bitumen. The final
product is generally ready for pipeline transport and to be used as a refinery
feedstock. The process
comprises:
(a) treating a bitumen-rich stream using a paraffinic froth treatment process
(230);
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(b) introducing the treated stream from (a) into a diluent recovery column
(240) to produce:
(i) a virgin atmospheric gasoil for direct product blending (245);
(ii) a stream (247)
(c) recycling solvent from the diluent recovery column back to the paraffinic
froth treatment
process;
(d) separating stream (247) to produce:
(i) light virgin vacuum gasoil (259)
(ii) heavy virgin vacuum gasoil (251); and
(ii) a bottoms stream (257);
(e) forwarding the light virgin vacuum gasoil and a portion of the heavy
virgin vacuum gasoil to
product blending (2);
(f) converting a portion of the heavy virgin vacuum gasoil using a fixed bed
hydrocracker (260);
(g) forwarding a lighter hydrocarbon stream (265) and a remaining uncoverted
heavy vacuum gasoil
stream (269) from the hydrocracker for direct product blending (2);
(h) blending streams (245), (251), (259), (257) and (269) to produce a product
(295).
As a person skilled in the art would appreciate, additional steps may be
incorporated into the above
procedure. For example, there may be a dehexanizer unit following the fixed
bed hydrocracking. As a
person skilled in the art would appreciate, step (d) may be carried out in a
vacuum distillation unit.
According to another aspect, there is provided a method similar to that
outlined in the second aspect
above, but further comprising using a solvent deasphalting unit (SDA) after
separating step (240). Products
resulting from the SDA treatment may be used to extract additional gasoils for
hydrocracking and for direct
product blending.
According to yet another aspect of the invention, there is provided a method
to produce a lighter
hydrocarbon fraction from a heavy crude, the method comprising:
(a) using a naphthenic froth treatment (430) to produce a stream (435);
(b) removing stream (435) to a diluent recovery unit to recover and recycle
diluent (443) for froth
treatment;
(c) producing a virgin atmospheric gasoil (445) for direct product blending;
(d) producing a stream of heavy bitumen (447) for treatment in a solvent
deasphalting unit (450);
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CA 02848789 2014-04-14
(e) removing a portion of the stream from the solvent deasphalting unit to
direct product blending
(495);
(f) removing a portion of the stream from the solvent deasphalting unit to a
coking process (460);
(g) removing a portion of the stream from the coking process to hydrotreating;
(h) blending streams (445), (457) and (475) to produce a product (4).
As with the other processes described here, the product meets pipeline
specifications. As well, there may
be additional steps. For example, there may be additional product streams
generated from the SDA process
to generate additional products such as asphalt blending feedstock.
In all of the processes described herein, ideally, solvent is recycled to the
froth treatment unit to avoid the
production of diluted bitumen and to ensure the appropriate streams are
produced for product blending.
Solvent recycling also contributes to the economic efficiency of the entire
process. The solvent can be
recycled after the extraction of the solvent/bitumen stream, and solvent
recycling can be incorporated at
various other points in the processes described.
BRIEF DESCRIPTION OF THE DRAWINGS
Several aspects of the present invention are illustrated by way of example,
and not by way of limitation, in
detail in the figures, wherein:
Fig. 1 is an illustrative process diagram for forming a pipeline transportable
hydrocarbon product from a
mined bitumen deposit.
Fig. 2 is a process diagram for forming a pipeline transportable hydrocarbon
product from a mined bitumen
deposit using paraffinic froth treatment.
Fig. 3 is a process diagram showing an alternate embodiment to the process
diagram in Figure 2.
Fig. 4 is a process diagram for forming a pipeline transportable hydrocarbon
product from a mined bitumen
deposit using naphthenic froth treatment.
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DETAILED DESCRIPTION
The detailed description set forth below, in conjunction with Figures 1 to 4,
is intended as a description of
various embodiments of the present disclosure and is not intended to represent
the only embodiments
contemplated by the inventors. The detailed description includes specific
details for the purpose of
providing a comprehensive understanding of the present disclosure. However, it
will be apparent to those
skilled in the art that the present processes may be practiced using
substitutions.
