Canadian Patents Database / Patent 2740481 Summary

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(12) Patent: (11) CA 2740481
(54) English Title: INTEGRATED PROCESSES FOR RECOVERY OF HYDROCARBON FROM OIL SANDS
(54) French Title: PROCEDES INTEGRES POUR LA RECUPERATION DES HYDROCARBURES DANS LES SABLES BITUMINEUX
(51) International Patent Classification (IPC):
  • C10G 1/04 (2006.01)
(72) Inventors :
  • ADEYINKA, OLUSOLA B. (Canada)
  • MYERS, RONALD D. (Canada)
  • GHOSH, MAINAK (Canada)
(73) Owners :
  • IMPERIAL OIL RESOURCES LIMITED (Canada)
(71) Applicants :
  • IMPERIAL OIL RESOURCES LIMITED (Canada)
(74) Agent: BORDEN LADNER GERVAIS LLP
(45) Issued: 2013-02-12
(22) Filed Date: 2011-05-17
(41) Open to Public Inspection: 2011-11-21
Examination requested: 2011-05-17
(30) Availability of licence: N/A
(30) Language of filing: English

(30) Application Priority Data:
Application No. Country/Territory Date
2,704,927 Canada 2010-05-21

English Abstract

Processes are described for extracting hydrocarbon from a mineable deposit, such as bitumen from oil sands. The integration of solvent-based extraction processes with aqueous extraction processes is described. In one embodiment, water is removed from an aqueous bituminous feed that is then directed into a solvent-based extraction process. In another embodiment, a stream produced through solvent extraction is directed into an water-based extraction process. In the solvent-based extraction processes, agglomeration of fines may be employed to simplify subsequent solid-liquid separation. The process permits recovery of hydrocarbon that has conventionally may have been too difficult to recover from oil sands processing, and thus has previously been lost. Advantageously, a fungible product can be formed more efficiently according to certain integrated processes described herein.


French Abstract

Des procédés d'extraction d'un hydrocarbure à partir d'un gisement minéral, tel que du bitume à partir de sables bitumineux. L'intégration de procédés d'extraction à base de solvant avec des procédés d'extraction aqueux est décrite. Dans un mode de réalisation, de l'eau est éliminée d'une alimentation bitumineuse aqueuse qui est ensuite dirigée vers un procédé d'extraction à base de solvant. Dans un autre mode de réalisation, le flux issu d'un procédé d'extraction par solvant est dirigé vers un procédé d'extraction à base aqueuse. Dans les procédés d'extraction à base de solvant, on peut agglomérer les fines particules pour simplifier la séparation solide-liquide ultérieure. Le procédé permet la récupération d'un hydrocarbure auparavant perdu parce que trop difficile à récupérer selon les procédés classiques de traitement de sables bitumineux. Comme autre avantage de l'invention, un produit fongible peut être formé plus efficacement conformément à certains procédés intégrés décrits ici.


Note: Claims are shown in the official language in which they were submitted.


CLAIMS:
1. A process for pre-treating an aqueous hydrocarbon-containing feed for a
downstream solvent-based extraction process for bitumen recovery, said aqueous

hydrocarbon-containing feed comprising from 50 wt% to 95 wt% water, from 0.1
wt% to
wt% bitumen, and from 5 wt% to 50 wt% solids, wherein said solids comprise
fines,
the process comprising:
removing water from the aqueous hydrocarbon-containing feed to produce an
effluent comprising 40 wt% water or less; and
providing the effluent to the downstream solvent-based extraction process for
bitumen recovery, wherein said downstream solvent-based extraction process
comprises
fines agglomeration.


2. The process according to claim 1, wherein removing water from the aqueous
hydrocarbon-containing feed comprises:
flowing the aqueous hydrocarbon-containing feed into a primary water
separation
system to remove water from the aqueous hydrocarbon-containing feed, producing
a
reduced-water stream of from 30 wt% to 60 wt% solids, and recycled water; and
removing water from the reduced-water stream using a secondary water
separation system to produce effluent comprising 40 wt% water or less.


3. The process of claim 2, wherein the primary water separation system
comprises a
clarifier, a settler, a thickener or a cyclone.


4. The process of claim 3, wherein a flocculant is added to the aqueous
hydrocarbon-containing feed in the clarifier.


5. The process of claim 1, wherein the aqueous hydrocarbon-containing feed is
produced from a water-based extraction process wherein a flocculants or
coagulant is
used to induce aggregation of fines and hydrocarbons within the water-based
extraction
process.


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6. The process of claim 3, wherein solvent or a flocculant is mixed with the
aqueous
hydrocarbon-containing feed prior to water separation in the clarifier.


7. The process of claim 6, wherein solvent is mixed with the aqueous
hydrocarbon-
containing feed, said solvent having bitumen entrained therein for a
solvent:bitumen ratio
of less than about 2:1.


8. The process of claim 6 or claim 7, wherein the solvent mixed with the
aqueous
hydrocarbon-containing feed comprises a low boiling point cycloalkane solvent.


9. The process of any one of claims 2 to 4 or 6 to 8, wherein the secondary
water
separation system comprises a centrifuge with filtering capacity, a shale
shaker, a
vacuum belt filter, or one or more clarifiers.


10. The process of any one of claims 1 to 9, wherein the aqueous hydrocarbon-
containing feed comprises effluent of a froth separation unit.


11. The process of any one of claims 1 to 9, wherein the aqueous hydrocarbon-
containing feed comprises tailings from a tailings solvent recovery unit.


12. The process of any one of claims 1 to 11, additionally comprising a
process for
recovery of bitumen, wherein the downstream solvent-based extraction process
comprises:
combining a first solvent with the effluent and a bituminous feed from oil
sands to
form an initial slurry; separating the initial slurry into a fine solids
stream and a coarse
solids stream; agglomerating solids from the fine solids stream to form an
agglomerated
slurry comprising agglomerates and a low solids bitumen extract; separating
the low
solids bitumen extract from the agglomerated slurry; mixing a second solvent
with the low
solids bitumen extract to form a solvent-bitumen low solids mixture, the
second solvent
having a similar or lower boiling point than the first solvent; subjecting the
mixture to
gravity separation to produce a high grade bitumen extract and a low grade
bitumen
extract; and recovering the first and second solvent from the high grade
bitumen extract,
leaving a high grade bitumen product.


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13. The process of any one of claims 1 to 11, additionally comprising a
process for
recovery of bitumen, wherein the downstream solvent-based extraction process
comprises:
combining a first solvent with the effluent and a bituminous feed from oil
sands to
form an initial slurry; agglomerating solids from the initial slurry to form
an agglomerated
slurry comprising agglomerates and a low solids bitumen extract; separating
the low
solids bitumen extract from the agglomerated slurry; mixing a second solvent
with the low
solids bitumen extract to form a solvent-bitumen low solids mixture, the
second solvent
having a similar or lower boiling point than the first solvent, subjecting the
mixture to
gravity separation to produce a high grade bitumen extract and a low grade
bitumen
extract; and recovering the first and second solvent from the high grade
bitumen extract,
leaving a high grade bitumen product;
wherein the ratio of first solvent to bitumen in the initial slurry is
selected to avoid
precipitation of asphaltenes during agglomeration.


14. A system for pre-treating an aqueous hydrocarbon-containing feed for a
downstream solvent-based extraction process for bitumen recovery, said aqueous

hydrocarbon-containing feed comprising from 50 wt% to 95 wt% water, from 0.1
wt% to
wt% bitumen, and from 5 wt% to 50 wt% solids, wherein said solids comprise
fines,
the system comprising:
a dewatering unit for removing water from the aqueous hydrocarbon-containing
feed to produce an effluent comprising 40 wt% water or less; and
a conduit for providing the effluent to a downstream solvent-based extraction
process comprising fines agglomeration to recover bitumen.


15. The system of claim 14, wherein the dewatering unit comprises:
a primary water separation system to remove water from the aqueous
hydrocarbon-containing feed, producing a reduced-water stream; and
a secondary water separation system for receiving the reduced-water stream and

removing water therefrom to produce the effluent comprising 40 wt% water or
less.


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16. The system of claim 14 or claim 15, additionally comprising the following
components for recovery of bitumen in the downstream solvent-based extraction
process:
a slurry system wherein a bituminous feed is mixed with effluent from the de-
watering unit and a first solvent to form an initial slurry; a fine/coarse
solids separator in
fluid communication with the slurry system for receiving the initial slurry
and separating a
fine solids stream therefrom; an agglomerator for receiving the fine solids
stream from the
fine/coarse solids separator, for agglomerating solids and producing an
agglomerated
slurry; a primary solid-liquid separator for separating the agglomerated
slurry into
agglomerates and a low solids bitumen extract; a gravity separator for
receiving the low
solids bitumen extract and a second solvent; and
a primary solvent recovery unit for recovering the first solvent or the second

solvent in a high grade bitumen extract arising from the gravity separator and
for
separating bitumen therefrom.

17. The system of claim 14 or claim 15, additionally comprising the following
components for recovery of bitumen in the downstream solvent-based extraction
process:
a slurry system wherein a bituminous feed is mixed with a first solvent to
form
an initial slurry; an agglomerator for receiving the initial slurry, for
agglomerating solids
and producing an agglomerated slurry; a primary solid-liquid separator for
separating the
agglomerated slurry into agglomerates and a low solids bitumen extract; a
gravity
separator for receiving the low solids bitumen extract and a second solvent;
and a primary
solvent recovery unit for recovering the first solvent or the second solvent
in a high grade
bitumen extract arising from the gravity separator and for separating bitumen
therefrom;
wherein the conduit for providing the effluent to the downstream solvent-
based extraction process provides the effluent comprising 40 wt% water or less
to the
slurry system as the bituminous feed.

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Note: Descriptions are shown in the official language in which they were submitted.


CA 02740481 2011-05-17

INTEGRATED PROCESSES FOR RECOVERY OF
HYDROCARBON FROM OIL SANDS
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to Canadian Patent Application No.
2,704,927 filed
May 21, 2010.

FIELD
[0002] The technology described herein relates generally to recovering
hydrocarbon from
mineable deposits, such as bitumen from oil sands. Processes are described for
recovery of
hydrocarbon from oil sands which integrate solvent-based extraction technology
and water-based
bitumen extraction technology.

BACKGROUND
[0003] Processes for extracting hydrocarbon from oil sands require energy
intensive steps to
separate solids and water from hydrocarbon, to yield commercially valuable
products. Increasing
the efficiency of oil sands extraction in ways that reduce water utilization,
reduce energy
consumption, and utilize production streams or heat that may have otherwise
gone to waste, will
reduce the cost of production and provide environmental benefits. Such
efficiencies are needed to
improve upon existing processes.
[0004] In general, water-based extraction and solvent-based extraction are the
two
processes that have been used to extract bitumen from oil sands. In the case
of water-based
extraction, water is the dominant liquid in the process and the extraction
occurs by having water
displace the bitumen on the surface of the solids. In the case of solvent-
based extraction, the
solvent is the dominant liquid and the extraction of the bitumen occurs by
dissolving bitumen into the
solvent.
[0005] Water-based extraction processes have several advantages. Chief among
them is
that the process water is relatively inexpensive and environmentally benign.
Another important
advantage is that water-based extraction has been shown to produce a fungible
bitumen product
when paraffinic froth treatment is used to treat the bitumen froth. Solvent-
based extraction
processes also offer advantages. Solvent-based processes result in effective
recovery of bitumen
from streams containing large amounts of fine solids (or "fines"). Further,
the volume of the tailings
(or "tails") produced in solvent-based processes is less than the volume
produced in water-based
extraction. Additionally, the bitumen product produced by solvent-based
extraction has a reduced

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CA 02740481 2011-05-17

content of fines and water when compared with bitumen froth produced in the
primary separation of
a water-based extraction process.
[0006] Canadian Patent Application No. 2,068,895 to NRC, describes integration
of solvent
extraction spherical agglomeration (SESA) technology, as described in more
detail below, with the
Clark Hot Water Extraction (CHWE) process for improved bitumen recovery and
reduced sludge
volume. A high fines conditioning drum oversize stream is processed in the
SESA process while a
low fines stream is processed in the Clark hot water process.
[0007] There is a need to further develop processes and systems for
integrating water-
based extraction processes and streams with solvent-based extraction processes
and streams to
capture previously unrecognized synergies between the two processes.
[0008] Processing problems associated with recovery of water and bitumen from
aqueous
sources, such as from conventional water-based hydrocarbon or bitumen
extraction processes, are
largely due to the presence of fines in the streams. Recovery of bitumen from
bitumen-lean
streams, or intermediate streams formed in a water-based extraction process,
is environmentally
prudent and would increase the efficiency of the overall extraction process.
Conventional attempts
at de-watering streams from a water-based extraction process have typically
been undertaken only
after the majority of hydrocarbon, or bitumen, has been removed.
[0009] Aqueous hydrocarbon-containing streams from a water-based extraction
process
which may undergo additional water-based bitumen recovery or which may be
stored as waste
products include middling streams from a primary separation vessel, and
bitumen-lean streams from
secondary flotation tails or froth treatment, among others. Such streams have
a high water content,
but may also have a bitumen content exceeding 15 wt% on a dry solids basis,
which would be
desirable to recover.
[0010] Canadian Patent No. 1,024,330 to NRC describes a process in which high
fines
streams, such as the middlings from a primary separation vessel of a water-
based extraction
process or mature fine tailings from the water-based extraction tailings
ponds, may be directed to a
solvent extraction solids agglomeration (SESA) process as a source of the
bridging liquid.
[0011] Aqueous hydrocarbon-containing streams and, in particular, aqueous
bitumen-lean
streams from water-based extraction, contain a large proportion of water. For
example, 50% or
more water by weight may be found in such streams, which is higher than
desired for many solvent-
based extraction processes. Thus, there is a need for a process that can
permit incorporation of
such aqueous hydrocarbon-containing streams into a solvent-based extraction
process in order
recover residual bitumen within these streams.

