Note: Descriptions are shown in the official language in which they were submitted.
CA 02819073 2013-06-13
r.R.Q.EmsFO (12:RA,k1 S MEARQ1115.
:BACKGROUND
Refinery of sweet crude resources requites less ca.pital input and less cost
expenditure than the processing
than 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 ATI 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 upgmders
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 ehullated bed
hydrocracking and fxed bed
hydro-treating to maximize the conversion of the heavy components in the
feedstock to lighter, lower sulfur
liquid products and gas.
Various processes have been used to convert and/or condition oil sands bitumen
into pipeline transportable
and refinery acceptable crudc. Of note, thermal cracking, catalytic cracking,
solvent &asphalting and various
combinations thereof (for example, visbreakirig and solvent deasphalting) have
been proposed to convert
bitumen to hydrocarbon streams having characteristics suitable for pipeline
transport and use as a refinery
_
= 20 feedstock_ Some examples of these methodologies are
presentedbelow,
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
dea.sphalting the non-distilled portion of the visbroken oil in a two-stage
deasphalting process to produce
separate asphaltene, resin, and deasphatted oil fractions; mixing the
deasphaited oil ("DAC/7') with the
visbroken distillates; and recycling and combining resins from the &asphalting
step i,vith the initial
CA 02819073 2013-06-13
feedstock. While the '023 Patent provides a means for upgrading lighter
hydrocarbons (API gravity>15), the
Apt 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).
US. Patent No. 4,191,636 describes a process in which heavy oil is
continuously converted into asphaltenes
arid 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.
MIMARY
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.
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 of heavy hydrocarbon feeds,
such as Canadian bitumen. The present disclosure provides a low complexity,
low severity, yet reliable
operational procedure to separate and convert Canadian bitumen to produce a
pipeIineable product withour
the need for external diluent. The methods disclosed herein achieve this
result by performing 6 lower
2
CA 02819073 2013-06-13
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). hi this way, much of the virgin portion of the feed bitumen
can be used in the final product
blend.
According to one aspect, a process for converting heavy crude oils to a
lighter hydrocarbon 'crude is
disclosed. The heavy crude may be 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 =
i) a Eight hydrocarbon component (41) for direct product blending (l);
ii) a virgin atmospheric gas oil (45) fordirect product blending (l);
iii) a heavy vacuum gas oil or a combination of virgin light and heavy vacuum
gas oils (49); and
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 pipe-line specifications. Pipe-line
specifications typically include
but are not limited to viscosity of less than or equal to 300 eSt at ambient
conditions, basic sediment and
water (BS&W) of less than or equal to 0.5vol% and no olefins measured in the
product.
3
CA 02819073 2013-06-13
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 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, optionallyõ 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 eSt).
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 refi.
nery feedstock. The process
comprises:
(a) treating a bitumen-rich stream. using a paraffinic froth treatment process
(230);
(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 (2.5e)
4
CA 02819073 2013-06-13
(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 stream (265) from the hydrocracker for direct product
blending (2);
(h) blending streams (245), (251), (259), (257) 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
1.0 skilled in the art would appreciate, step (d) may he 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, them 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 uait (450);
(e) removing a portion of the stream from the solvent deasphalting unit to
direct product blending (495);
CA 02819073 2013-06-13
(f) removing a portion of the strtam 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
S 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 contributts 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 he incorporated at
various other points in the processes described.
PRIV DFSCREPTIQN QE_TBIE 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. I is an illustrative process diagram for fonning 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.
RENALEPIASE
6
CA 02819073 2013-06-13
The detailed description set forth below, in conjunction with Figures 1 to 4,
is intended as a deseription of
various embodiments of the present disclosure and is not intended to represent
the only embodirtients
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:
"Naphtha" is a portion of bitumen (and crude oil) that consists of
hydrocarbons having carbon numbers in the
range of CrC12, 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 consist of
hydrocarbons having carbon numbers in the
range of C1,0 to Clg 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 JO and 35. Gasoils can be further
categorized as atmospheric (500-
700 F boiling range), light vacuum (700-800 F) and heavy vacuum (800-950 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.
"Bitumen bottoms'' are a portion of the crude that consists of the heaviest
hydrocarbcms having carbon
numbers typically above C25 with a boiling point typically above 950 P. API's
for this fraction of the
= = bitumen are considered to be typically below I O.