Definitions
As used throughout this disclosure, the following terms have the meanings set
out below:
"Asphaltenes" are complex structured hydrocarbons found within bitum6n and
conventional heavy oils
consisting primarily of carbon, hydrogen, nitrogen, oxygen, and sulfur, as
well as trace amounts of
vanadium and nickel, with their boiling range above 950 F. The Carbon to
Hydrogen ratio is approximately
1:1.2, and are defined operationally as the n-pentane or n-heptane insoluble
component of a carbonaceous
material such as crude oil, bitumen, or coal.
"Naphtha" is a portion of bitumen (and crude oil) that consists of
hydrocarbons having carbon numbers in
the range of C5-C12, with a boiling point typically below 350 F. API's for
this fraction of the bitumen are
considered to be above 65.
"Distillate" is a portion of the bitumen and crude that consists of
hydrocarbons having carbon numbers in
the range of Cio to C18 with a boiling point typically between 350 F and 500
F. API's for this fraction of the
bitumen are considered to be between 35 and 65.
"Gasoils" are a portion of the bitumen and crude that consist of hydrocarbons
having carbon numbers in
the range of C15 to C30 with a boiling point typically between 500 F and 950
F. API's for this fraction of the
bitumen are considered to be between 10 and 35. Gasoils can be further
categorized as atmospheric (270-
650 F boiling range), light vacuum (752-850 F) and heavy vacuum (850-975 F).
The atmospheric gas oil is
typically produced in a refinery or upgrader through atmospheric distillation.
The light and heavy vacuum
gasoils are typically produced through vacuum distillation.
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CA 02848789 2014-04-14
"Bitumen bottoms" are a portion of the crude that consists of the heaviest
hydrocarbons having carbon
numbers typically above C28 with a boiling point typically above 950 F. This
refers to the portion of the
bitumen remaining once the gasoil fractions have been removed. API's for this
fraction of the bitumen are
considered to be typically below 10.
The term "atmospheric" comes from the technique used to isolate this
hydrocarbon from the main stream.
"Light virgin atmospheric gas oil" boils in the lower range of the atmospheric
gasoil boiling range, hence the
light descriptor. This is a 270 -650 F boiling range material.
The term "vacuum" comes from the technique (Vacuum tower) used to isolate this
hydrocarbon from the
main stream. "Virgin heavy vacuum gasoil" can also be called heavy virgin
gasoil. It boils in the upper range
of the vacuum gasoil boiling range, hence the heavy descriptor. This is a
material boiling between 850-975
'F. "Light virgin vacuum gasoil" boils in the lower range of the vacuum gasoil
boiling range, hence the light
descriptor. This is a 752-850 F boiling range material.
"Virgin" (or "straight run") in refining refers to the crude or bitumen
molecules that have not been
thermally or catalytically converted. These molecules have simply been
separated (e.g. via distillation or
solvent extraction) from the bulk hydrocarbon stream for use in the product
blend.
"Diluent" is a light hydrocarbon, typically in the naphtha boiling range (API
above 65, viscosity below 1 cSt
at 40 C). It is used as a blending component to reduce the viscosity of
heavier hydrocarbons.
"Pipeline specification" usually means that the flowing material has minimal
solids (e.g. <800wppm), is less
than or equal to 0.5vol% of Basic Sediment and Water (BS&W) has a viscosity of
less than or equal to 350
cSt at ambient conditions, and has no detectable olefins in the product
blends.
"Substantially water free" means that there is less than about 1.5 percentage
(by volume) in the stream or
mixture in question.
The methods relate to combining hydrocarbon streams produced at various stages
and by various means in
a hydrocracking process to produce a pipeline suitable product. As will be
described below, using the
processes of this invention, a specific, selective, and small portion of the
bitumen (e.g. heavy vacuum gas
oils) is catalytically treated to generate lighter hydrocarbons in the
distillate and naphtha boiling range.