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CA 02740481 2011-05-17

[0012] Approximately 10% of the bitumen extracted in conventional water-based
extraction
processes is lost in the tailings of paraffinic froth treatment (PFT).
Although a majority of these
hydrocarbons are asphaltenes, there is still sufficient value to be derived
from this fraction to support
recovery from paraffinic froth tailings to increase the overall volume of
bitumen produced.
Conventional water-based extraction processes offer limited solutions for
recovery of hydrocarbon
from this fraction, generally requiring one or more addition extraction stages
to recover residual
maltenes from froth treatment tailings.
[0013] Canadian Patent Application No. 2,662,346 describes the conditioning of
froth
treatment tailings (both paraffinic froth treatment and naphthenic froth
treatment) in order to
separate the hydrocarbons from the solid mineral material. After solids
removal, the hydrocarbon
rich stream from the conditioning process is then directed to a solvent-based
extraction process.
Separating the fines from the hydrocarbons is a challenge regardless of
whether it is undertaken
within a conditioning stage prior to solvent extraction or within the solvent-
based extraction process
itself.
[0014] There is a need to develop a solvent-based extraction process for
recovering
hydrocarbons from paraffinic froth treatment tails without dispersing the
fines into the hydrocarbon
extract.
[0015] In solvent-based extraction processes, the solvent may contain
dissolved (or
"entrained") bitumen prior to contacting the oil sands with the solvent. Such
a mixture of solvent and
bitumen may be referred to interchangeably herein as a "liquor" or "extraction
liquor". An exemplary
level of pre-dissolved bitumen can makeup as much as 50 wt% of the liquor.
Having a large amount
of pre-dissolved bitumen may offer advantages. For example, using solvent with
dissolved bitumen
may reduce the required inventory of solvent needed for the bitumen extraction
from oil sands.
Further, for certain solvents, pre-dissolved bitumen may increase the ability
of the liquor to dissolve
additional bitumen from oil sands. Furthermore, the pre-dissolved bitumen
reduces the vapor
pressure of the liquor, when compared with that of the solvent, which can
allow for higher operating
temperatures for the solvent-based extraction process.
[0016] In previously described solvent-based extraction processes, such as
those disclosed
in Canadian Patent No. 2,147,943; U.S. Patent No. 4,422,209; and U.S. Patent
No. 4,719,008, the
pre-dissolved bitumen results from recycling bitumen from the solid-liquid
separation stage to the oil
sands extraction stage. The recycling of the bitumen reduces the yield of the
solvent-based
extraction process.
[0017] The froth treatment processes for water-based extraction, such as
naphthenic froth
treatment and paraffinic froth treatment, involve mixing a water extracted
bitumen-rich stream with a
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CA 02740481 2011-05-17

solvent. However, the purpose of these steps within a water-based extraction
process is primarily to
remove residual water and solids from a bitumen-rich stream. Such froth
treatment processes are
conventionally conducted only within an overall water-based extraction
process.
[0018] There is a need to develop alternative methods for providing pre-
dissolved bitumen
within the solvent of a solvent-based extraction process while reducing the
amount of recycled
bitumen within the solvent-based extraction process.
[0019] Solvent extracted bitumen has a much lower solids and water content
than that of
bitumen froth produced in the water-based extraction process. However, the
residual amounts of
water and solids contained in solvent extracted bitumen may nevertheless
render the bitumen
unsuitable for marketing. A fungible bitumen product is bitumen with a solids
content of less than
300 ppm on a bitumen basis, measured as filterable solids. Further, a total
bitumen solids and
water (or "BS & W") content of less than 0.5% is acceptable for meeting
pipeline specifications.
Bitumen of such quality is termed "fungible" because it can be processed in
conventional refinery
processes, such as hydroprocessing, without dramatically fouling the refinery
equipment. Removing
contaminants from solvent extracted bitumen is difficult using conventional
separation methods such
as gravity settling, centrifugation or filtering.
[0020] Solvent deasphalting has previously been proposed for product cleaning
of solvent
extracted bitumen. Deasphalting technologies are described in U.S. Patent No.
4,572,777 issued
February 25, 1986 entitled: Recovery of a carbonaceous liquid with a low fines
content; and U.S.
Patent No. 4,888,108 issued December 19, 1989 entitled: Separation of Fines
Solids from
Petroleum Oils and the Like. The solvent deasphalting processes described in
these patents do not
result in the formation of a fungible product in a deasphalting step. The
processes described in
these patents are limited by the type of deasphalting solvent used and the
proper deasphalting
solvent to bitumen ratio required for optimal solids removal. The deasphalting
process described
were not specific and relied more on conventional deasphalting technologies,
such as those
commonly used in refineries to produce heavy crude oils to upgrade heavy
bottoms streams to
deasphalt oil. However, these conventional deasphalting technologies operate
at high temperatures
and pressures, and at a low feed rate, compared to what would be required for
a large scale
production facility.
[0021] Paraffinic froth treatment (PFT) units operate under much milder
conditions than
deasphalting units found currently in refineries. PFT processes have generally
been used only
within water-based extraction processes. U.S. Patent Application No.
12/340,515 of Sury et al.
(Publication No. US 2009/0200209) describes a process in which water is added
to a solvent and
bitumen froth mixture within a PFT process in order to enhance the
deasphalting process.

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CA 02740481 2011-05-17

[0022] U.S. Patent No. 4,634,520 and U.S. Patent No. 7,625,466 disclose
methods for
deasphalting a heavy oil and water emulsion. In U.S. Patent No. 4,634,520, the
asphaltene and
water flocs, after settling, are mixed with hot water in order to agglomerate
and recover asphaltenes.
In U.S. Patent No. 7,625,466, a heavy oil and water emulsion is described to
mix with a
deasphalting solvent and optionally with water before directing the mixture to
a settling vessel.
[0023] The following references describe processes in which asphaltene-water
interaction
enhances deasphalting of bitumen: Fuel Processing Technology, Vol. 89 (2008)
pp 933-940; and
Fuel Processing Technology, Vol. 89 (2009) pp 941-948.
[0024] There is a need to develop a solvent deasphalting method for producing
a fungible
bitumen product from solvent extracted bitumen.
[0025] The use of hydrocarbons, such as kerosene, as process aids in water-
based
extraction processes has been disclosed. However, light hydrocarbons are
relatively expensive as
process aids, and may need to be recovered from the water extracted tailings
for economic and/or
environmental reasons.
[0026] Bitumen can itself act as process aid for additional bitumen recovery
in a water-
based extraction process. For example, U.S. Patent Application 12/163,590
filed June 27, 2008,
published as Publication No US 2009/0321326 and entitled Primary Froth
Recycle, reveals the
possibility of using a bitumen-rich stream to enhance recovery. This document
describes the
recycling of primary bitumen froth in a step of the water-based extraction
process upstream of the
primary separation vessel, in an effort to increase overall bitumen recovery
in a water-based
process. This publication presents pilot plant data showing improvements in
overall bitumen
recovery and higher quality primary froth. For example, for oil sands ore with
10 wt% bitumen and
27 wt% fines, recycling 33% of the froth to the slurry preparation unit
improved bitumen recovery
from approximately 73% to approximately 91 %.
[0027] The process described in US 2009/0321326 does not suggest uses for
froth outside
of conventional water-based extraction processes. However, an improvement in
bitumen recovery is
realized due to recycling of froth, illustrates that increasing the bitumen
content of a water-based
slurry can yield improved bitumen recovery in a water-based process.
[0028] There is a need for similar benefits to be sought within a water-based
extraction
process that is integrated with a solvent-based extraction process. Thus,
there is a need to develop
a process where solvent extracted bitumen may be used to improve the bitumen
recovery within a
water-based extraction process.
[0029] Wet tailings produced in water-based extraction processes are often
held in a
geographically contained location. Government regulations may require tailings
produced from
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CA 02740481 2011-05-17

water-based extraction to achieve a set strength rating over a period of time,
such as a strength
rating of 5 kPa one year after production of the tailings. While such strength
objectives can be met
by extra dewatering, the energy intensity required to achieve an even lower
water content may
make the incremental dewatering inefficient. The dewatering of fine wet
tailings derived from water-
based extraction may involve the use of expensive flocculants. Holding areas,
known as dedicated
disposal areas (DDA), are required for containing the dewatered tailings. The
DDAs are expected to
be expensive to maintain. Furthermore, it is unclear that the thickened
tailings produced from
dewatering will consistently be able to meet the strength rating goal within
one year of tailings
production.
[0030] Treatments for solids or tailings produced by a solvent-based
extraction process
have been previously proposed. For example, Canadian Patent No. 1,031,712
entitled Tar Sands
Separation, describes using an aqueous bridging liquid to agglomerate solids
during solvent
extraction. The document describes that these agglomerates can be sintered at
high temperatures
to produce agglomerates having concrete-like strength. The document also
discloses using water
with water-soluble adhesives and/or emulsion type adhesives as the bridging
liquid to form the
agglomerates. The adhesives would act to strengthen the agglomerates and
impart water
resistance when the agglomerates are dried in the tailings solvent recovery
stage of the solvent-
based extraction process.
[0031] The dry agglomerates produced in solvent-based extraction processes
have been
previously described for use in landscape construction. However, there is
little suggestion of other
uses for dry agglomerates. There is a need to develop processes by which these
dry agglomerates
from solvent-based extraction processes can be integrated within water-based
extraction processes
for improved overall tailings behavior.
[0032] An overview of a previously described process for recovery of
hydrocarbon using
solvent is provided below. This process is referred to as solvent extraction
spherical agglomeration
(SESA). SESA has not been commercially adopted. For a full description of the
SESA process,
see Sparks et al., Fuel 1992(71);1349-1353. The SESA process involved mixing a
slurry of oil
sands material with a hydrocarbon solvent (such as a high boiling point
solvent), adding a bridging
liquid (for example, water), agitating this mixture in a slow and controlled
manner to nucleate
particles, and continuing such agitation so as to permit these nucleated
particles to form larger multi-
particle spherical agglomerates for removal. A bridging liquid (also referred
to as a binding liquid) is
a liquid with affinity for the solid particles (i.e. preferentially wets the
solid particles) but is immiscible
in the solvent. The process was conducted at about 50 - 80 C (see also
Canadian Patent

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CA 02740481 2011-05-17

Application 2,068,895 of Sparks et al.). The enlarged size of the agglomerates
formed permitted
easy removal of the solids by sedimentation, screening or filtration.
[0033] The proposed solvents in previously described SESA processes have a low
molecular weight, high aromatic content, and low short chain paraffin content.
Naphtha was the
solvent proposed for the SESA process, with a final boiling point ranging
between 180-220 C, and
a molecular weight of 100 - 215 g/mol.
[0034] A methodology described by Meadus et al. in U.S. Patent No. 4,057,486,
involved
combining solvent extraction with particle enlargement to achieve spherical
agglomeration of tailings
suitable for direct mine refill. Organic material was separated from oil sands
by mixing the oil sands
material with an organic solvent to form a slurry, after which an aqueous
bridging liquid was added
in small amounts. By using controlled agitation, solid particles from oil
sands adhere to each other
and were enlarged to form macro-agglomerates of mean diameter greater than 2
mm from which
the bulk of the bitumen and solvent was excluded. This process permitted a
significant decrease in
water use, as compared with conventional water-based extraction processes.
Solvents used in the
process were of low molecular weight, having aromatic content, but only small
amounts of short
chain paraffins.
[0035] U.S. Patent No. 3,984,287 describes an apparatus for separating organic
material
from particulate tar sands, resulting in agglomeration of a particulate
residue. The apparatus
included a tapered rotating drum in which tar sands, water, and an organic
solvent were mixed
together. In this apparatus, water was intended to act as a bridging liquid to
agglomerate the
particulate, while the organic solvent dissolves organic materials. As the
materials combined in the
drum, bitumen was separated from the ore.
[0036] A device to convey agglomerated particulate solids for removal to
achieve the
process of Meadus et al. (U.S. Patent No. 4,057,486) within a single vessel is
described in U.S.
Patent No. 4,406,788.
[0037] A method for separating fine solids from a bitumen solution is
described in U.S.
Patent No. 4,888,108. To remove fine solids, an aqueous solution of polar
organic additive as well
as solvent capable of precipitating asphaltenes was added to the solution, so
as to form aggregates
for removal from the residual liquid.
[0038] Others have proposed sequential use of two solvents in different
solvent-based
extraction schemes. For example U.S. Patent No. 3,131,141 proposed the use of
high boiling point
solvent for oil sands extraction followed by low boiling point/volatile
solvent for enhanced solvent
recovery from tailings in a unique process arrangement. U.S. Patent No.
4,046,668 describes a
process of bitumen recovery from oil sands using a mixture of light naphtha
and methanol.

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[0039] U.S. Patent No. 4,719,008 describes a method for separating micro-
agglomerated
solids from a high-quality hydrocarbon fraction derived from oil sands. A
light milling action was
imposed on a solvated oil sands mixture. After large agglomerates were formed,
the milling action
was used to break down the agglomerate size, but still permitted agglomerate
settling and removal.
[0040] U.S. Patent No. 5,453,133 and U.S. Patent No. 5,882,429 describe soil
remediation
processes to remove hydrocarbon contaminants from soil. The processes employed
a solvent and
a bridging liquid immiscible with the solvent, and this mixture formed
agglomerates when agitated
with the contaminated soil. The contaminant hydrocarbon was solvated by the
solvent, while soil
particles agglomerated with the bridging liquid. In this way, the soil was
considered to have been
cleaned. Multiple extraction stages were proposed.
[0041] Govier and Sparks describe an agglomeration process in "The SESA
Process for the
Recovery of Bitumen from Mined Oil Sands" (Proceedings of AOSTRA Oils Sands
2000
Symposium, Edmonton 1990, Paper 5). This process is referenced herein as the
Govier and
Sparks process. The solvent described possessed a low molecular weight and
significant aromatic
content, while containing only a small amount of short chain paraffins.
Exemplary solvents were
described as varsol or naphtha.
[0042] Typically, a bottom sediment and water (BS&W) content, primarily
comprised of fines,
of between 0.2 - 0.5 wt% of solids in dry bitumen could be achieved according
to the Govier and
Sparks process. However, occasionally solids agglomeration would cycle
unpredictably and the
fines content of the agglomerator discharge stream would rise dramatically.
Subsequent settling in a
clarifier or bed filtration would then be required to achieve the desired
product quality of 0.2 - 0.5
wt% BS&W. The BS&W component prepared by the process was comprised mostly of
solids.
Bitumen products with this composition are not fungible and can only be
processed at a site coking
facility or at an onsite upgrader.
[0043] The above-described agglomeration processes integrated solvent
extraction and
agglomeration within the same mixing vessel. Conventional agglomeration units
are large drums
designed to integrate both the extraction and agglomeration aspects of the
process.
[0044] A variety of system components are known for use in bitumen extraction.
The
solvent-based extraction system described by Sparks et al. (Fuel 1992; 71:1349-
1353) employs a
direct feed of oil sand into an extraction agglomerator configured as a
rotating tumbler, following
which agglomerated sand is washed in a counter-current washing system using
progressively
cleaner solvent. Solvent is recovered from washed agglomerates using a
rotating dryer.
[0045] The system described in U.S. Patent No. 4,057,486 to Meadus et al.
employs an
agglomerator configured as a rotating conical vessel, into which oil sands and
solvent are added.
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This is followed by settling of agglomerates and decantation, or by screening
agglomerates to
separate of the organic phase from the agglomerates. Optional system
components such as a
fluidized bed conversion unit may be used for further processing of
agglomerates, while a distillation
unit or conversion unit may be used to further process the organic phase.
[0046] In Canadian Patent Application 2,068,895, a system is described which
employs a
rotating drum agglomerator to combine a high fines fraction from oil sands
with solvent. Discharge
of agglomerates through a trommel screen for removing large stones is followed
by feeding effluent
to a filter via a surge hopper. Countercurrent washing through a filter with
progressively cleaner
solvent is followed by drainage of agglomerates. A rotary dryer is employed
for drying agglomerates
and for solvent recovery.
[0047] It is desirable to provide processes and systems that increase the
efficiency of oil
sands extraction, reduce water use, utilize waste products of extraction
processes, and/or reduce
energy intensity required to produce a commercially desirable bitumen product
from oil sands.
Producing a product that is capable of meeting or exceeding requirements for
downstream
processing or pipeline transport is desirable.