7 =
CA 02819073 2013-06-13
"Virgin" (Or "straight run") in refining refers to the crude or bitumen
molecules that have not beeu thermally
or catalytically convemd. 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). lt is used as a blending component to reduce the viscosity of
heavier hydroearbons.
"Pipeline specification" usually means that the flowing material has minimal
solids (e.g. -4:8001,vppro), is less
than or equal to 0.5vol ,4 of Basic Sediment and Water (BS&W) has a viscosity
of less than or equal to 350
eSt 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 strearn 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 snitable 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. These
lighter hydrocarbons are blended with the remaining virgin bitumen to meet
pipeline specific.ations. 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 (1-EVG0); b) by adjusting operation of the
vacuum; and/or c) by adding light
vacuum gas oil (INGO) into the base 1-1VG0 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 asphaftene rejection. There is generally
over 100% of product yield
downstream of the distillation step (e.g- downstream of the diluent recovery
unit (MU) shown in Figures 1
to 3). This is because the processes described herein allow for full use of
the virgin bitumen product resulting
=
8
CA 02819073 2013-06-13
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
strearn (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 as oil assists in preventing
precipitation of asphaltenes ìn 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 bottorns ratiO is below 1:1, precipitation will be
minimized. Alternatively, when the
naphtha to (vdu bottoms + wails) 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 of greater than about 150 feet. Other sources of
bitumen are possible.
Generally, the bitumen found to be effective 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-C4
paraffinic OT lower temperature
napthlenic).
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, 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 diagrarn depicting a process 100 for forming a
hydrocarbon pipelineable product
95 from an oil sand hydrocarbon feedstock 5. A mine operation 30 is required
to dig the oil sands out from
= 9
CA 02819073 2013-06-13
the deposit of clay, rock and sand. The solid oil sand, clay, rock and and
mixture 15 is transported from the
mine to extractiOn unit 20. In extraction unit 2.0, 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 bitumee 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 I. Stream 45 can be a virgin atmospheric gas oil
(VAGO) which meets pipeline
specification and can be sent directly to product blending I. Alternatively, a
combination of atrnospheric and
Iight vacuum mei] (LVGO) can be produced and sent directly for product
blending,
Stream 49 may be heavy vacuum gas oil (1-1V00) or a combination of virgin
light vacuum asoil 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 I. 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 dimetly for product blending 1. Stream 69,
arising from conversion unit 60, ean
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.
23 Coking is a thermal process, and generates coke which can't be used in
the product blend while the catalytic
CA 02819073 2013-06-13
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 l 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 pipeline.able 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 frorri 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 arid sand and
produce a flowable liquid stream
25. The rock, clay, sand, and residual bitumen/wiener is sent back to the mine
as stream 27.
Stream 25 is fed to paraffinic froth treatment unit 230 where a C5, or C6
solvent or a mixillre of the two is
added to separate the water from the bitumen in strearn 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 frorn the bitumen feedstock 5.
Stream 235, consisting of bitumen and paraffinic solvent, is sent to diluent
recovery unit (DRU) 240. DRILT
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 distilialjon
unit 250, virgin vacuum gasoils
(VVG0) are separated into a heavy VaCULIM gas oil stream 259 and a. light
vacuum gps oil stream 251, with a
CA 02819073 2013-06-13
residual bitumen bottoms stream 257. Strca.m 253 is the portion of the heavy
vaeutim 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
andior 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 INGO material is needed, the
vacuum unit operation may be
adjusted to al low some INGO 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 sitnpler and more robust hydroprocessing emit
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_
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 etnbodiment of process 200 shown in
Figure 2, In this arrangement,
a solvent deasphalting unit (SDA) 380 is added subsequent to the vaenum
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
12
CA 02819073 2013-06-13
more gasoils out of the bitumen in the event a larger hydrocracker is needed.