CA 02848789 2014-04-14
= These lighter hydrocarbons are blended with the remaining virgin bitumen
to meet pipeline specifications.
As an added feature of some of the processes described herein, the product
distribution can be tailored.
For example, this can be accomplished by: a) adjusting the feed to the fixed
bed hydrocracker (e.g. adding
heavier heavy vacuum gas oil (HVG0); b) by adjusting operation of the vacuum;
and/or c) by adding light
vacuum gas oil (LVGO) into the base HVGO feed. By adjusting in this way, the
hydrocracker output changes
to match the product distribution of other fungible heavy crudes such as Maya
and Alaska North Slope. This
in turn increases the marketability of this product.
Overall, the processes described in this disclosure retain a large portion of
the overall original bitumen as
pipelineable product with minimal asphaltene rejection. There is generally
over 100% of product yield
downstream of the distillation step (e.g. downstream of the diluent recovery
unit (DRU) shown in Figures 1
to 3). This is because the processes described herein allow for full use of
the virgin bitumen product
resulting from the distillation step. For the processes described herein,
there is no need to add external
diluent to the processed stream to meet pipeline specification for transport.
In the processes described herein, the heavy portion of the virgin bitumen
stream (vdu bottoms) is blended
with gas oils before being mixed with the lighter hydrocarbons (e.g. napthas).
The mixing of the heavy
portion of the virgin bitumen stream with the gas oil assists in preventing
precipitation of asphaltenes in
the heavy bitumen stream that would otherwise occur when mixing with lighter
components. The gasoils
act as a buffer and/or neutralizer and/or dilution agent to counter the effect
of the lighter hydrocarbons.
Generally, when the naphtha:vdu bottoms ratio is below 1:1, precipitation will
be minimized. Alternatively,
when the naphtha to (vdu bottoms + gasoils) is below 1:1, precipitation will
be minimized. The presence of
gasoils serves to allow more naphtha to be added without precipitation issues.
A person skilled in the art would appreciate that the source of bitumen for
the process described above
could be derived from a mining operation. Typical mining operations used to
extract Canadian bitumen
mine the oil sands deposit from depths less than about 150 feet. Other sources
of bitumen are possible.
Generally, the bitumen found to be effectively treated in the process of the
invention is Canadian oil sands
bitumen. Once the bitumen is mined, the bitumen is generally treated in a hot
water bitumen extraction
unit. It is this bitumen-rich stream that is the feedstock of the process
described above. The bitumen-rich
stream is subject to a froth treatment process (step (a) above). Froth
treatment processes are generally
known in the art, and could be conducted in a froth treatment unit (high
temperature C5-C6 paraffinic or
lower temperature napthlenic).
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A person skilled in the art would appreciate that various equipment could be
used to carry out the steps
enumerated in the processes described herein. For example, a vacuum
distillation and diluent columns may
be used for distilling/separating steps.
The process will now be described with reference to the specific embodiments
illustrated in Figures 1 to 4.
Figure 1 is a process flow diagram depicting a process 100 for forming a
hydrocarbon pipelineable product
95 from an oil sand hydrocarbon feedstock 5. A mine operation 10 is required
to dig the oil sands out from
the deposit of clay, rock and sand. The solid oil sand, clay, rock and sand
mixture 15 is transported from the
mine to extraction unit 20. In extraction unit 20, hot water is added to
separate the oil sands from the clay,
rock and sand to produce a flowable liquid stream 25. The rock, clay, sand,
and residual bitumen/water is
sent back to the mine as stream 27.
Stream 25 is fed to a froth treatment unit 30, where a light hydrocarbon
solvent, such as naphtha boiling
range hydrocarbons, is added to separate water from the bitumen. Stream 37,
along with residual water
from the extraction process, is returned to the mine 10 via tailings pond.
Stream 35, consisting of bitumen
and solvent, is then sent to separation unit 40. In separation unit 40,
distillation, extraction, stripping or
other separation methods may occur. Stream 43 is solvent which is returned to
froth treatment unit 30.