SUMMARY
[0048] It is an object of the present disclosure to obviate or mitigate at
least one
disadvantage of previous processes or systems for hydrocarbon extraction from
mineable deposits
such as oil sands.
[0049] There are described herein processes and/or systems for integrating a
water-based
extraction processes and streams with solvent-based extraction processes and
streams in order to
capture previously unrecognized synergies between the two processes.
[0050] (A) Integration of Water-Based Extraction and Solvent-Based Extraction
Processes and Systems
[0051] It is desirable to optimize efficiencies of geographically proximal
water-based
extraction and solvent-based extraction systems by integrating streams from
one system into the
other, in situations where such streams may be used effectively, for example
to increase bitumen
recovery, produce a cleaner product, and/or increase thermal efficiencies.
[0052] There is described herein a process for extracting bitumen from oil
sands into a
bitumen-rich stream, the process comprising: (a) separating bitumen from oil
sands by addition of
water to form a bitumen-enhanced stream and a bitumen-lean stream; (b) mixing
the bitumen-lean
stream with additional oil sands to form a mixed stream; (c) adding solvent to
the mixed stream to
extract bitumen from the mixed stream into the solvent, thereby forming a
bitumen-depleted stream
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and an extracted bitumen stream; and (d) mixing the extracted bitumen stream
with the bitumen-
enhanced stream to form a bitumen-rich stream.
[0053] Processes are described herein which integrate solvent-based extraction
procedures
with certain aspects of water-based extraction procedures for extraction of
hydrocarbon from
mineable deposits. Hydrocarbon-containing streams from water-based extraction
processes can be
directed to solvent-based extraction processes, and/or streams from solvent-
based extraction
processes can be directed to water-based processes. This may have the possible
advantages of
reducing and/or eliminating process equipment currently used in either the
water-based extraction
process or solvent-based extraction process.
[0054] Furthermore, the integration of these extraction processes may also
lead to an
overall reduction in water use in the water-based extraction process per unit
of bitumen produced.
Other benefits may include reduced tailings volumes, improved operation of
both the water-based
and solvent-based extraction processes, and increased overall bitumen recovery
from oil sands.
Other possible integration opportunities include directing the bitumen product
derived from solvent-
based extraction to the water-based extraction process. For example, solvent
extracted bitumen
product may be directed to the froth treatment stage of water-based extraction
process for further
processing. This integration may result in the advantage of producing a
cleaner pipelineable
product from the solvent extracted bitumen, which is optimally fungible, with
300 ppm or less of total
solids content.
[0055] A reduction in fresh water withdrawal from nearby rivers may be
realized. Improved
tailings management versus currently practiced water-based extraction process
could also be an
advantage of the processes and systems described herein. Further, the
integration of water-based
extraction and solvent-based extraction processes may have the advantage of
reduced energy
intensity, and commensurate cost reductions. Heat generated during solvent-
based extraction may
be captured to heat water used in the water-based extraction process and vise
versa. Further,
heated streams may be combined with cold streams to achieve process
efficiencies.
[0056] (B) Recovery of Bitumen from Aqueous Sources
[0057] Further, it is desirable to provide techniques to recover bitumen from
aqueous
hydrocarbon-containing streams arising from water-based extraction, that can
operate efficiently in
the presence of fines, or which are largely unaffected by the presence of
fines.
[0058] There is described herein a process for pre-treating an aqueous
hydrocarbon-
containing feed for a downstream solvent-based extraction process for bitumen
recovery, said
aqueous hydrocarbon-containing feed comprising from 50 wt% to 95 wt% water,
from 0.1 wt% to 10
wt% bitumen, and from 5 wt% to 50 wt% solids, wherein said solids comprise
fines, the process

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comprising: removing water from the aqueous hydrocarbon-containing feed to
produce an effluent
comprising 40 wt% water or less; and providing the effluent to the downstream
solvent-based
extraction process for bitumen recovery, wherein said downstream solvent-based
extraction process
comprises fines agglomeration.
[0059] Certain embodiments described herein advantageously permit recovery of
hydrocarbon from aqueous hydrocarbon-containing streams that were previously
considered too
dilute for recovery, in part due to a high fines content combined together
with a high water content of
over 50% by weight. By de-watering such aqueous streams containing bitumen to
the point that the
effluent contains less than 40% water, the streams can then be used in a
process that employs
agglomeration of fines.
[0060] Recycling conventionally discarded aqueous hydrocarbon-containing
streams is
important from an environmental perspective as well as from an efficiency
perspective. By
decreasing water content of an aqueous hydrocarbon-containing stream to a
desirable level, the
stream would become more desirable for use in solvent-based extraction
processes. Recovered
water may advantageously be put to use in any aspect of bitumen production
that may incorporate
recycled water. By de-watering an aqueous hydrocarbon-containing stream prior
to attempts to
remove all hydrocarbon or bitumen, steps in a conventional water-based
extraction process can be
omitted, thereby introducing efficiencies at certain steps in the process.
[0061] (C) Extracting Hydrocarbons from PFT Tailings by Directing Tailings
into a
Solvent-Based Extraction Process
[0062] Further, it is desirable to increase recovery of hydrocarbon from
paraffinic froth
treatment tailings by directing such tailings into a solvent-based extraction
process for further
bitumen recovery.
[0063] There is described herein a process for recovering hydrocarbon from a
tailings
stream from a paraffinic froth treatment process, the process comprising: (a)
accessing a
hydrocarbon-containing froth treatment tailings stream from a paraffinic froth
treatment process; (b)
combining the froth treatment tailings stream with a solvent and additional
oil sands to form a slurry;
(c) agitating the slurry to dissolve hydrocarbon into the solvent and to
agglomerate fines within the
slurry; (d) separating the extracted hydrocarbon from the agglomerated fines
to form a low solids
extracted hydrocarbon stream and an extracted tailings stream; and (e)
recovering the solvent from
the extracted tailings stream.
[0064] Advantageously, according to an embodiment in which froth treatment
tailings are
directed into a solvent-based extraction process involving fines
agglomeration, the extraction of
residual bitumen from the tailings and the formation of agglomerates occur
simultaneously during
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the agglomeration step. In this way, most of the hydrocarbons are recovered
and most of the fines
solids are captured within the formed agglomerates for easy separation from
the hydrocarbon
extract.
[0065] (D) Directing a Bitumen-Rich Stream into a Solvent-Based Extraction
Process
[0066] It is desirable to direct bitumen-rich aqueous streams, derived from
water-based
extraction, into a solvent-based extraction process, as a source of dissolved
bitumen for the solvent
used in an extraction liquor. In this way, the amount of bitumen recycled
within the solvent-based
extraction process can be reduced or eliminated while maintaining the
advantages provided by
having pre-dissolved bitumen within the solvent used in the solvent-based
extraction process.
Further, the increased bitumen yield (lower recycle bitumen) of the solvent-
based extraction process
translates to a significant reduction in the energy requirement, on a
production basis, of the tailing
solvent recovery unit.
[0067] There is described herein a process for recovering bitumen from oil
sands, the
process comprising: (a) extracting bitumen from oil sands in a water-based
extraction process to
form a bitumen-enhanced stream and a bitumen-lean stream; (b) mixing the
bitumen-enhanced
stream with a solvent to form an extraction liquor; (c) mixing the extraction
liquor with additional oil
sands to form a slurry comprising solids and bitumen extract; (d) separating
the solids from the
slurry to form a low solids bitumen extract; and (e) recovering solvent from
the low solids bitumen
extract to form a solvent extracted bitumen product.
[0068] Bitumen-rich streams derived from the water-based extraction process
can be used
to replace recycled bitumen. In this way, most or all of the bitumen processed
in the solvent-based
extraction process will add to the bitumen yield of the process. Additionally,
fewer solids will be
processed in the solvent-based extraction process per unit of bitumen
produced.
[0069] The bitumen-rich aqueous streams can also provide the water needed for
solvent-
based extraction, for example when a solids agglomeration step employs a
bridging liquid.
Additionally, the solvent-based extraction process may also act to separate
most of the solids and
water associated with the bitumen-rich aqueous streams from the resulting
bitumen extract. In this
way, the solvent-based extraction process can act in place of the froth
treatment unit of a
conventional water-based extraction process.
[0070] (E) Water-Assisted Deasphalting Technologies for Streams Derived from
Solvent-Based Extraction
[0071] It is desirable to provide processes through which residual fine solids
and water can
be removed from a stream derived from a solvent-based extraction process, by a
deasphalting
process such as paraffinic froth treatment associated with a water-based
extraction process or a

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process similar to paraffinic froth treatment. In this way, advantages
associated with paraffinic froth
treatment, such as enhanced settling rates, higher product yields, and reduced
operating
temperatures, can be realized.
[0072] There is described herein a process for removing solids from oil sands,
the process
comprising: (a) forming an oil sands slurry by mixing the oil sands with a
first solvent, wherein the
amount of first solvent added is greater than 10 wt% of the oil sands; (b)
separating a majority of the
solids from the oil sands slurry, forming a solids-rich stream and a bitumen-
rich stream, wherein the
bitumen-rich stream comprises residual solids; (c) emulsifying the bitumen-
rich stream with a water-
containing stream to form a hydrocarbon-external emulsion, wherein
hydrocarbons form an external
phase of the emulsion; (d) mixing the hydrocarbon-external emulsion with a
deasphalting solvent in
sufficient quantity to cause some asphaltene precipitation, wherein
precipitated asphaltenes adhere
to at least a portion of the residual solids and to water droplets; and (e)
separating the precipitated
asphaltenes from the hydrocarbon-external emulsion, thereby removing residual
solids and water
droplets adhering to the precipitated asphaltenes and forming a cleaned
hydrocarbon product.
[0073] Further, there is described herein a process for removing solids from
oil sands
comprising bitumen and solids, the process comprising: (a) mixing oil sands
with a first solvent to
form an oil sands slurry, wherein the amount of the first solvent added is
greater than 10 wt% of the
oil sands; (b) separating a majority of the solids from the oil sands slurry
to form a solids-rich
stream and an initial bitumen-rich stream, wherein the initial bitumen-rich
stream comprises residual
solids; (c) removing the first solvent from the initial bitumen-rich stream to
form a solvent depleted
bitumen-rich stream; (d) directing at least a portion of the solvent-depleted
bitumen-rich stream to a
paraffinic froth treatment process of a water-based extraction process; and
(e) deriving a fungible
bitumen product from the paraffinic froth treatment process.
[0074] Solvent deasphalting assisted by the addition of water to the solvent
extracted
bitumen will allow for a deasphalting process similar to PFT, bringing about
some of the advantages
of the PFT process within solvent-based bitumen extraction process.
[0075] (F) Directing Solvent Extracted Bitumen Product to Water-based
Extraction
Processes
[0076] It is desirable to utilize integration of bitumen-containing streams
from solvent-based
extraction processes for preparing an input feed for water-based extraction
process so as to achieve
a bitumen enriched stream within the water-based extraction process.
[0077] There is described herein a process for recovering hydrocarbon from oil
sands, the
process comprising: (a) contacting a first oil sands ore with a solvent to
form a solvent-based slurry
comprising solids and a bitumen extract; (b) separating the solids from the
solvent-based slurry to

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produce a low solids bitumen extract; (c) removing solvent from the low solids
bitumen extract to
form a solvent extracted bitumen product; (d) contacting a second oil sands
ore with water to form
an aqueous slurry; (e) mixing the solvent extracted bitumen product with the
aqueous slurry to form
a bitumen enriched slurry; and (f) recovering bitumen from the bitumen
enriched second slurry.
[0078] The enriched bitumen stream may lead to an increase in overall bitumen
recovery
and bitumen froth quality. Furthermore, since recovered bitumen from the water-
based extraction
process may undergo paraffinic froth treatment to produce a fungible bitumen
product, this
integration of extraction processes permits further cleaning of the streams
derived from solvent-
based extraction which may not yet be of a fungible quality, or adequately
pure to meet pipeline
specifications.
[0079] (G) Directing Solvent Extracted Tailings to Water-Based Extraction
Process
[0080] It is desirable to combine nominally dry tailings from a solvent-based
extraction
process with tailings or partially dewatered tailings from a water-based
extraction process in order to
yield a combined higher volume of reclaimable material.
[0081] There is described herein a process for extracting hydrocarbon from oil
sands ore,
the process comprising: (a) contacting the ore with a first solvent to form a
first slurry comprising
solids and a bitumen extract; (b) separating the bitumen extract from the
first slurry to form solvent
wet tailings comprised of the solids and the first solvent; (c) removing the
first solvent from the
solvent wet tailings to form dry tailings; (d) combining said dry tailings
with water wet tailings
produced from a water-based extraction process to form strengthened tailings,
wherein the dry
tailings comprise a water content of less than 15 wt% and the water wet
tailings comprise a water
content of more than 25 wt%.
[0082] For example, the agglomerated fines produced in a solvent-based
extraction process
that employs solids agglomeration may be treated using heat or chemicals to
reduce the likelihood
of the agglomerates disintegrating in the presence of water. Such agglomerated
fines can be
directed to the water-based extraction process where they may serve as coarse
tailings substitutes
in a process such as non-segregating tailings formation. The integration of
water extracted wet
tailings with solvent extracted dry tailings in order to produce a mixture of
tailings with higher yield
strength than the water extracted wet tailings alone offers advantages in
meeting stringent
requirements for tailings characteristics.
[0083] Other aspects and features described herein will become apparent to
those ordinarily
skilled in the art upon review of the following description of specific
embodiments in conjunction with
the accompanying figures.

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CA 02740481 2011-05-17
BRIEF DESCRIPTION OF THE DRAWINGS
[0084] Embodiments of the present disclosure will now be described, by way of
example
only, with reference to the attached Figures.
[0085] Figure 1 is a schematic representation of process within the scope of
the present
disclosure.
[0086] Figure 2 illustrates an exemplary embodiment of processes consistent
with the
representation shown in Figure 1.
[0087] Figure 3 is a schematic representation of processes within the scope of
the present
disclosure.
[0088] Figure 4 illustrates an exemplary embodiment of processes consistent
with the
representation shown in Figure 3.
[0089] Figure 5 is a schematic representation of process within the scope of
the present
disclosure.
[0090] Figure 6 illustrates an exemplary embodiment of processes consistent
with the
representation shown in Figure 5.
[0091] Figure 7 provides a schematic representation of systems within the
scope of the
present disclosure.
[0092] Figure 8 is a schematic representation of an embodiment of the process
described
herein.
[0093] Figure 9 illustrates an integrated process in which streams from a
water-based
process are directed to a solvent-based extraction process.
[0094] Figure 10 is a schematic representation of processes for preparation of
an aqueous
stream for downstream bitumen extraction, within the scope of the present
disclosure.
[0095] Figure 11 depicts an embodiment of processes according to Figure 10,
which
employ primary and secondary water separation.
[0096] Figure 12 is a schematic illustration of processes incorporating the
preparation of an
aqueous stream according to Figure 10 together with downstream steps for
recovery of bitumen
using a solvent-based extraction process.
[0097] Figure 13 is a schematic representation of an exemplary process in
which froth
tailings are directed to a solvent-based extraction process to recover
bitumen.
[0098] Figure 14 is a schematic representation of an embodiment of the process
depicted in
Figure 13, in which hydrocarbon from paraffinic froth treatment tailings is
extracted in a water-based
process involving agglomeration.

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[0099] Figure 15 is a schematic representation of a process for utilizing
bitumen entrained
in froth from a water-based process in a solvent-based process.
[00100] Figure 16 illustrates an exemplary process for utilizing an extraction
liquor spiked
with bitumen froth from water-based extraction.
[00101] Figure 17 is a schematic representation of a process in which fine
solids are
removed from a solvent extracted bitumen product by water-assisted partial
deasphalting.
[00102] Figure 18 illustrates a process according to Figure 17 in which water-
assisted
deasphalting is used to create a fungible product from solvent extracted oil
sands.
[00103] Figure 19 is a schematic representation of a process in which
paraffinic froth
treatment is used to remove residual solids within a product stream derived
from solvent extraction.
[00104] Figure 20 illustrates a process according to Figure 19 in which the
bitumen product
produced by PFT is below the threshold of fungible standards to permit the
product of a solvent-
based extraction process, that does not meet the fungible standards, to be
combined directly,
resulting in a net fungible product.
[00105] Figure 21 is a schematic diagram of a process in which a solvent-based
extraction
product is further processed as an input feed into a water-based extraction
process.
[00106] Figure 22 illustrates a process in which a stream derived from solvent-
based
extraction is processed in a water-based extraction process.
[00107] Figure 23 is a schematic diagram of a process in which dry tailings
from a solvent-
based extraction process are integrated in a water-based extraction process.
[00108] Figure 24 illustrates a process in which integration of dry
agglomerated tailings with
tailings derived from a water-based extraction process, results in
strengthened tailings for use in
reclaimed land.