Thes asoils are more difficult
to separate cleanly from the bitumen in vacuum distillation. To resolve this,
the SDA 380 is used. The
remaining products from the SDA 380 are still sent tO product blending, thus
maintaining a high product
yield. ideally, the operation of the SDA 3N should not extract too many resins
into the DA,0 stream 385 so
that the asphalteries do not prematurely precipitate when re-blended with the
lighter virgin streams
preNriously 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
(<20vo1%), 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
utilintion 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 8o1id 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 23. The
rock, clay, sand, and residual
bitumen/water is sent back to the minc as siream 27. Stream 25 is fed to the
naphthenic froth treatment unit
430, where a hydrocarbon with an approximate ideal boiling range of I50 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 t vo 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 deasphaiting unit (SDA)
450. Two streams are generated
from SDA 450. Stream 457 contairis the lighter portion of the feed stream,
noted as deasphalted oil (DO)
13
CA 02819073 2013-06-13
and is sent to product blending. The second strewn 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 eould 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 species and cracking molecules. The hydrotreated
product stream 475 is added to
the product blend to create the final product stream 493. Of note, stream 495
has low metals content and
eieCCR (e.g. Conradson ConCarbon Residue ¨ a measure or coking precursors in
the stream) for a
pipet ineable crude that meets viscosity specifications.
In the naphthenic froth treatment process shown in Figure 4, a downstream unit
is generally required 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 hydmcarbons blend with the remaining virgin bitumen to
meet pipeline specifications.
Similar to the scheme shown in Figure 2, the product distribution can be
adjusted tomatch 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 ebtillated
bed motor is based on
information in Hydrocarbon Processing's, Refining Processes 2011 Handbook
(Gulf Publishing Company)
where the ebuilated bed reactor is a reactor with an expanded catalyst bed
(not fixed) maintained in
14
CA 02819073 2013-06-13
turbulence by liquid upflow to achieve expected operation. Intermittent
cata.lyst addition and withdrawal are
features that differentiate ebullated bed from a fixed bed hydrocracker. The
ebullated bed operates between
725-340 F, l ,000-2,700 psig hydrogen partial pressure, and Lurv of 0.1-0.6,
Table 1 provides tbe feed
steam 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
tEjOCtioll 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
LO yielc-ls 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 has a
reduced quantity of asphaltenes and
thus less light hydrocarbon is needed to meet the pipeline viscosity
specification. All of the remaining
bottoms can used in the product blend increasing the overall yield of the
pipelineable product. In addition,
more of the barrel remains as product, thereby reducin 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
Pat App Feed
Stream numbers
Gravity, o API (atiSoC) 8.5-10.5
Sulfur, wt% -4,2
Nitrogen, wt% -0,32
. Conradeon Carbon Residue, wt% ,9.7
Distillation, y%
IBP-350'oF 0
36600F 14.9
650-9750F 44.4
-975oF 40.7
15
CA 02819073 2013-06-13
=
Table 2 - Summary of Flowrates
- Flowrate, kBPSID
Ebullated CaSe 200,300,400
Bitumen to Crude Still 100 100
AGO to SCO Blending 20.8 20.8
Total Atmospheric residue 79.2 = 79.2
Atmospheric residue bypaSsed23.7 0
= .
Atmospheric residue to VDU 55.5 = 79.2
VG0 to SCO blending 16.6 10.4
Vacuum Residue to SDA 39 12.4
Vauuum Residue to Blend 0 28.4
=
EiVG0 to Fixed Red He 0 28
SDA.Asphaltenes to Gasification or fuel 12 0
SDA aSphaltertes to blend 0 6.4 .
Hydroprocessing Products = 29.2 41
Total SCO or pipelineable product 90.8 = 106.8
Hydrogen Required, MMSCFD 54.4 76.6
synTas Export from Gasifier, .MM Btutday 48,560 . 0
. .
Tabl.e 3 - Product yields (1.00,000 BPSD Feed to DRU)
. _
. ..,
units Ebul late d Process 200 Process 300 Process 400
Case,, Figure 2 Figure 3 Figure 4
..
Total Product BPD = 00837,00 108830.00 105300.00
:89468,67
Yield on Crude = % \ -90.80 - 106.80 105.30 =' 89.47
_ . .
Grayly ' API 20,40 21,70 19.80 21.20
Viscosity R 7oC ' u-St - <350 <350 <350 <350
Sulfur . yt% 2.50 3.20 3,50 = 3.00
Nitrovo wt% 0.24 . 0.27 0.29 0.21 '
Conradsort Carbon Ro3Iclue wt% 5.30 7,00 - 7,30
1.98 ,
Nickel+ Vanadium wPPm 99.00 170.00 177.00 30.10
-
Distillation. '
, .
IDP-360oF V% 7.80 5.50 4,50 7.70
350-680oP ' v% 40.80 - 41.80 36,70 19.80 =
850-975oF___. V% = 40.90 20.10 20,10 47.80
975oF V%
" 20,70 , 32.60 38.70 24.90
=
=
=
16