From separation 40, multiple intermediate streams may be produced depending on
processing objectives.
Stream 41 can be a combination of naphtha and distillate boiling range
materials for use directly as native
diluent in the product blend 1. Stream 45 can be a virgin atmospheric gas oil
(VAGO) which meets pipeline
specification and can be sent directly to product blending 1: Alternatively, a
combination of atmospheric
and light vacuum gasoil (LVGO) can be produced and sent directly for product
blending.
Stream 49 may be heavy vacuum gas oil (HVGO) or a combination of virgin light
vacuum gasoil and heavy
vacuum gas oils. A portion of stream 49 is sent to conversion unit 60 and the
remainder is sent directly to
product blending 1. Stream 47 has the remaining heavy bitumen (bitumen
bottoms) and can be sent for
further processing. A portion of stream 47 is available for feed to the
conversion unit 60 and the remainder
sent for product blending 1. Conversion unit 60, whether thermal or catalytic,
produces a suite of lighter
hydrocarbons (such as naphtha, distillate and light vacuum gas oil boiling
range components), shown as
stream 65. Stream 65 is used directly for product blending 1. Stream 69,
arising from conversion unit 60,
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can either be a solid by-product (e.g. coke) or a heavy slurry for
gasification. Alternatively, stream 69 may
be used in the product blend, depending on conversion technology used.
Conversion unit 60 is meant to
represent a generic conversion unit and may be a coking apparatus or a
catalytic converter, for example.
Coking is a thermal process, and generates coke which can't be used in the
product blend while the
catalytic conversion type (hydrocracking) has the potential to produce all of
the products that can be used
in the product blend.
Stream 63 is sent to dehexanizer unit 70. In dehexanizer unit 70, make-up
solvent is produced as stream 73
for use in froth treatment unit 30. The remaining material, stream 75, is sent
to product blending.
As a person skilled in the art would appreciate, dehexanizer unit 70 is
optional. Also, there may be various
solvent recycling steps incorporated in the process. Product blending 1 is a
mixture of streams 41, 45, 49,
47, 65 and 75. The result is a pipeline suitable product 95.
Figure 2 is a process flow diagram depicting a process 200 for forming a
hydrocarbon pipelineable product
295 from oil sand-based solid hydrocarbon feedstock 5. The feedstock 5 is
derived from mine operation 10.
Mine operation 10 is required to dig the oil sands out from the deposit of
clay, rock and sand. The solid oil
sand, clay, rock and sand mixture 15 is transported from mine 10 to extraction
unit 20. In extraction unit
20, hot water is added to separate the oil sands from the clay, rock and sand
and produce a flowable liquid
stream 25. The rock, clay, sand, and residual bitumen/water is sent back to
the mine as stream 27.
Stream 25 is fed to paraffinic froth treatment unit 230 where a Cs, or C6
solvent or a mixture of the two is
added to separate the water from the bitumen in stream 25. Stream 237 is
returned to mine 10 via tailings
pond(s). Stream 237 includes residual water from the extraction process,
nearly all the entrained solids and
a large portion of the asphaltenes from the bitumen feedstock 5.
Stream 235, consisting of bitumen and paraffinic solvent, is sent to diluent
recovery unit (DRU) 240. DRU
240 returns the paraffinic solvent in stream 243 and produces two streams: 1)
stream 245 is virgin
atmospheric gasoil (VAGO) which is sent directly to product blending 2; and 2)
stream 247, containing the
remaining heavy bitumen, is sent for further processing. Stream 243 contains
solvent which is recycled back
to paraffinic froth treatment (230).
Stream 247 is sent to a vacuum distillation unit 250. In vacuum distillation
unit 250, virgin vacuum gasoils
(VVGO) are separated into a heavy vacuum gas oil stream 259 and a light vacuum
gas oil stream 251, with a
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residual bitumen bottoms stream 257. Stream 253 is the portion of the heavy
vacuum gas oil used as feed
to the hydrocracker 260. Stream 251 goes to product blend 2.