DETAILED DESCRIPTION
[00109] Generally, there are described herein processes and systems for
extraction of
bitumen from oil sands. Processing oil sands according to the processes
described herein can
permit high throughput, efficiencies, increased bitumen recovery, and/or
improved product quality
and value.
[00110] The term "bituminous feed" from oil sands refers to a stream derived
from oil sands
that requires downstream processing in order to realize valuable bitumen
products or fractions. The
bituminous feed from oil sands is one that contains bitumen along with other
undesirable
components, which are removed in the process described herein. Such a
bituminous feed may be
derived directly from oil sands, and may be, for example, raw oil sands ore.
Further, the bituminous

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feed may be a feed that has already realized some initial processing but
nevertheless requires
further processing according to the process described herein. Also, recycled
streams that contain
bitumen in combination with other components for removal in the described
process can be included
in the bituminous feed. A bituminous feed need not be derived directly from
oil sands, but may arise
from other processes. For example, a waste product from other extraction
processes which
contains bitumen that would otherwise not have been recovered, may be used as
a bituminous feed.
Such a bituminous feed may be also derived directly from oil shale, oil
bearing diatomite or oil
saturated sandstones.
[00111] As used herein, "agglomerate" refers to conditions that produce a
cluster, aggregate,
collection or mass, such as nucleation, coalescence, layering, sticking,
clumping, fusing and
sintering, as examples.
[00112] Certain extraction processes for separation of bitumen from oil sands
involving
aqueous extraction are referred to herein as "water-based" extraction
processes. Bitumen
extraction processes that primarily involve water may also include solvent
additions at different
stages in various steps in combination with water. However, in such cases,
water remains the
dominant liquid by volume in the extraction process. Certain extraction
processes for separation of
bitumen from oil sands involving solvent extraction are referred to herein as
"solvent-based"
extraction processes. Bitumen extraction processes that primarily involve
solvent may also include
water additions at different stages in various steps in combination with
solvent. However, in such
cases, solvent remains the dominant liquid by volume in the extraction
process.
[00113] (A) Integration of Water-Based Extraction and Solvent-Based Extraction
Processes and Systems
[00114] A process is described herein for extracting bitumen from oil sands
into a bitumen-
rich stream. The process involves separating bitumen from oil sands by
addition of water to form a
bitumen-enhanced stream and a bitumen-lean stream. This may be done, for
example, using a
water-based extraction process, and the bitumen-enhanced stream may be, for
example froth,
sales bitumen product, FSU overflow, or SRU underflow.
[00115] The bitumen-lean stream is mixed with additional oil sands to form a
mixed stream.
The bitumen-lean stream may be partially dewatered before mixing with
additional oil sands, for
example, to a level of 40% water by weight or less.
[00116] . Solvent is added to the mixed stream to extract bitumen from the
mixed stream
into the solvent, thereby forming a bitumen-depleted stream and an extracted
bitumen stream.
This may be done, for example, in a solvent-based extraction process, and the
bitumen-lean
stream may be derived from, middlings, primary separation tailings, flotation
tailings, mature fine

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CA 02740481 2011-05-17

tailings, froth treatment tailings (such as from FSU underflow or TSRU), or
other streams derived
from water-based extraction, such as a reject stream from a slurry preparation
system of a water-
based extraction process.
[00117] The extracted bitumen stream is then mixed with the bitumen-enhanced
stream to
form a bitumen-rich stream. Optionally, solvent can be removed from the
extracted bitumen
stream before mixing with the bitumen-enhanced stream. Once formed, the
bitumen-rich stream
may be subsequently processed to remove residual solids and water therefrom to
produce a
product cleaned bitumen, which may optionally be upgraded on sit. Such
processing may occur
for example in a froth treatment unit of a water-based extraction process to
produce a product
cleaned bitumen. The bitumen-rich stream may be processed to meet fungible
specifications so as
to produce a fungible bitumen product. An exemplary mode of treatment for the
bitumen-rich
stream is within paraffinic froth treatment, which can achieve a fungible
bitumen product.
Advantageously, the bitumen-rich stream can be mixed with the bitumen-lean
stream before being
directed to paraffinic froth treatment, and optionally, the bitumen-lean
stream can be partially
dewatered before being mixed in this way.
[00118] The bitumen-enhanced stream may be referred to as "sales bitumen
product", in
instances wherein mixing the extracted bitumen stream yields a bitumen-rich
stream that is
fungible.
[00119] The bitumen-depleted stream may be one comprising agglomerated fines,
optionally
derived from the mixed stream after adding solvent to the mixed stream,
forming agglomerates in a
solvent-based extraction process. Such agglomerates may be washed on a belt
filter using
countercurrent washing.
[00120] In this process, heat may be recovered from a solvent recovery unit of
the solvent-
based extraction process.
[00121] According to certain embodiments wherein a water-based extraction
process is
used to form the bitumen-enhanced stream, and a solvent-based extraction
process is used to
form the bitumen-depleted and extracted bitumen streams, it is possible to
consolidate a solvent
recovery step of the water-based extraction process with a solvent recovery
step of the solvent-
based extraction process to realize efficiency in the process. Optionally, the
water-based extraction
process may employ a primary separation vessel for recovering bitumen froth
and a froth
separation unit for producing the bitumen-enhanced stream. When solvent-based
extraction is
employed, it may be a solvent-based extraction and solids agglomeration
process (SESA).
[00122] (B) Recovery of Bitumen from Aqueous Sources
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CA 02740481 2011-05-17

[00123] A process is described herein for pre-treating an aqueous hydrocarbon-
containing
feed for a downstream solvent-based extraction process for bitumen recovery.
The feed may
include from 50 wt% to 95 wt% water, from 0.1 wt% to 10 wt% bitumen, and from
5 wt% to 50 wt%
solids, wherein said solids comprise fines. The process involves removing
water from the feed to
produce an effluent comprising 40 wt% water or less; and subsequently
providing the effluent to
the downstream solvent-based extraction process for bitumen recovery. The
downstream solvent-
based extraction process may comprise fines agglomeration. Removing water from
the aqueous
hydrocarbon-containing feed may entail flowing the feed into a primary water
separation system to
remove water therefrom, such as a clarifier, a settler, a thickener or a
cyclone. A solvent and/or
flocculant may be added, for example mixed in with the feed prior to
separation within a clarifier .
This step of water removal produces a reduced-water stream of from 30 wt% to
60 wt% solids, and
recycled water. Further, water may removed from the reduced-water stream using
a secondary
water separation system to produce an effluent comprising 40 wt% water or
less.
[00124] The feed may be one that is produced from a water-based extraction
process
wherein a flocculants or coagulant is used to induce aggregation of fines and
hydrocarbons within
the water-based extraction process.
[00125] If solvent is mixed with the feed, the solvent may havie bitumen
entrained therein for
a solvent:bitumen ratio of less than about 2:1. Such a solvent may be a low
boiling point
cycloalkane.
[00126] For embodiments in which a secondary water separation system is
employed, this
may comprise a centrifuge with filtering capacity, a shale shaker, a vacuum
belt filter, or one or
more clarifiers.
[00127] The aqueous hydrocarbon-containing feed may be the effluent of a froth
separation
unit, for example, or may be derived from tailings from a tailings solvent
recovery unit.
[00128] Embodiments of the process may additionally comprise recovery of
bitumen,
wherein the downstream solvent-based extraction process comprises: combining a
first solvent
with the effluent and a bituminous feed from oil sands to form an initial
slurry; separating the initial
slurry into a fine solids stream and a coarse solids stream; agglomerating
solids from the fine solids
stream to form an agglomerated slurry comprising agglomerates and a low solids
bitumen extract;
separating the low solids bitumen extract from the agglomerated slurry; mixing
a second solvent
with the low solids bitumen extract to form a solvent-bitumen low solids
mixture, the second solvent
having a similar or lower boiling point than the first solvent; subjecting the
mixture to gravity
separation to produce a high grade bitumen extract and a low grade bitumen
extract; and

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CA 02740481 2011-05-17

recovering the first and second solvent from the high grade bitumen extract,
leaving a high grade
bitumen product.
[00129] The downstream solvent-based extraction process may alternatively
include:
combining a first solvent with the effluent and a bituminous feed from oil
sands to form an initial
slurry; agglomerating solids from the initial slurry to form an agglomerated
slurry comprising
agglomerates and a low solids bitumen extract; separating the low solids
bitumen extract from the
agglomerated slurry; mixing a second solvent with the low solids bitumen
extract to form a solvent-
bitumen low solids mixture, the second solvent having a similar or lower
boiling point than the first
solvent, subjecting the mixture to gravity separation to produce a high grade
bitumen extract and a
low grade bitumen extract; and recovering the first and second solvent from
the high grade
bitumen extract, leaving a high grade bitumen product; wherein the ratio of
first solvent to bitumen
in the initial slurry is selected to avoid precipitation of asphaltenes during
agglomeration.
[00130] A system is described herein for pre-treating an aqueous hydrocarbon-
containing
feed for a downstream solvent-based extraction process for bitumen recovery,
wherein the feed
contains from 50 wt% to 95 wt% water, from 0.1 wt% to 10 wt% bitumen, and from
5 wt% to 50
wt% solids, wherein said solids are fines. The system comprises a dewatering
unit for removing
water from the aqueous hydrocarbon-containing feed to produce an effluent
comprising 40 wt%
water or less; and a conduit for providing the effluent to a downstream
solvent-based extraction
process comprising fines agglomeration to recover bitumen.
[00131] In such a system, the dewatering unit may include a primary water
separation
system to remove water from the aqueous hydrocarbon-containing feed, producing
a reduced-
water stream and recycled; and a secondary water separation system for
receiving the reduced-
water stream and removing water therefrom to produce an effluent comprising 40
wt% water or
less. The system may additionally comprise components for recovery of bitumen
in the
downstream solvent-based extraction process. For example, such components may
be: a slurry
system wherein a bituminous feed is mixed with effluent from the de-watering
system and a first
solvent to form an initial slurry; a fine/coarse solids separator in fluid
communication with the slurry
system for receiving the initial slurry and separating a fine solids stream
therefrom; an
agglomerator for receiving a fine solids stream from the fine/coarse solids
separator, for
agglomerating solids and producing an agglomerated slurry; a primary solid-
liquid separator for
separating the agglomerated slurry into agglomerates and a low solids bitumen
extract; a gravity
separator for receiving the low solids bitumen extract and a second solvent;
and a primary solvent
recovery unit for recovering the first solvent or the second solvent in a high
grade bitumen extract
arising from the gravity separator and for separating bitumen therefrom.

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CA 02740481 2011-05-17

[00132] Further, the components for recovery of bitumen in the downstream
solvent-based
extraction process could alternatively include: a slurry system wherein a
bituminous feed is mixed
with a first solvent to form an initial slurry; an agglomerator for receiving
the initial slurry, for
agglomerating solids and producing an agglomerated slurry; a primary solid-
liquid separator for
separating the agglomerated slurry into agglomerates and a low solids bitumen
extract; a gravity
separator for receiving the low solids bitumen extract and a second solvent;
and a primary solvent
recovery unit for recovering the first solvent or the second solvent in a high
grade bitumen extract
arising from the gravity separator and for separating bitumen therefrom.
[00133] (C) Extracting Hydrocarbons from PFT Tailings by Directing Tailings
into a
Solvent-Based Extraction Process
[00134] Described herein is a process for recovering hydrocarbon from a
tailings stream
from a paraffinic froth treatment process. An exemplary embodiment of the
process includes
accessing a hydrocarbon-containing froth treatment tailings stream from a
paraffinic froth treatment
process; combining the froth treatment tailings stream with a solvent and
additional oil sands to
form a slurry; agitating the slurry to dissolve hydrocarbon into the solvent
and to agglomerate fines
within the slurry; separating the extracted hydrocarbon from the agglomerated
fines to form a low
solids extracted hydrocarbon stream and an extracted tailings stream; and
recovering the solvent
from the extracted tailings stream. The froth treatment tailings stream may be
derived from a froth
separation unit underflow of the paraffinic froth treatment (PFT) process, or
from a tailings solvent
recovery unit of PFT. Further, the froth treatment tailings stream may be
partially dewatered to
form a dewatered tailings stream before combining with the solvent, for
example, the stream can
be dewatered to less than 40 wt% water.
[00135] The slurry formed may have a water content of from 5 wt% to 25 wt%.
[00136] The solvent may be an aromatic solvent, such as toluene or benzene,
and may
have bitumen entrained therein, for example at an initial level in the solvent
of 10 wt% or greater.
For example, the solvent may be a cycloalkane with entrained bitumen.
[00137] In certain embodiments, the extracted tailings stream may comprise
agglomerated
fines. The process may further entail removal of the solvent from the low
solids extracted
hydrocarbon stream to form a bitumen product.
[00138] Optionally, separating the extracted hydrocarbon from the agglomerated
fines may
comprise washing agglomerated fines on a belt filter, for example with
countercurrent washing with
progressively cleaner solvent.
[00139] (D) Directing a Bitumen-Rich Stream into a Solvent-Based Extraction
Process
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CA 02740481 2011-05-17

[00140] A process for recovering bitumen from oil sands is described herein,
which includes
extracting bitumen from oil sands in a water-based extraction process to form
a bitumen-enhanced
stream and a bitumen-lean stream; mixing the bitumen-enhanced stream with a
solvent to form an
extraction liquor; mixing the extraction liquor with additional oil sands to
form a slurry comprising
solids and bitumen extract; separating the solids from the slurry to form a
low solids bitumen
extract; and recovering solvent from the low solids bitumen extract to form a
solvent extracted
bitumen product.
[00141] The oil sands initially extracted in the process may be of a high to
medium bitumen
content and a low to medium fines content. Further, the additional oil sands
mixed with the
extraction liquor for extraction may be of low to medium bitumen content and
of high to medium
fines content. The water-based extraction process used to produce the bitumen-
enhanced stream
may optionally employ a flocculant or a coagulant to induce aggregation of
fines and hydrocarbon
within the water-based extraction process. The water used in the water-based
extraction process
may have a sodium ion content of 1000 wppm or greater, on a weight basis,
and/or may have a
calcium ion content of 100 wppm or greater (also on a weight basis). Further,
the water may have
a pH of less than 8.
[00142] The bitumen-enhanced stream may have bitumen to solids ratio greater
than the oil
sands, for example, a bitumen:solids ratio of greater than 0.5:1. The bitumen-
enhanced stream
may have a bitumen content of 50 wt% or greater, and/or may have a water
content of 30 wt% or
less. The bitumen-enhanced stream may be bitumen froth derived from the water-
based extraction
process. Optionally, the bitumen-enhanced stream may be partially dewatered
prior to mixing with
the solvent. The extraction liquor may also be partially dewatered prior to
mixing with additional oil
sands. The bitumen-lean stream may also be partially dewatered.
[00143] The solvent mixed with the bitumen-enhanced stream may comprise
dissolved
bitumen. The extraction liquor may have a bitumen content of 40 wt% or less.
[00144] In embodiments of the process fines may be agglomerated within the
slurry.
[00145] In the solvent extracted bitumen product, there may be, for example,
from between
0.1 to about 2 wt% solids on a bitumen basis. The process may optionally
direct the solvent
extracted bitumen product to a product cleaning step to produce a fungible
bitumen product.
Exemplary cleaning steps may include gas flotation, membrane filtration, or a
combination thereof.
A fungible bitumen product so formed may have less than 300 wppm solids on a
bitumen basis.
The solvent extracted bitumen product may be forwarded to an upgrader for
further processing.
[00146] (E) Water-Assisted Deasphalting Technologies for Streams Derived from
Solvent-Based Extraction

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CA 02740481 2011-05-17

[00147] A process is described herein for removing solids from oil sands. The
process
involves forming an oil sands slurry by mixing the oil sands with a first
solvent, wherein the amount
of first solvent added is greater than 10 wt% of the oil sands; separating a
majority of the solids
from the oil sands slurry, forming a solids-rich stream and a bitumen-rich
stream, wherein the
bitumen-rich stream comprises residual solids; emulsifying the bitumen-rich
stream with a water-
containing stream to form a hydrocarbon-external emulsion, wherein
hydrocarbons form an
external phase of the emulsion; mixing the hydrocarbon-external emulsion with
a deasphalting
solvent in sufficient quantity to cause some asphaltene precipitation, wherein
precipitated
asphaltenes adhere to at least a portion of the residual solids and to water
droplets; and separating
the precipitated asphaltenes from the hydrocarbon-external emulsion, thereby
removing residual
solids and water droplets adhering to the precipitated asphaltenes and forming
a cleaned
hydrocarbon product.
[00148] The solvents may be removed from the cleaned hydrocarbon product to
form a
fungible bitumen product, such as one comprising 300 wppm solids or less on a
bitumen basis.
[00149] In one embodiment, the majority of the deasphalting solvent comprises
C3-C6
components, on a weight basis. In certain embodiments, the first solvent and
deasphalting solvent
are the same.
[00150] The water-containing stream may be process water, bitumen froth,
middlings,
flotation tailings, froth treatment tailings, deasphalting unit tailings, or
mixtures thereof.
[00151] The hydrocarbon-external emulsion formed in the process may comprise a
hydrocarbon dominated phase as overflow and an underflow with water as the
dominant fluid.
[00152] The first solvent may be removed from the bitumen-rich stream prior to
emulsifying
the bitumen-rich stream with the water-containing stream. Optionally, adding
the deasphalting
solvent to the bitumen-rich stream may occur prior to emulsifying the bitumen-
rich stream with the
water-containing stream. Advantageously, the deasphalting solvent can be added
to the bitumen-
rich stream in an amount that is not sufficient to precipitate asphaltenes.
[00153] The process may comprise removing the first solvent from the
hydrocarbon-external
emulsion prior to mixing the hydrocarbon-external emulsion with the
deasphalting solvent.
[00154] Agglomeration of fines may be employed in order to separate a majority
of the solids
from the oil sands slurry.
[00155] The bitumen-rich stream may be one containing between 0.1 to about 2
wt% solids
on a bitumen basis.
[00156] Mixing the emulsion with the deasphalting solvent may occur in a
deasphalting unit,
for example, a paraffinic forth treatment unit of a water-based extraction
process. In certain