A vacuum column 250 (such as a vacuum distillation unit 250) is used to
extract more of the gasoils from
the bottoms 247 without requiring a higher temperature than the DRU (240). The
use of high temperature
would create unwanted coke and light gases. Some of stream 259 may be sent
directly to product blend 2
and/or a portion or all of stream 259 is used as feed to fixed bed
hydrocracker 260 to generate lighter
hydrocarbons for the product blend. If more HVGO material is needed, the
vacuum unit operation may be
adjusted to allow some LVGO into stream 259. It is expected that fixed bed
hydrocracker 260 will operate in
approximate ranges of 750-820 F, 800-1750 psi of hydrogen partial pressure and
liquid hourly space
velocities (LHSV) of 0.5-3Ø
A fixed bed hydrocracker is a simpler and more robust hydroprocessing unit
then an ebullated bed
hydrocracker. Ebullated bed hydrocrackers run up to 2,700 psi of hydrogen
partial pressure for Athabasca
bitumen. Fixed bed hydrocracker 260 produces a suite of lighter hydrocarbons
primarily including the
stream 265 (consisting of naphtha, distillate and light vacuum gas oil boiling
range components) for product
blending. In addition, stream 269 leaves unit 260 as unconverted heavy vacuum
gas oil from the feed
stream 259.
Stream 263 sent to dehexanizer unit 270 where paraffinic solvent is produced
as stream 273 for use as
make-up in the paraffinic froth treatment unit 230. The remaining material,
stream 275 is sent to product
blending to generate stream 295.
Figure 3 shows process 300, an alternate embodiment of process 200 shown in
Figure 2. In this
arrangement, a solvent deasphalting unit (SDA) 380 is added subsequent to the
vacuum distillation unit
250. If more gasoil is required than what the vacuum unit can typically
provide in meeting pipeline
specification the SDA serves to provide a cleaner (e.g. less metals) and
heavier feedstock to the
hydrocracker (260) to ensure the reliability of the hydrocracker.
As a person skilled in the art would appreciate, the hydrocracker is fed
gasoils and the vacuum column
generates a side product that will not have appreciable asphaltenes in the
gasoil stream. The SDA extracts
more gasoils out of the bitumen in the event a larger hydrocracker is needed.
These gasoils are more
difficult to separate cleanly from the bitumen in vacuum distillation. To
resolve this, the SDA 380 is used.
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The remaining products from the SDA 380, streams 385 and 387 are still
primarily sent to product blending,
thus maintaining a high product yield. Stream 385 is termed deasphalted oil,
the lighter portion of the feed
to the SDA. Stream 387 is an asphaltene-rich heavier stream, typically called
pitch. Stream 383 is a portion
of Stream 385 that provides an additional feed source to the hydrocracker,
unit 260. Whatever material
from 385 that is not used as stream 383, will be sent to product blending. In
the event the blended product
does not meet pipeline specification, a portion of the pitch in stream 387 can
be diverted to another
disposition, labeled stream 381. A disposition can be a thermal cracker, but
ideally there is normally no
flow in stream 381 so the overall yield of the process is maximized. Ideally,
the operation of the SDA 380
should not extract too many resins into the DAC) stream 385 so that the
asphaltenes in stream 387 do not
prematurely precipitate when re-blended with the lighter virgin streams
previously separated.
Both processes 200 and 300 provide a crude feedstock that meets pipeline
specifications and which is
suitable for high conversion refiners. Streams 295 and 395 both have low
proportions of diluent/naphtha
(<20 vol %), with substantial VG0 range material (>20% of crude). For high
conversion refiners (>1.4:1
conversion to coking), the distillation quality of the crude produced in
streams 295 and 395 will improve
utilization of the highest profit-generating units while filling out the
remaining units.
Figure 4 is a process flow diagram depicting a process 400 for forming a
hydrocarbon pipelineable product
495 from oil sand-based solid hydrocarbon feedstock 5. A mine operation, 10 is
required to dig the oil
sands out from the deposit of clay, rock and sand. The solid oil sand, clay,
rock and sand mixture 15 is
transported from the mine to the extraction unit 20. In extraction unit 20,
hot water is added to separate
the oil sands from the clay, rock and sand and make it into a flowable liquid
stream 25. The rock, clay, sand,
and residual bitumen/water is sent back to the mine as stream 27. Stream 25 is
fed to the naphthenic froth
treatment unit 430, where a hydrocarbon with an approximate ideal boiling
range of 150 F ¨ 235 F
(naphtha boiling range) is added to the bitumen/water mixture to separate the
water from the bitumen.
Stream 437 is returned to the mine 10 via tailings pond(s) with residual water
from the extraction process.
Stream 435 takes the bitumen and naphtha-based solvent to the diluent recovery
unit (DRU) 440. The DRU
returns the naphtha-based solvent in stream 443 and produces two streams: 1)
stream 445 is virgin
atmospheric gasoil sent direct to product blending; and 2) stream 447,
containing the remaining heavy
bitumen, is sent for further processing to a solvent deasphalting unit (SDA)
450. Two streams are generated
from SDA 450. Stream 457 contains the lighter portion of the feed stream,
noted as deasphalted oil (DAO)
CA 02848789 2014-04-14
and is sent to product blending. The second stream 455, containing
concentrated asphaltenes and solids, is
sent to coking unit 360.
Coking unit 360 thermally cracks the heavy asphaltene-based feed stream into
lighter hydrocarbons such as
naphtha, distillate and gasoil range liquid hydrocarbons for use in the final
product blend to meet viscosity
pipeline specification. These hydrocarbons are collected as stream 465 and
sent to a hydrotreating unit
470. Byproducts of the coking unit include coke, unwanted solids, metals and
"burned" heavy
hydrocarbons shown as stream 469 and light "non-condensable" hydrocarbons 461,
which are directed to a
fuel gas system.
Stream 469 could be further treated in a metals recovery unit to extract
valuable material such as titanium
and vanadium. A mild hydrotreating operation with low hydrogen consumption
(<750 scf/bbl) is employed
on stream 465 to simply saturate any olefins generated in the coking unit to
meet pipeline specification
without removing sulfur and nitrogen species. The hydrotreated product stream
475 is shared between
streams 473 and stream 475. Stream 475 is added to the product blend to create
the final product stream
495. Stream 473 can be used as solvent make-up for the froth treatment unit
430 and/or the SDA unit 450
depending on the specifications for these units. Of note, stream 495 has low
metals content and %CCR (e.g.
Conradson ConCarbon Residue ¨ a measure or coking precursors in the stream)
for a pipelineable crude
that meets viscosity specifications.
In the naphthenic froth treatment process shown in Figure 4, a downstream unit
is generally preferred to
handle the solids (clays, sands) that remain with the bitumen prior to
blending for pipeline use. In Figure 4,
the coking unit handles solids, and also serves to generate lighter
hydrocarbons in the distillate and
naphtha boiling range. These hydrocarbons blend with the remaining virgin
bitumen to meet pipeline
specifications. Similar to the scheme shown in Figure 2, the product
distribution can be adjusted to match
the distribution of other fungible heavy crudes such as Maya and Alaska North
Slope. This increases the
marketability of this product. Overall, this process creates over 90% of
product yield downstream of the
diluent recovery unit.
Processes 200 and 300 were compared to a process similar to process 300, but
using a commercially
available ebullated bed reactor instead of a fixed bed reactor. The ebullated
bed reactor is based on
information in Hydrocarbon Processing's, Refining Processes 2011 Handbook
(Gulf Publishing Company)
where the ebullated bed reactor is a reactor with an expanded catalyst bed
(not fixed) maintained in
turbulence by liquid upflow to achieve expected operation. Intermittent
catalyst addition and withdrawal
are features that differentiate ebullated bed from a fixed bed hydrocracker.