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CA 02740481 2011-05-17

embodiments, the water-containing stream may provide a sufficient amount of
water to allow water
to be the dominant fluid in a settling phase when the emulsion is deasphalted.
Alternatively, the
deasphalting unit may comprise primary separation and secondary separation.
Deasphalting may
occur within the deasphalting unit by mixing the deasphalting solvent with the
hydrocarbon-external
emulsion and directing the mixture into a primary settling vessel to produce a
primary overflow and
a primary underflow; introducing the primary overflow into a solvent recovery
unit to produce the
cleaned bitumen product and to recover the deasphalting solvent. Optionally,
the primary
underflow may be introduced into a secondary settling vessel with the
deasphalting solvent from
the solvent recovery unit, to recovery deasphalting solvent and a secondary
underflow.
Deasphalting solvent derived from the secondary settling vessel may be used as
the deasphalting
solvent for mixing with the hydrocarbon-external emulsion.
[00157] The process may additionally comprise adding water, additives, or a
combination
thereof, to the primary settling vessel. Further, the secondary underflow may
be introduced into a
tailings solvent recovery unit to produce tailings and to recover deasphalting
solvent. The
deasphalting solvent from the tailings solvent recovery unit may be recycled
into the secondary
settling vessel.
[00158] In embodiments of the process, the ratio of the deasphalting solvent
to bitumen of
the secondary settling vessel may be about 10:1 or greater, which minimizes
bitumen lost in the
secondary underflow. The deasphalting solvent may be a paraffinic solvent.
[00159] There is also described herein a further process for removing solids
from oil sands
comprising bitumen and solids which involves mixing oil sands with a first
solvent to form an oil
sands slurry, wherein the amount of the first solvent added is greater than 10
wt% of the oil sands.
A majority of the solids are then separated from the oil sands slurry to form
a solids-rich stream
and an initial bitumen-rich stream, wherein the initial bitumen-rich stream
comprises residual solids.
The first solvent is then removed from the initial bitumen-rich stream to form
a solvent depleted
bitumen-rich stream; and at least a portion of the solvent-depleted bitumen-
rich stream is directed
to a paraffinic froth treatment process of a water-based extraction process. A
fungible bitumen
product can then be derived from the paraffinic froth treatment process.
Optionally, the process
may comprise mixing oil sands with water, wherein the amount of water added is
greater than 50
wt% of the oil sands, and forming bitumen froth, wherein the bitumen froth
comprises bitumen,
solids and water; and directing the bitumen froth and a second solvent to
paraffinic froth treatment.
[00160] The residual solids within the initial bitumen-rich stream may be less
than 2 wt% of
the mass content of the initial bitumen-rich stream. Further, the second
solvent may be a paraffinic
solvent or a mixture thereof.

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CA 02740481 2011-05-17

[00161] According to one embodiment, the paraffinic froth treatment process
may occur
within a first froth settling unit (FSU 1) and a second froth settling unit
(FSU 2). The solvent-
depleted bitumen-rich stream may be mixed with the bitumen froth before being
directed to the
FSU 1. The solvent-depleted bitumen-rich stream may be mixed with overflow of
FSU 1.
Optionally, the second solvent can be removed from the overflow of FSU 1 prior
to mixing with the
solvent-depleted bitumen-rich stream. Further, the solvent-depleted bitumen-
rich stream can be
mixed with the underflow of FSU 1. The solvent-depleted bitumen-rich stream
can optionally be
mixed with the overflow of FSU 2.
[00162] A fungible bitumen product so formed may have a solids content of less
than 300
wppm on a bitumen basis.
[00163] A bridging liquid, such as for example water, may be added to the oil
sands slurry to
agglomerate fines within the oil sands slurry.
[00164] According to certain embodiments, the first solvent and the second
solvent can be
the same.
[00165] (F) Directing Solvent Extracted Bitumen Product to Water-based
Extraction
Processes
[00166] A process is described herein for recovering hydrocarbon from oil
sands. The
process includes contacting a first oil sands ore with a solvent to form a
solvent-based slurry
comprising solids and a bitumen extract; separating the solids from the
solvent-based slurry to
produce a low solids bitumen extract; removing solvent from the low solids
bitumen extract to form
a solvent extracted bitumen product; contacting a second oil sands ore with
water to form an
aqueous slurry; mixing the solvent extracted bitumen product with the aqueous
slurry to form a
bitumen enriched slurry; and recovering bitumen from the bitumen enriched
second slurry.
[00167] Optionally, the aqueous slurry comprises a water-based extraction
stream upstream
of primary separation in a water-based extraction process, for example a
middlings stream of
primary separation in a water-based extraction process. Alternatively, the
aqueous slurry may
comprise a tailings stream of primary, secondary or tertiary separation in a
water-based extraction
process.
[00168] The solvent extracted bitumen product may be mixed with process water
prior to
mixing with the aqueous slurry.
[00169] The solvent-based slurry may be mixed with a bridging liquid, such as
process
water, to agglomerate solids within the solvent-based slurry.
[00170] Recovery of bitumen may occur within a settling vessel, or within
flotation cells.
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CA 02740481 2011-05-17

[00171] The step of mixing the solvent extracted bitumen product with the
aqueous slurry
may occur upstream of froth treatment. Optionally, the step of mixing the
solvent extracted
bitumen product with the aqueous slurry can occur within a hydrotransport
pipeline.
[00172] (G) Directing Solvent Extracted Tailings to Water-Based Extraction
Process
[00173] There is described herein a process for extracting hydrocarbon from
oil sands ore,
the process comprising contacting the ore with a first solvent to form a first
slurry comprising solids
and a bitumen extract; separating the bitumen extract from the first slurry to
form solvent wet
tailings comprised of the solids and the first solvent; removing the first
solvent from the solvent wet
tailings to form dry tailings; and combining said dry tailings with water wet
tailings produced from a
water-based extraction process to form strengthened tailings. In this process,
the dry tailings
comprise a water content of less than 15 wt% and the water wet tailings
comprise a water content
of more than 25 wt%.
[00174] The solvent wet tailings may be washed with a second solvent producing
washed
solids. The first solvent and second solvent may be removed from the washed
solids to form the
dry tailings. The second solvent is a paraffinic solvent of carbon number C7
or less.
[00175] A bridging liquid, such as process water optionally including dissolve
salts, can be
added to the first slurry so as to agglomerate some or all the solids within
the first slurry to form an
agglomerated slurry comprising agglomerated solids and a bitumen extract.
According to one
optional embodiment, the bridging liquid may be water with water-soluble
adhesives and/or
emulsion type adhesives.
[00176] The dry tailings may comprise precipitated asphaltenes.
[00177] The process may further comprise adding water-soluble adhesives and/or
emulsion
type adhesives to the solvent wet tailings. Also, the process may include
adding water-soluble
adhesives and/or emulsion type adhesives to the dry tailings.
[00178] Optionally, the dry tailings are sintered at a high temperature prior
to forming
strengthened tailings. Dry tailings may be heat treated at a temperatures
greater than 500 C.
[00179] The water wet tailings may optionally be thickened fine tailings from
a water-based
extraction process, such as for example, the underflow from a high rate or
paste thickener.
Alternatively, the water wet tailings may be mature fine tailings from a water-
based extraction
process, or may be non-segregating tailings from a water-based extraction
process. The non-
segregating tailings, if utilized, may comprise a mixture of thickened fine
tailings and coarse tailings
produced within a water-based extraction process. Further, the non-segregating
tailings may
comprise a mixture of mature fine tailings and coarse tailings produced within
a water-based

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CA 02740481 2011-05-17

extraction process. The water wet tailings may be partially dewatered prior to
mixing with dry
tailings. Such dry tailings may be sintered at a temperature greater than 500
C.
[00180] Strengthened tailings may be ones having, for example, a strength of 5
kPa or
greater. The strengthened tailings may be treated with a coagulant, and/or may
also be treated so
as to lower the pH of the strengthened tailings.
[00181] The water wet tailings may optionally be sprayed onto the dry tailings
to combine
the dry and wet tailings. Further the dry tailings and water wet tailings may
be mixed to form
agglomerates comprising solids from the water wet tailings.
[00182] The dry tailings may be used as mine construction material, in mine
refill, and/or in
direct reclamation of land.
[00183] In the process described, the oil sands ore may be a low grade of oil
sands ore with
high fines content.
[00184] Before discussing additional details, under sections (A) to (G) below,
the ways in
which integration of solvent-based extraction processes with water-based
extraction processes can
be achieved, exemplary non-limiting solvent-based extraction processes will be
described.

[00185] Overview of Exemplary Solvent-Based Extraction Processes Involving
Agglomeration
[00186] Exemplary processes of solvent-based extraction are described in
Canadian Patent
Application No. 2,724,806, filed December 10, 2010 and entitled: "Processes
and Systems for
Solvent Extraction of Bitumen from Oil Sands". Processes for solvent-based
extraction of a
bituminous feed, as described in this document, employing fines agglomeration
are briefly described
below. Solvent-based extraction processes which may be integrated with water-
based extraction
processes according to the processes described herein are not limited to the
process described
below, but may also extend to solvent-based processes described above in the
background section,
or any other process that relies upon solvent, as opposed to water, as a basis
for extracting bitumen
from oil sands.
[00187] As described in Canadian Patent Application No. 2,724,806, to extract
bitumen from
oil sands in a manner that employs solvent, a solvent is combined with a
bituminous feed derived
from oil sand to form initial slurry. Separation of the initial slurry into a
fine solids stream and coarse
solids stream may be followed by agglomeration of solids from the fine solids
stream to form an
agglomerated slurry. The agglomerated slurry can be separated into
agglomerates and a low solids
bitumen extract. Optionally, the coarse solids stream may be reintroduced and
further extracted in
the agglomerated slurry. A low solids bitumen extract can be separated from
the agglomerated

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CA 02740481 2011-05-17

slurry for further processing. Optionally, the mixing of a second solvent with
low solids bitumen
extract to extract bitumen may take place, forming a solvent-bitumen low
solids mixture, which can
then be separated further into a low grade and high grade bitumen extracts.
Recovery of solvent
from the low grade and/or high grade extracts is conducted, to produce bitumen
products of
commercial value.
[00188] In an exemplary embodiment of solvent-based extraction, a bituminous
feed is
combined with a first solvent having entrained bitumen. A slurry system is
employed to form the
initial slurry, which system may include a mixing vessel, such as a mix box, a
pump or a
combination thereof, having a feed section with gas blanket that provides a
low oxygen
environment. Steam can be added to the slurry system to heat the initial
slurry to a level of, for
example, 0 to 60 C. The initial slurry can be separated in a fine/coarse
solids separator to form a
fine solids stream that is directed into an agglomerator, as well as a coarse
solids stream which may
optionally join with the agglomerated slurry arising from the agglomerator for
further processing.
[00189] The first solvent, having bitumen entrained therein, may be derived
from downstream
recycling of the first solvent. This solvent can be added to the agglomerator
in order to achieve a
desired ratio of solvent:bitumen within the agglomerator. A desirable ratio
may be one that limits
precipitation of asphaltenes within the agglomerator, such as less than 2:1.
[00190] For fine/coarse solids separation, a settling vessel, cyclone or
screen may be used,
or any other suitable separation device. An aqueous bridging liquid, such as
water, may optionally
be added during agglomeration in the interests of achieving good adherence of
fines into larger
particles while agitation occurs. The agglomerated slurry formed comprises
agglomerates that can
be separated from a low solids bitumen extract. In the instance where coarse
solids stream is
combined with the agglomerated slurry, some residual bitumen adhering to the
coarse solids may
become entrained in the low solids bitumen extract, and thus can be recovered.
In order to
separate solids from the low solids bitumen extract, the slurry can be sent to
solid-liquid separation.
Primary means of separation may involve deep cone settlers, incline plate
(lamella) settlers, or other
clarification devices.
[00191] Once separated from the solids, the low solids bitumen extract can be
combined in a
mixer with a solvent that can be the same or different from the solvent used
in forming the initial
slurry. Optionally, the low solids bitumen extract can be sent to a solvent
recovery unit, to recover
solvent therefrom, before any subsequent mixing with a different solvent is
undertaken within the
mixer. In instances where the solvent used in the mixer used is different from
the earlier (or "first")
solvent, the different (or "second") solvent may be one having a low boiling
point. The bitumen-
containing mixture derived from the mixer may be separated using a gravity
separator such as a

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CA 02740481 2011-05-17

clarifier or other separator capable of separating solids and water. Streams
arising from the gravity
separator are directed to a solvent recovery unit, following which a high
grade bitumen product can
be formed. Further, underflow of the gravity separator, from which solvent is
recovered, forms a low
grade bitumen product. The solvent recovered can be re-used in the process,
with or without
bitumen entrained therein. When the second solvent differs from the first due
to its volatility and low
boiling point, it can readily be recovered according to these characteristics.
[00192] The agglomerates separated from the agglomerated slurry can also be
utilized, and
subjected to subsequent solid-liquid separator, permitting recovery of solvent
and bitumen
therefrom. Solvent derived agglomerates may also be recycled. Washing of
agglomerates may be
conducted using a belt filter with countercurrent washing using progressively
cleaner solvent.
Additional quantities of solvent can be used if needed. Tailings may be
recovered in a tailings
solvent recovery unit (TSRU) so that agglomerated tailings can be separated
from solvent or any
recoverable water present.
[00193] A stream containing solvent plus bitumen, arising from the secondary
solid-liquid
separation of agglomerates can be processed with the intent of achieving a
bottom sediment and
water (BS&W) content lower than about 0.5 wt% solid in dry bitumen. For
example, the product
could have less than 400 wppm solids. This stream may be utilized
commercially, or recycled back
into the solvent-based extraction process by including it in the agglomerator
or slurry system as a
way of providing solvent while maintaining the desired solvent:bitumen ratio
within the agglomerator,
in efforts to avoid precipitation of asphaltenes.
[00194] Solvents used in the process include low boiling point solvents such
as low boiling
point cycloalkanes, or a mixture of such cycloalkanes, which substantially
dissolve asphaltenes. The
solvent may comprise a paraffinic solvent in which the solvent to bitumen
ratio is maintained at a
level to avoid precipitation of asphaltenes. In the case where a second
solvent is used that differs
from the first solvent added to the slurry system, the second solvent may
comprise low boiling point
n- or iso-alkanes and alcohols or blends of these.
[00195] Solvent-based extraction processes to recover bitumen from oil sands
are described,
employing solvent extraction and sequential agglomeration of fines to
advantageously simplify
subsequent solid-liquid separation. The processes can produce at least one
bitumen product with a
quality specification of water and solids that exceeds downstream processing
and pipeline
transportation requirements and contains low levels of solids and water.
Further, systems for
implementing such processes are described.
[00196] The use of low boiling point solvents advantageously permits recovery
of solvent with
a lower energy requirement than would be expended for recovery of high boiling
point solvents. By
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conducting solvent extraction and agglomeration steps independently, shorter
residence times in the
agglomeration unit can be achieved. The sequential nature of the process
allows for flexible design
of a slurry feed system which permits high throughput from a smaller sized
agglomeration unit, as
well as faster bitumen production.
[00197] When the optional step of steam pre-conditioning is employed in the
process, this
realizes the further advantage that steam not only heats the slurry or oil
sands, but adds the water
necessary for the later agglomeration process.
[00198] Advantageously, the described processes permit formation of bitumen
products with
an acceptable composition for sale or processing at a remote refinery, and
thus these products need
not be processed by an onsite upgrader.
[00199] The bitumen product formed can be utilized in its current form, or
further processed
as necessary to meet and/or exceed quality specifications of low water content
and low solids
content required for pipeline transport and downstream processing. The
processes described
herein permit different levels and qualities of bitumen to be formed. Premium,
dry and clean
bitumen to be obtained as well as a lower grade bitumen (which in certain
cases may comprise
primarily of asphaltenes) for various commercial uses.
[00200] A bitumen product could be formed containing less than about 400 wppm
solids on a
bitumen basis, for example less than about 300 wppm solids, less than about
200 wppm solids, or
less than about 100 wppm solids, according to the processes described.
Further, a product formed
by the process described herein may contain about 0.5 wt% or less of combined
water plus solids of
the dry weight of bitumen product. For example, a bitumen product containing
0.4 wt% or less, 0.3
wt% or less, 0.2 wt% or less, or 0.1 wt% or less of combined water and solids
can be produced.
Water content, if evaluated alone, may be less than or equal to 200 wppm in
the final bitumen
product. This is an improved result compared with the 0.2 - 0.5 wt% of solids
in dry bitumen that can
be achieved according to the previously described SESA process of Govier and
Sparks. A bitumen
product having 300 wppm solids or less, is considered to be a high grade
fungible bitumen product.
As used herein, wppm may be found to be interchangeable with the abbreviation
ppm, which can be
assumed to be parts per million when evaluated on a weight basis.
[00201] There are a variety of ways in which the solvent extraction and
agglomeration can be
conducted according to the process described in Canadian Patent Application
No. 2,724,806. For
example, in one embodiment, a first solvent is added prior to agglomeration,
an initial slurry is
formed, which is then agglomerated through mixing to form an agglomerated
slurry. A low solids
bitumen extract is separated from the agglomerated slurry, and is subsequently
mixed with a second
solvent to further extract bitumen. While the second solvent is one having a
similar or lower boiling

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point than the first solvent. Gravity separation and other downstream
processes may be used to
separate bitumen and recycle solvent. Agglomerates can be washed using counter
current
washing, for example on a belt filter, with progressively cleaner solvent
(having dissolved bitumen
therein). In another embodiment the second solvent may be added prior to
separating low solids
bitumen extract from the agglomerated slurry. Coarse solids may be removed
from the initial slurry
prior to agglomeration and can then be processed separately, or reintroduced
and mixed with
agglomerates for further processing. Alternatively the initial slurry may
simply be directed to
agglomeration without removal of coarse solids.
[00202] Systems described in Canadian Patent Application No. 2,724,806
comprise a variety
of components, such as a fine/coarse solids separator and a gravity separator.
Specifically, such a
system includes a slurry system for mixing the bituminous feed with a first
solvent to form the initial
slurry. Optionally, a fine/coarse solids separator, in fluid communication
with the slurry system,
receives the initial slurry and separates fine solids and coarse solids.
However, it is possible to
allow fine and coarse solids to proceed to agglomeration without separation.
The system includes
an agglomerator for receiving the fine solids stream from the fine/coarse
solids separator (when
present), for agglomerating solids and producing an agglomerated slurry. A
primary solid-liquid
separator is present in the system for separating the agglomerated slurry into
agglomerates and a
low solids bitumen extract. A gravity separator is present in the system for
receiving the low solids
bitumen extract and a second solvent. A primary solvent recovery unit is
included, for recovering
solvent.
[00203] Ratio of Solvent to Bitumen in Initial Slurry. The process may be
adjusted to
render the ratio of the first solvent to bitumen in the initial slurry at a
level that avoids precipitation of
asphaltenes during agglomeration.
[00204] Some amount of asphaltene precipitation is unavoidable, but by
adjusting the amount
of solvent flowing into the system, with respect to the expected amount of
bitumen in the bituminous
feed, when taken together with the amount of bitumen that may be entrained in
the solvent used,
can permit the control of a ratio of solvent to bitumen in the slurry system
and agglomerator. When
the solvent is assessed for an optimal ratio of solvent to bitumen during
agglomeration, the
precipitation of asphaltenes can be minimized or avoided beyond an unavoidable
amount. Another
advantage of selecting an optimal solvent to bitumen ratio is that when the
ratio of solvent to
bitumen is too high, costs of the process may be increased due to increased
solvent requirements.
[00205] Solvent used in extraction processes described herein containing
dissolved or
entrained bitumen may be referenced interchangeably as "liquor" or "extraction
liquor". which is a

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term that encompasses the solvent together with any bitumen entrained or
dissolved therein,
regardless of the quantity or ratio of solvent to bitumen.
[00206] An exemplary ratio of solvent to bitumen to be selected as a target
ratio during
agglomeration is less than 2:1. A ratio of 1.5:1 or less, and a ratio of 1:1
or less, for example, a ratio
of 0.75:1, would also be considered acceptable target ratios for
agglomeration. For clarity, ratios
may be expressed herein using a colon between two values, such as "2:1 ", or
may equally be
expressed as a single number, such as "2", which carries the assumption that
the denominator of
the ratio is 1 and is expressed on a weight to weight basis.
[00207] Slurry System. The slurry system in which the slurry is prepared in
the system may
optionally be a mix box, a pump, or a combination of these. By slurrying the
first solvent together
with the bituminous feed, and optionally with additional additives, the
bitumen entrained within the
feed is given an opportunity to become extracted into the solvent phase prior
to the downstream
separation of fine and coarse solid streams and prior to agglomeration within
the agglomeration. In
some prior art processes, solvent is introduced at the time of agglomeration,
which may require
more residence time within the agglomerator, and may lead to incomplete
bitumen dissolution and
lower overall bitumen recovery. The slurry system advantageously permits
contact and extraction of
bitumen from solids within the initial slurry, prior to agglomeration. Forming
an initial slurry prior to
agglomeration advantageously permit flexible design of the slurry system and
simplifies means of
feeding materials into the agglomerator.
[00208] Bridging Liquid. A bridging liquid is a liquid with affinity for the
solids particles in the
bituminous feed, and which is immiscible in the first solvent. In some
embodiments, the
agglomerating of solids comprises adding an aqueous bridging liquid to the
fine solids stream and
providing agitation. Exemplary aqueous liquids may be recycled water from
other aspects or steps
of oil sands processing. The aqueous liquid need not be pure water, and may
indeed be water
containing one or more salt, a waste product from conventional aqueous oil
sand extraction
processes which may include additives, aqueous solution with a range of pH, or
any other
acceptable aqueous solution capable of adhering to solid particles within an
agglomerator in such a
way that permits fines to adhere to each other. An exemplary bridging liquid
is water. The bridging
liquid may be referred to interchangeably herein as a "binding liquid".
[00209] Heating Bituminous Feed With Steam. According to an embodiment of the
process, steam may be added to the bituminous feed before combining with the
first solvent, to
increase the temperature of the bituminous feed to a temperature of from about
0 C to about 60 C.
Steam may be of particular benefit when oil sands are mined in cold
conditions, such as during
winter time. The steam may be added to heat the oil sands or other bituminous
feed to a

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temperature of from about 0 C to about 30 C. The temperatures recited here
are simply
approximate upper and lower values. Because these are exemplary ranges,
provided here primarily
for illustration purposes, it is emphasized that values outside of these
ranges may also be
acceptable. A steam source for pre-conditioning the initial slurry entering
the separator may be an
optional component of the system. Other methods of heating the bituminous feed
or the solvent (or
solvent/bitumen combination) used to form the initial slurry may be
incorporated into the process.
[00210] During the winter, a bituminous feed may be at a low temperature below
0 C due to
low temperature of the ambient outdoor surroundings, and the addition of steam
to heat the feed to
a level greater than 0 C would be an improvement over a colder temperature.
During hot summer
conditions, the temperature of the bituminous feed may exceed 0 C, in which
case, it may not be
beneficial to heat the bituminous feed. Addition of steam may be desirable for
processing efficiency
reasons, and it is possible that the upper limit of the ranges provided may be
exceeded.
[00211] The optional step of steam pre-conditioning of the oil sands before
making contact
with solvent in the slurry system has the beneficial effect of raising the
temperature of the input
bituminous feed. The amount of steam added is lower or equal to the amount of
water required for
agglomeration. Slurrying the input feed with a low boiling point solvent is
promoted without the use
of a pressurized mixing system. Since steam pre-conditioning permits the use
of low boiling point
solvents, higher level of solvent recovery from tailings can be realized with
reduced energy intensity
relative to conventional processes.
[00212] During the winter, incoming oil sands may be about -3 C. At this
temperature, the
separation process would require more heat energy to reach the process
temperatures between
about 0 C and 60 C, or more particularly for an exemplary processing
temperature of about 30 C.
Optimally, a solvent boiling point is less than about 100 C. For a low
boiling point solvent, this
heating obtained through steam pre-conditioning is adequate to meet the
processing requirement.
For example, by heating the oil sands in a pre-conditioning step, a
temperature can be achieved that
is higher than could be achieved by heating the solvent alone, and adding it
to a cold bituminous
feed. In this way, optimal process temperatures can be achieved without any
need to use a
pressurized mixing system for solvent heating. Therefore, the steam not only
provides water, but
also some of the heating required to bring the components of the initial
slurry to a desired
temperature.
[00213] Once included as steam in a pre-conditioning step, the water content
of the initial
slurry would optimally be about 11 wt% or less, and when expressed as a
percent of solids, about
15 wt% is an upper limit to the optimal level.

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[00214] The steam pre-conditioning need not occur, as it is optional. Some
water may be
added at the agglomeration step if it is not added through steam pre-
conditioning. In instances
where steam pre-conditioning is used, optimally about half of the water
requirement is added as
steam, and further amounts of water can be added when the fine solids stream
is transferred into
the agglomerator.
[00215] In embodiments in which no steam pre-conditioning is employed, a
slurry comprising
the bituminous feed together with the first solvent may be prepared within the
slurry system.
Optionally, a solvent vapor could be added to the bituminous feed in the
slurry stage to capture the
latent heat at atmospheric pressure without need to pressurize the mixing
vessel.
[00216] Low Oxygen for Initial Slurry. The initial slurry of the process
described herein
may optionally be formed in a low oxygen environment. A gas blanket may be
used to provide this
environment, or steam may be used to entrain oxygen away from the bituminous
feed prior to
addition of solvent. The gas blanket, when used, may be formed from a gas that
is not reactive
under process conditions. Exemplary gasses include, but are not limited to
nitrogen, methane,
carbon dioxide, argon, steam, or a combination thereof.
[00217] Separation of Fine Solids Stream and Coarse Solids Stream. The
processes
described herein may involve separation of a fine solids stream from a coarse
solids stream from
the initial slurry after it is mixed in a slurry system. This aspect of the
process may be said to occur
within a fine/coarse solids separator. An exemplary separator system may
include a cyclone, a
screen, a filter or a combination of these. The size of the solids separated,
which may determine
whether they are forwarded to the fine solids stream versus the coarse solids
stream can be
variable, depending on the nature of the bituminous feed. Whether a bituminous
feed contains
primarily small particles and fines, or is coarser in nature may be taken into
consideration for
determining what size of particles are considered as fine solids and directed
toward agglomeration.
Notably, embodiments of the process described herein do not require separation
of coarse and fine
solids from the initial slurry. In such instances, both coarse and fine solids
will be present in the
agglomerator. When separation of coarse and fine solids is desired, a typical
minimum size to
determine whether a solid is directed to the coarse solids stream would be
about 140 microns. Fines
entrainment in the coarse stream is unavoidable during this separation. The
amount of fines
entrained in the coarse solids stream is preferably less than 10 wt%, for
example, less than 5 wt%.
[00218] Fine/Coarse Solids Separator. A coarse solids stream derived from the
fine/coarse
solids separator may be derived from the system. When the fine/coarse solids
separator is present,
the coarse solids stream may be directed for combination with the agglomerated
slurry arising from
the agglomerator prior to entry of the slurry into the solid-liquid separator.

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[00219] The feed stream entering the agglomerator unit is pre-conditioned to
separate out
coarse particles before entry into the agglomerator unit. Thus, the stream
entering the agglomerator
is predominantly comprised of finely divided particles or a "fine solids
stream". The slurry fraction
containing predominantly coarse particles or the "coarse solids stream" may by-
pass the
agglomerator unit and can then be combined with the agglomerated slurry before
the solid-liquid
separation stage in which low solids bitumen is extracted from the
agglomerated slurry.
[00220] A fine solids stream is processed separately from the coarse solids
stream, in part
because coarse solids are readily removed and need not be subjected to the
processing within the
agglomerator. The separator permits separation of a fine solids stream as a
top stream that can be
removed, while the coarse solids stream is a bottom stream flowing from the
separator.
[00221] The coarse solids fraction derived from the separator may be combined
with the
effluent arising from the agglomerator, as the coarse solids together with the
agglomerates will be
removed in a later solid-liquid separation step. This would permit recovery of
bituminous
components that were removed in the coarse solids stream.
[00222] Re-combining Coarse Solids with Agglomerated Slurry. It is optional in
the
process to utilize the coarse solids stream derived from the fine/coarse
solids separator by re-
combining it with the agglomerated slurry prior to separating the low solids
bitumen extract from the
agglomerated slurry. Alternatively, the coarse solids stream may be processed
separately, or added
back into the slurry system for iterative processing.
[00223] Agglomeration. The step of agglomerating solids may comprise adding
steam to the
bituminous feed. The addition of steam may be beneficial to the bituminous
feed because it may
begin solids nucleation prior to the step of agglomerating.
[00224] The step of agglomerating solids may comprise adding water as bridging
liquid to the
fine solids stream and providing suitable mixing or agitation. The type and
intensity of mixing will
dictate the form of agglomerates resulting from the particle enlargement
process.
[00225] Agitation could be provided in colloid mills, shakers, high speed
blenders, disc and
drum agglomerators, or other vessels capable of producing a turbulent mixing
atmosphere. The
amount of bridging liquid is balanced by the intensity of agitation to produce
agglomerates of desired
characteristics. As an example of appropriate conditions for a drum or disc
agglomerator, agitation
of the vessel may typically be about 40% of the critical drum rotational speed
while a bridging liquid
is kept below about 20 wt% of the slurry. The agitation of the vessel could
range from 10% to 60%
of the critical drum rotational speed, and the bridging liquid may be kept
between about 10 wt% to
about 20 wt% of solids contained in the slurry, in order to produce compact
agglomerates of
different sizes.

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[00226] Solvents. Two solvents, or solvent systems, are sequentially employed
in this
process. The terms "first solvent" and "second solvent" as used herein should
be understood to
mean either a single solvent, or a combination of solvents which are used
together in a first solvent
extraction and a second solvent extraction, respectively.
[00227] While the stage of the process at which the solvent is introduced can
be used to
determine whether a solvent is the first or second solvent, as the sequential
timing of the addition
into the process results in the designations of first and second.
[00228] It is emphasized that the first and second solvents are not required
to be different
from each other. There are embodiments in which the first solvent and second
solvent are the same
solvent, or are combinations which include the same solvents, or combinations
in which certain
solvent ingredients are common to both the first and second solvents.
[00229] While it is not necessary to use a low boiling point solvent, when it
is used, there is
the extra advantage that solvent recovery through an evaporative process
proceeds at lower
temperatures, and requires a lower energy consumption. When a low boiling
point solvent is
selected, it may be one having a boiling point of less than 100 C.
[00230] The solvents may also include additives. These additives may or may
not be
considered a solvent per se. Possible additives may be components such as de-
emulsifying agents
or solids aggregating agents. Having an agglomerating agent additive present
in the bridging liquid
and dispersed in the first solvent may be helpful in the subsequent
agglomeration step. Exemplary
agglomerating agent additives included cements, fly ash, gypsum, lime, brine,
water softening
wastes (e.g. magnesium oxide and calcium carbonate), solids conditioning and
anti-erosion aids
such as polyvinyl acetate emulsion, commercial fertilizer, humic substances
(e.g. fulvic acid),
polyacrylamide based flocculants and others. Additives may also be added prior
to gravity
separation with the second solvent to enhance removal of suspended solids and
prevent
emulsification of the two solvents. Exemplary additives include methanoic
acid, ethylcellulose and
polyoxyalkylate block polymers.
[00231] While the solvent extractions may be initiated independently, there is
no requirement
for the first solvent to be fully removed before the second solvent extraction
is initiated.
[00232] When it is said that the first solvent and the second solvent may have
"similar" boiling
points, it is meant that the boiling points can be the same, but need not be
identical. For example,
similar boiling points may be ones within a few degrees of each other, such
as, within 5 degrees of
each other would be considered as similar boiling points. The first solvent
and the second solvent
may be the same according to certain embodiments, in which case, having
"similar" boiling points
permits the solvents used to have the same boiling point.