The ebullated bed operates
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between 725-840 F, 1,000-2,700 psig hydrogen partial pressure, and LSHV of 0.1-
0.6. Table 1 provides the
feed stream used in the analysis. in Table 2, a summary of flow rates
(measured in kilos of standard barrels
per day (kBPSD) is shown when an ebullated hydrocracker is compared to a fixed
bed hydrocracker used for
unit 260.
As shown in Table 3, the yield for the ebullated bed process is 90% due to the
rejection of asphaltenes in
the SDA to gasification or fuel. Also, the ebullated bed approach requires a
complicated, tough to operate
hydrocracking unit to accomplish the necessary light hydrocarbon generation.
In processes 200 and 300,
the yields are approximately 105-106% post DRU since the bottoms pitch can be
used in the product blend.
In the upstream paraffinic froth unit, up to 66% of the asphaltenes or 12% of
the bitumen from the mine
will be returned to the mine. As a result, the bottoms of the product blend
have a reduced quantity of
asphaltenes and thus less light hydrocarbon is needed to meet the pipeline
viscosity specification. All of the
remaining bottoms can be used in the product blend increasing the overall
yield of the pipelineable
product. In addition, more of the barrel remains as product, thereby reducing
the emissions generated.
Also, the way the bitumen barrel is segregrated between units 230 and 260,
allows for a simpler, more
dependable hydroprocessing unit (fixed bed hydrocracker) to be used improving
the overall economics of
the operation.
Table 1- Feed Properties
Gravity, API (at 15 C) 8.5 ¨ 10.5
Sulfur, wt % "4.2
Nitrogen, wt % "0.32
Conradson Carbon Residue, wt % 9.7
Distillation, V %
18P-350 F 0
350-650 F 14.9 %
650-975 F 44.4 %
975 F 40.7 %
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Table 2 - Summary of Flowrates
, Flowrate, kBPSD .
Ebullated case 200,300,400
Bitumen to Crude Still 100 100
AGO and SCO Blending 20.8 20.8
Total Atmospheric residue 79.2 79.2
Atmospheric residue bypassed 23.7 0
Atmospheric residue to VDU 55.5 79.2
VG0 to SCO blending 16.5 , 10.4
Vacuum Residue to SDA 39 0-12.4
Vacuum Residue to Blend 0 0-28.4
HVGO to Fixed Bed HC 0 24-28
SDA Asphaltenes to Glasification or fuel 12 0
s
SDA asphaltenes to blend 0 0-6.4
Hydroprocessing Products 29.2 30-41
Total SCO or pipelineable product 90.8 90-106.8
Hydrogen Required, MMSCFD 54.4 50-76.6
-
Syngas Export from Gasifier, MM Btu/day 48,500 0
Table 3 - Product yields (100,000 BPSD Feed to DRU)
units Ebullated Process 200 Process 300 Process 400
Case Figure 2 Figure 3 Figure 4
Total Product BPD 90837.00 106830.00 105300.00
89466.67
Yield on Crude % 90.80 106.80 105.30 89.47
Gravity oAPI 20.40 21.70 19.80 21.20
Viscosity (41 7oC cSt <350 <350 <350 <350
Sulfur wt% 2.50 3.20 3.50 3.00
Nitrogen wt% 0.24 0.27 0.29 0.21
Conradson Carbon Residue wt% 5.30 7.00 7.30 1.98
Nickel+ Vanadium wppm 99.00 170.00 177.00 30.10
Distillation
IBP-3500F V% 7.80 5.50 4.50 7.70
350-6500F V% 30.60 41.80 36.70 19.60
650-975oF V% 40.90 20.10 20.10 47.80
975oF V% 20.70 32.60 38.70 24.90
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It is to be understood that other aspects of the present disclosure will
become readily apparent to those
skilled in the art from the following detailed description, wherein various
embodiments are shown and
described by way of illustration. As will be realized, there are many other
and different embodiments, and
the details provided herein are capable of modification in various other
respects, all without departing from
the spirit and scope of the present disclosure. Accordingly, the drawings and
detailed description are to be
regarded as illustrative in nature and not as restrictive.
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