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CA 02740481 2011-05-17

[00233] First Solvent. The first solvent selected according to certain
embodiments may
comprise an organic solvent or a mixture of organic solvents. For example, the
first solvent may
comprise a paraffinic solvent, an open chain aliphatic hydrocarbon, a cyclic
aliphatic hydrocarbon, or
a mixture thereof. Should a paraffinic solvent be utilized, it may comprise an
alkane, a natural gas
condensate, a distillate from a fractionation unit (or diluent cut), or a
combination of these containing
more than 40% small chain paraffins of 5 to 10 carbon atoms. These embodiments
would be
considered primarily a small chain (or short chain) paraffin mixture. Should
an alkane be selected
as the first solvent, the alkane may comprise a normal alkane, an iso-alkane,
or a combination
thereof. The alkane may specifically comprise heptane, iso-heptane, hexane,
iso-hexane, pentane,
iso-pentane, or a combination thereof. Should a cyclic aliphatic hydrocarbon
be selected as the first
solvent, it may comprise a cycloalkane of 4 to 9 carbon atoms. A mixture of C4-
C9 cyclic and/or
open chain aliphatic solvents would be appropriate.
[00234] Exemplary cycloalkanes include cyclohexane, cyclopentane, or a mixture
thereof.
[00235] If the first solvent is selected as the distillate from a
fractionation unit, it may for
example be one having a final boiling point of less than 180 C. An exemplary
upper limit of the final
boiling point of the distillate may be less than 100 C.
[00236] A mixture of C4-010 cyclic and/or open chain aliphatic solvents would
also be
appropriate. For example, it can be a mixture of C4-C9 cyclic aliphatic
hydrocarbons and paraffinic
solvents where the percentage of the cyclic aliphatic hydrocarbon in the
mixture is greater than
50%.
[00237] Second Solvent. The second solvent may be selected to be the same as
or
different from the first solvent, and may comprise a low boiling point alkane
or an alcohol. The
second solvent, when different from the first solvent, may be one that
improves the washing of
agglomerates. Under certain circumstances, the second solvent is not selected
as one that can
cause deasphalting. For example, in embodiments described herein, a stream
derived from solvent-
based extraction may later be directed to a froth treatment process, or other
deasphalting process,
within a water-based extraction process. In such an embodiment, it is
undesirable to cause
deasphalting within the solvent-based extraction process (through selection of
the second solvent)
because deasphalting can be deferred to the later froth treatment stage.
Throughout embodiments
described herein, it is understood that in instances where the product of
solvent-based extraction is
later deasphalted and further cleaned in a water-based process (such as PFT),
the second solvent
utilized in solvent-based extraction should not be one that causes
deasphalting (product cleaning),
but rather should be selected to accomplish further washing and/or bitumen
extraction, without
effectively deasphalting the stream during the solvent-based extraction
process.

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CA 02740481 2011-05-17

[00238] The second solvent may have an exemplary boiling point of less than
100 C. In
some embodiments, the second solvent can be mixed with feed into the solid-
liquid separation
steps. Because the first solvent is not used in both agglomeration and the
solid-liquid separation
steps as described in prior art, a second solvent that is miscible with the
agglomerate bridging liquid
(for example, miscible with water) can be employed at the solid-liquid
separation stage. In other
words, the two processing steps can be conducted independently and without the
solid-liquid
separation disrupting the agglomeration process. Thus, selecting the second
solvent to be
immiscible in the first solvent, and/or having the ability to be rendered
immiscible after addition,
would be optional criteria.
[00239] The second solvent may comprise a single solvent or a solvent system
that includes
a mixture of appropriate solvents. The second solvent may be a low boiling
point, volatile, polar
solvent, which may or may not include an alcohol or an aqueous component. The
second solvent
can be C2 to C10 aliphatic hydrocarbon solvents, ketones, ionic liquids or
biodegradable solvents
such as biodiesel. The boiling point of the second solvent from the
aforementioned class of solvents
is preferably less than 100 C.
[00240] Process Temperatures. The process may occur at a wide variety of
temperatures.
In general, the heat involved at different stages of the process may vary. One
example of
temperature variation is that the temperature at which the low solids bitumen
extract is separated
from the agglomerated slurry may be higher than the temperature at which the
first solvent is
combined with the bituminous feed. Further, the temperature at which the low
solids bitumen
extract is separated from the agglomerated slurry may be higher than the
temperature at which
solids are agglomerated. The temperature increase during the process may be
introduced by
recycled solvent streams that are re-processed at a point further downstream
in the process. By
recycling pre-warmed solvent from later stages of the process into earlier
stages of the process,
energy required to heat recycle stream is lower and heat is better conserved
within the process.
Alternatively, the temperature of the dilution solvent may be intentionally
raised to increase the
temperature at different stages of the process. An increase in the temperature
of the solvent may
result in a reduced viscosity of mixtures of solvent and bitumen, thereby
increasing the speed of
various stages of the process, such as washing and/or filtering steps.
[00241] Solid-Liquid Separator. The agglomerated slurry may be separated into
a low solids
bitumen extract and agglomerates in a solid-liquid separator. The solid-liquid
separator may
comprise any type of unit capable of separating solids from liquids, so as to
remove agglomerates.
Exemplary types of units include a gravity separator, a clarifier, a cyclone,
a screen, a belt filter or a
combination thereof.

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[00242] The system may contain a solid-liquid separator but may alternatively
contain more
than one. When more than one solid-liquid separation step is employed at this
stage of the process,
it may be said that both steps are conducted within one solid-liquid
separator, or if such steps are
dissimilar, or not proximal to each other, it may be said that a primary solid-
liquid separator is
employed together with a secondary solid-liquid separator. When a primary and
secondary unit are
both employed, generally, the primary unit separates agglomerates, while the
secondary unit
involves washing agglomerates.
[00243] Secondary Stage of Solid-Liquid Separation to wash Agglomerates. As a
component of the solid-liquid separator, a secondary stage of separation may
be introduced for
countercurrently washing the agglomerates separated from the agglomerated
slurry. The initial
separation of agglomerates may be said to occur in a primary solid-liquid
separator, while the
secondary stage may occur within the primary unit, or may be conduced
completely separately in a
secondary solid-liquid separator. By "countercurrently washing", it is meant
that a progressively
cleaner solvent is used to wash bitumen from the agglomerates. Solvent
involved in the final wash
of agglomerates may be re-used for one or more upstream washes of
agglomerates, so that the
more bitumen entrained on the agglomerates, the less clean will be the solvent
used to wash
agglomerates at that stage. The result being that the cleanest wash of
agglomerates is conducted
using the cleanest solvent.
[00244] A secondary solid-liquid separator for countercurrently washing
agglomerates may be
included in the system or may be included as a component of a system described
herein. The
secondary solid-liquid separator may be separate or incorporated within the
primary solid-liquid
separator. The secondary solid-liquid separator may optionally be a gravity
separator, a cyclone, a
screen or belt filter. Further, a Secondary solvent recovery unit for
recovering solvent arising from
the solid-liquid separator can be included. The secondary solvent recovery
unit may be conventional
fractionation tower or a distillation unit.
[00245] The temperature for countercurrently washing the agglomerates may be
selected to
be higher than the temperature at which the first solvent is combined with the
bituminous feed.
Further, the temperature selected for countercurrently washing the
agglomerates may be higher
than the temperature at which solids are agglomerated.
[00246] When conducted in the process, the secondary stage for
countercurrently washing
the agglomerates may comprise a gravity separator, a cyclone, a screen, a belt
filter, or a
combination thereof.
[00247] Recycle and Recovery of Solvent. The process involves removal and
recovery of
solvent used in the process. In this way, solvent is used and re-used, even
when a good deal of
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CA 02740481 2011-05-17

bitumen in entrained therein. Because an exemplary solvent:bitumen ratio in
the agglomerator may
be 2:1 or lower, it is acceptable to use recycled solvent containing bitumen
to achieve this ratio. The
amount of make-up solvent required for the process may depend solely on
solvent losses, as there
is no requirement to store and/or not re-use solvent that have been used in a
previous extraction
step. When solvent is said to be "removed", or "recovered", this does not
require removal or
recovery of all solvent, as it is understood that some solvent will be
retained with the bitumen even
when the majority of the solvent is removed. For example, in steps of the
process when solvent is
recovered from a low grade or high grade bitumen extract leaving a bitumen
product, it is
understood that some solvent may remain within that product
[00248] The system may contain a single solvent recovery unit for recovering
the first and
second solvents arising from the gravity separator. The system may
alternatively contain more than
one solvent recovery unit. For example, another solvent recovery unit may be
incorporated before
the step of adding the second solvent to recover part or all of the first
solvent.
[00249] In order to recover either or both the first solvent or the second
solvent, conventional
means may be employed. For example, typical solvent recovery units may
comprise a fractionation
tower or a distillation unit. A primary and/or secondary solvent recovery unit
may be desirable for
use in the process described herein.
[00250] Solvent recovery and recycle is incorporated into embodiments of the
process. For
example, the first solvent derived from the slurry of agglomerated solids,
which may contain
bitumen, can be recycled in the process, such as at the slurrying or
agglomerating step. Further,
the second solvent may be recovered by using a solvent recovery unit and
recycled for addition to
the low solids bitumen extract.
[00251] Solvent recovery may be controlled to ensure that the second solvent
is added at the
appropriate time. For example, the first and second solvent may be recovered
by distillation or
mechanical separation following the solid-liquid separation step.
Subsequently, the first solvent may
be recycled to the agglomeration step while the second solvent is recycled
downstream of the
agglomerating step. In the exemplary embodiment where the second solvent is
immiscible with the
first solvent, the process will occur with no upset to the agglomeration
process since interaction of
the second solvent with the bridging liquid only occurs downstream of the
agglomerating step.
[00252] Heat entrained in recycled solvent can advantageously be utilized when
the solvent is
added to the process at different stages to heat that stage of the process, as
required. For example,
heated solvent with entrained bitumen derived from washing of the agglomerates
in the secondary
solid-liquid separator, may be used not only to increase the temperature of
the initial slurry in the
slurry system, but also to include a bitumen content that may be desirable to
keep the

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solvent:bitumen ratio at a desired level so as to avoid precipitation of
asphaltenes from solution
during agglomeration. By including heated solvent as well as bitumen, this
addition provides an
advantage to the agglomeration process.
[00253] The first solvent recovered in the process may comprise entrained
bitumen therein,
and can thus be re-used for combining with the bituminous feed; or for
including with the fine solids
stream during agglomeration. Other optional steps of the process may
incorporate the solvent
having bitumen entrained therein, for example in countercurrent washing of
agglomerates, or for
adjusting the solvent and bitumen content within the initial slurry to achieve
the selected ratio within
the agglomerator that avoids precipitation of asphaltenes.
[00254] Extraction Step is Separate from Agglomeration Step. Solvent
extraction may be
conducted separately from agglomeration in certain embodiments of the process.
Unlike prior art
processes, where the solvent is first exposed to the bituminous feed within
the agglomerator,
embodiments described herein include formation of an initial slurry in which
bitumen dissolution into
a solvent occurs prior to the agglomeration step. This has the effect of
reducing residence time in
the agglomerator, when compared to previously proposed processes which require
extraction of
bitumen and agglomeration to occur simultaneously. The instant process is
tantamount to
agglomeration of pre-blended slurry in which extraction via bitumen
dissolution is substantially or
completely achieved separately. Performing extraction upstream of the
agglomerator permits the
use of enhanced material handling schemes whereby flow/mixing systems such as
pumps, mix
boxes or other types of conditioning systems can be employed.
[00255] Because the extraction occurs upstream of the agglomeration step, the
residence
time in the agglomerator is reduced. One other reason for this reduction is
that by adding
components, such as water, some initial nucleation of particles that
ultimately form larger
agglomerates can occur prior to the slurry arriving in the agglomerator.
[00256] Figure 1 is a schematic representation of an embodiment of processes
(10)
described herein. The combining (11) of a first solvent and a bituminous feed
from oil sand to form
initial slurry is followed by separating (12) of a fine solids stream and
coarse solids stream from the
initial slurry. Agglomerating (13) of solids from fine solids stream then
occurs to form agglomerated
slurry comprising agglomerates and low solids bitumen extract, optionally
subsequently adding
coarse solids stream to agglomerated slurry. Subsequently, separation (15) of
low solids bitumen
extract from agglomerated slurry occurs. Further, mixing (16) of a second
solvent with low solids
bitumen extract to extract bitumen takes place, forming a solvent-bitumen low
solids mixture.
Separation (18) of low grade bitumen extract and high grade bitumen extracts
from the mixture

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occurs. Further, recovery (19) of solvent from the high grade extract is
conducted, leaving a high
grade bitumen product. Further details of these process steps are provided
herein.
[00257] Figure 2 outlines an embodiment of the processes described herein, in
which the
second solvent is mixed with a low solids bitumen extract derived from
separation of the
agglomerated slurry in a clarifier.
[00258] In this embodiment, a bituminous feed (202) is provided and combined
with a first
solvent (209a), which may contain entrained bitumen (203a), in a slurry system
(204) to form an
initial slurry (205). The slurry system (204) may be any type of mixing
vessel, such as a mix box,
pump or pipeline or combination thereof, having a feed section with gas
blanket that provides a low
oxygen environment. Steam (207) may be added to the slurry system (204) so as
to heat the initial
slurry (205) to a level of, for example, 0 to 60 C. The initial slurry (205)
is separated in a fine/coarse
solids separator (206) to form a fine solids stream (208), which is directed
into an agglomerator
(210), as well as a coarse solids stream (212), which later, optionally, joins
with the agglomerated
slurry (216) arising from the agglomerator (210) for further processing. The
fine/coarse solids
separator (206) may be a settling vessel, cyclone or screen, or any suitable
separation device
known in the art.
[00259] Bitumen (203b) which may be entrained in the first solvent (209b), for
example, as
derived from downstream recycling of the first solvent, may be added to the
agglomerator (210) in
order to achieve an optimal ratio of solvent to bitumen within the
agglomerator (210). Such a ratio
would be one that avoids precipitation of asphaltenes within the agglomerator
(210), and an
exemplary ratio may be less than 2:1.
[00260] An aqueous bridging liquid (214), such as water, may optionally be
added to the
agglomerator (210) in the interests of achieving good adherence of fines into
larger particles, and
the process of agglomeration of the solids contained within the fine solids
stream (208) occurs by
agitation within the agglomerator (210). The agglomerated slurry (216) arising
from the
agglomerator (210) comprises agglomerates (217a) together with a low solids
bitumen extract
(220a), all of which is optionally combined with the coarse solids stream
(212) in the event that the
coarse solids stream is directed to be combined at this stage. The slurry
(216) is then directed to
the primary solid-liquid separator (218), which may be a deep cone settler, or
other device, such as
thickeners, incline plate (lamella) settlers, and other clarification devices
known in the art.
[00261] The low solids bitumen extract (220b) is separated from the
agglomerated slurry
within the primary solid-liquid separator (218). This extract (220b) is
subsequently combined in a
mixer (221) with a second solvent (222a). Extract (220b) may optionally be
sent to a solvent

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recovery unit, not shown, where the first solvent is recovered from the
extract, before the mixing with
the second solvent (222a) is undertaken within the mixer (221).
[00262] The second solvent may be one having a low boiling point. The bitumen-
containing
mixture (223) obtained from the mixer (221) is separated in a gravity
separator (224), which may for
example be a clarifier or any other type of separator employing gravity to
separate solids and water.
Streams arising from the gravity separator (224) are the overflow (225), which
is directed toward
forming a high grade bitumen product (226) once the solvent has been extracted
in a solvent
recovery unit (228), and the underflow which may be removed as a low grade
bitumen extract (230),
which may then optionally have solvent removed to form a low grade bitumen
product. The solvent
recovery unit (228) may advantageously be used to recover any of the first
solvent (209c) remaining
within the effluent of the gravity separator (224), in the interests of
solvent recovery and re-use.
Advantageously, the second solvent (222b) is easily removed and recovered due
to its volatility and
low boiling point. There may be bitumen entrained in recovered solvents.
[00263] The agglomerates (217b) can also be utilized, as they leave the
primary solid-liquid
separator (218) and are subsequently subjected to a separation in a secondary
solid-liquid
separator (232), permitting recovery of the first solvent (209a) and bitumen
(203a) in the process.
First solvent (209c) derived from the solvent recovery unit (228) may also be
recycled to the
secondary solid-liquid separator (232), to wash agglomerates, for example in a
belt filter using
countercurrent washing with progressively cleaner solvent. Additional
quantities of first solvent
(209d) can be used if additional volumes of solvent are needed. Tailings may
be recovered in a
TSRU or tailings solvent recovery unit (234) so that agglomerated tailings
(236) can be separated
from recyclable water (238). Either or both the recovered first solvent (209e)
derived from the TSRU
(234) and/or from the solvent recovery unit (228) may be recycled in the
secondary solid-liquid
separator (232).
[00264] A combination containing the first solvent (209a) plus bitumen (203a)
arising from the
secondary solid-liquid separator (232) can be processed with the intent of
achieving a bottom
sediment and water (BS & W) content lower than about 0.5 wt% on a dry bitumen
basis. In
particular, the product would have less than 400 ppm solids. This combination
may also be recycled
back into the process by including it in the agglomerator (210) or slurry
system (204) as a way of
recycling solvent, and maintaining an appropriate solvent:bitumen ratio within
the agglomerator to
avoid precipitation of asphaltenes.
[00265] Advantageously, such processes as outlined in Figure 2 permit recovery
of both the
first solvent and the second solvent. In one embodiment, the first solvent may
be a low boiling point
solvent, such as a low boiling point cycloalkane, or a mixture of such
cycloalkanes, which

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substantially dissolves asphaltenes. The first solvent may also be a
paraffinic solvent in which the
solvent to bitumen ratio is maintained at a level to avoid precipitation of
asphaltenes.
[00266] For the second solvent, a low boiling point n- or iso-alkane and
alcohols or blends are
candidates. Surface modifiers may be added to the alcohol if needed. With the
alkanes, solvent
deasphalting is achieved with concurrent cleaning of the high grade bitumen
product (226) to
achieve pipeline quality. Therefore, the low grade bitumen extract (230) is
comprised predominantly
of asphaltenes or other more polar bitumen fractions.
[00267] Another advantage is that the process forms two different grades of
bitumen product
from the gravity separator (224). Specifically, partial product upgrading is
conducted to produce a
first product of high grade bitumen product (226). The low grade bitumen
extract (230) formed may
also be processed to a low grade bitumen product after solvent recovery, so as
to also possesses
some commercial value.
[00268] This process facilitates recovery of bitumen with no need for handling
more than one
solvent in the tailings loop of the TSRU (234), thereby allowing for
simplified solvent
recovery/recycling processes.
[00269] Figure 3 is a schematic representation of a further embodiment of a
process (30)
described herein. The combining (31) of a first solvent and a bituminous feed
from oil sand to form
the initial slurry is followed by separating (32) of a fine solids stream and
coarse solids stream from
the initial slurry. Agglomerating (33) of solids from fine solids stream then
occurs to form an
agglomerated slurry comprising agglomerates and low solids bitumen extract,
optionally
subsequently adding the coarse solids stream into the agglomerated slurry.
Further, mixing (36) of
a second solvent with the agglomerated slurry occurs, to extract bitumen,
forming a solvent-bitumen
agglomerated slurry mixture. Removal (37) of agglomerates from the mixture
then occurs.
Separation (38) of high grade and low grade bitumen extracts then occurs.
Further, recovery (39) of
the solvents from the bitumen extracts is conducted, leaving a high grade
bitumen product and a low
grade bitumen product. Further details of these process steps are provided
herein.
[00270] Figure 4 illustrates an embodiment of the processes described herein
which can be
characterized by the feature that the second solvent is mixed with the
agglomerated slurry upon
entry into the primary solid-liquid separator.
[00271] In this embodiment, a bituminous feed (402) is provided and is
combined with a first
solvent (409a), which may have bitumen (403a) entrained therein, into slurry
system (404) to form
an initial slurry (405), optionally in the presence of steam (407) to heat the
initial slurry (405). The
initial slurry (405) is mixed and the first solvent (409a) is given time to
contact the bituminous feed
so as to extract bitumen. The slurry (405) is then directed to a separator
(406) to form a fine solids
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CA 02740481 2011-05-17

stream (408) which is directed into an agglomerator (410). Further arising
from the separator (406)
is a coarse solids stream (412) for later processing and solid-liquid
separation.
[00272] A bridging liquid (414), such as water, is added to the agglomerator
(410), optionally
together with bitumen (403b) which may be entrained in the first solvent
(409b) as derived from
downstream solvent recovery. The process of agglomeration of the solids from
the fine solids
stream (408) occurs by agitation of the agglomerator. The agglomerated slurry
(416) arising from
the agglomerator (410) comprises agglomerates (417a) together with a low
solids bitumen extract
420a), all of which may be combined with the coarse solids stream (412) and
directed to a mixer
(421) so as to be combined prior to entry into the primary solid-liquid
separator (418). The
agglomerated slurry (416) is mixed with the second solvent (422a) to form a
solvent-bitumen
agglomerated slurry mixture (423) within the mixer, and is then separated
within the primary solid-
liquid separator (418), which may be a deep cone settler or any other sort of
separator.
Concurrently, the second solvent (422a) can be added to the primary solid-
liquid separator (418).
The second solvent (422a) may also be added to the mixer (421) before entry
into the primary solid-
liquid separator (418). The second solvent (422a) may be one having a low
boiling point, such as a
boiling point below 100 C, and is immiscible in the first solvent, or can be
rendered immiscible in
the first solvent.
[00273] The bitumen-containing mixture within the primary solid-liquid
separator (418) is
separated and either directed toward forming high grade bitumen product (426)
once the solvent
has passed through the separator (418) to form a high grade bitumen extract
(425) and has been
extracted in a primary solvent recovery unit (428), or can be directed toward
forming a low grade
bitumen product (430). Advantageously in this embodiment, the second solvent
(422b, 422c) is
easily removed and recovered due to its volatility, low boiling point, and
optionally due to its
immiscibility in the first solvent.
[00274] The agglomerates (417b) can also be processed as they leave the
primary solid-
liquid separator (418) and are subsequently subjected to a separation in a
secondary solid-liquid
separator (432), permitting recovery of the second solvent (422d), first
solvent (409c) and any
bitumen entrained therein in the process. Residual solvent in the tailings may
be recovered in a
TSRU or tailings solvent recovery unit (434) so that agglomerated tailings
(436) may be separated,
and optionally water (438) used in the process may be recovered and recycled.
[00275] The recovered first solvent (409d) arising from the primary solvent
recovery unit (428)
may be recycled for use in the process, for example when combined with the
bituminous feed (402)
in the separator (406). This recovered solvent may contain bitumen entrained
therein. Quantities of
a combination comprising recycled first solvent (409d) plus any entrained
bitumen arising from the

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CA 02740481 2011-05-17

primary solid-liquid separator (418) or solvent recovery unit (428) may be
directed to the
agglomerator (410) for further processing. The second solvent (422b) recovered
from the primary
solvent recovery unit (428) may be also be recycled.
[00276] Secondary recovery of bitumen occurs within the secondary solid-liquid
separator
(432). The separated low grade bitumen extract (450) may be subjected to
separation within a
secondary solvent recovery unit (444), which may be a distillation unit, to
recover and recycle the
second solvent (422g) and to arrive at a low grade bitumen product (430). The
low grade bitumen
product (430) possesses some commercial value, as it can be processed further
with the intent of
achieving a bottom sediment and water (BS&W) content lower than about 0.5 wt%
solid in dry
bitumen.
[00277] Solvent recovered may be held in a first solvent storage (429) in the
case of the first
solvent (409d), or in a second solvent storage (445), in the case of the
second solvent (422b, 422g)
for later use in the upstream aspects of the process. High grade bitumen (431)
may be added to the
first solvent derived from first solvent storage (429), if there is a need to
alter the solvent to bitumen
ratio prior to adding a combination of solvent (409a) and bitumen (403a) to
the slurry system (404).
Further, additional first solvent (409e) make-up quantities or second solvent
(422e) make-up
quantities may be included in respective solvent storage, if the solvent
volume requires replenishing.
Additional second solvent (422f) may also be added to the secondary solid-
liquid separator (432) if
needed.
[00278] This embodiment of the process forms different grades of bitumen
product and
advantageously permits recovery and/or recycling of both the first solvent and
the second solvent.
[00279] In this embodiment, the first solvent may be a low boiling point
cyclic aliphatic
solvent, such as a low boiling point cycloalkane, or a mixture of such
cycloalkanes, which
substantially dissolves asphaltenes. The first solvent may also be a
paraffinic solvent in which the
solvent to bitumen ratio is maintained at a level to avoid precipitation of
asphaltenes.
[00280] The second solvent may be a polar solvent, such as an alcohol, a
solvent with an
aqueous component, or another solvent which is immiscible in the first solvent
or which could be
rendered immiscible in the first solvent. A low boiling point n- or iso-alkane
and alcohols or blends of
these with or without an aqueous component are candidates. Surface modifiers
may be added to
the alcohol if needed. Good agglomerate strength is achieved if the
agglomerates are modified with
hydrating agents, such as a cement, a geopolymer, fly ash, gypsum or lime
during agglomeration.
Optionally, the second solvent may comprise a wetting agent in an aqueous
solution. A further
option is to employ controlled precipitation of asphaltenes within either the
agglomerator (410) or the
primary solid-liquid separator (418) by employing a mixture of solvent and
bitumen in a ratio that

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CA 02740481 2011-05-17

avoids precipitation of asphaltenes. For example, a ratio of solvent to
bitumen of 2:1 or less may be
used within the agglomerator to control asphaltene precipitation.
[00281] The embodiment depicted in Figure 4 results in enhanced liquid
drainage during
agglomerate washing when the second solvent comprises predominantly of polar
component, such
as an alcohol. Further, enhanced solvent recovery may be achieved, which
results in a more
environmentally benign tailings stream.
[00282] The product upgrading of low grade bitumen product (430) can be
undertaken to
produce a low grade product with some commercial value. If the commercial
value involves
alternate fuel applications, it would be possible to have a residual alcohol
content remaining in the
low grade bitumen product (430) from the second solvent. Generally, the low
grade bitumen
product (430) is comprised predominantly of asphaltenes or other more polar
bitumen fractions.
[00283] Figure 5 is a schematic representation of an additional embodiment of
the process
(50) described herein. The combining (51) of a first solvent and a bituminous
feed from oil sand to
form initial slurry is followed by separating (52) of a fine solids stream and
coarse solids stream from
the initial slurry. Recovery (54) of the first solvent from the coarse solids
stream is then conducted.
Agglomerating (53) of solids from the fine solids stream then occurs to form
agglomerated slurry
comprising agglomerates and low solids bitumen extract. In this embodiment,
the coarse solids
stream is not optionally added to the agglomerated slurry, as the coarse
solids stream is processed
separately. Subsequently, separation (55) of low solids bitumen extract from
agglomerated slurry
occurs. Further, mixing (56) of a second solvent with low solids bitumen
extract to extract bitumen
takes place, forming a solvent-bitumen low solids mixture. Separation (58) by
gravity of low grade
and high grade bitumen extracts from the mixture then occurs. Further,
recovery (59) of the
solvents is conducted, leaving a high grade bitumen product. Further details
of these process steps
are provided herein.
[00284] Figure 6 illustrates an embodiment similar to that depicted in Figure
2, except that
coarse solids stream separated out of the bituminous feed is processed
separately, and not re-
combined with an agglomerated slurry.
[00285] A bituminous feed (602) is provided and combined with a first solvent
(609a),
optionally with bitumen (603a) entrained therein, in a slurry system (604) to
form an initial slurry
(605). Steam (607) may be added to the slurry system (604) to heat the initial
slurry (605). The
initial slurry (605) is then directed from the slurry system (604) to a
separator (606) for separation,
which may be a fine/coarse solids separator, in order to form a fine solids
stream (608), which is
directed into an agglomerator (610), as well as a coarse solids stream (612),
which is processed
separately from the agglomerated slurry (616) arising from the agglomerator
(610). Additional

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CA 02740481 2011-05-17

quantities of first solvent (609b) having bitumen (603b) entrained therein,
may be added to the
agglomerator (610). A bridging liquid (614), such as water, may be added to
the agglomerator (610),
and the process of agglomeration of the solids contained within the fine
solids stream (608) occurs
by agitation within the agglomerator (610). The agglomerated slurry (616)
arising from the
agglomerator comprises agglomerates (617a) together with a low solids bitumen
extract (620a). In
this example, there is no combination with the coarse solids stream. Instead,
the agglomerated
slurry (616) itself is directed to the primary solid-liquid separator (618).
[00286] The low solids bitumen extract (620) is separated from the
agglomerated slurry (616)
within the primary solid-liquid separator (618). This extract (620) is
subsequently combined in a
mixer (621) with a second solvent (622a). Extract (620) may optionally be sent
to a solvent recovery
unit, not shown, where all of the first solvent contained therein is recovered
from the extract, before
mixing with the second solvent within the mixer (621).
[00287] The second solvent may be one having a low boiling point. The solvent-
bitumen low
solids mixture (623) derived from the mixer (621) is separated in a gravity
separator (624), and
streams arising from the gravity separator (624) are directed either toward
forming a high grade
bitumen product (626) once the solvent has been extracted in a solvent
recovery unit (628), or
toward forming a low grade bitumen extract (630). The solvent recovery unit
(628) may
advantageously be used to recover the majority of the first solvent (609d)
remaining within the
effluent, or overflow, of the gravity separator (624), in the interests of
solvent recovery and re-use.
Streams derived from the gravity separator (624) include high grade bitumen
extract (625), and low
grade bitumen extract (630) as underflow. Advantageously, the second solvent
(622b) is easily
removed and recovered due to its volatility and low boiling point.
[00288] The separated agglomerates (617b) can also be utilized, as they leave
the primary
solid-liquid separator (618) and are subsequently subjected to a separation in
a secondary solid-
liquid separator (632), permitting recovery of the first solvent (609c) and
bitumen (603c) entrained
therein in the process. Solvent (609d) derived from the solvent recovery unit
(628) may also be
recycled to the secondary solid-liquid separation separator (632). Additional
quantities of the first
solvent (609e) may be added to the secondary solid-liquid separator, if
desired, for example for
washing purposes. Tailings may be recovered in a TSRU or tailings separation
recovery unit (634)
so that agglomerated tailings (636) can be separated from recyclable water
(638). Either or both the
recovered first solvent (609g or 609d)) derived from the TSRU (634) and/or
from the solvent
recovery unit (628) may be recycled in the secondary solid-liquid separator
(632).
[00289] A combination containing the first solvent (609c) plus bitumen (603c)
arising from the
secondary solid-liquid separator (632) can be processed with the intent of
achieving a bottom

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CA 02740481 2011-05-17

sediment and water (BS&W) content lower than about 0.5 wt% solid in dry
bitumen. In particular,
the product may have less than 400 ppm solids. This combination containing the
first solvent plus
bitumen may also be recycled back into the process by including it in the
agglomerator (610) or
slurry system (604).
[00290] Advantageously, the process permits recovery of both the first solvent
and the
second solvent. In one embodiment, the first solvent may be a low boiling
point solvent, such as a
low boiling point cycloalkane, or a mixture of such cycloalkanes, which
substantially dissolves
asphaltenes. The first solvent may also be a paraffinic solvent in which the
solvent to bitumen ratio
is maintained at a level to avoid precipitation of asphaltenes.
[00291] For the second solvent, a low boiling point n- or iso-alkane and
alcohols or blends are
candidates. Surface modifiers may be added to the alcohol if needed. With the
alkanes, solvent
deasphalting is achieved with concurrent cleaning of the high grade bitumen
product (626) to
achieve pipeline quality. Therefore, the low grade bitumen extract (630) is
comprised predominantly
of asphaltenes or other more polar bitumen fractions.
[00292] In this embodiment, the coarse solid stream (612) derived from the
separator (606) is
kept segregated from the agglomerated slurry (616). Thus, the separator (606)
can be reduced in
size compared to the approach described with respect to Figure 2, as only
quick settling solids are
removed. These coarse solids may form the majority of the particulate,
especially for high grade oil
sands, and will exhibit high drainage rates in the secondary solid-liquid
separator for coarse solids
(652). The non-agglomerated nature of the coarse solids allows for efficient
solvent recovery of both
first solvent (609f) and bitumen (603f) entrained therein.
[00293] The agglomerated slurry (616) may thus enter a reduced size primary
solid-liquid
separator (618) and can be processed as described above in the secondary
liquid-solid separator
(632) and TSRU (634). Agglomerated tailings (636) can be removed using the
TSRU (634). The
rate determining step in solvent recovery from tailings is the time required
for release of residual
solvent from the pores of the agglomerated solids. With segregation, the
solvent recovery from the
fine particles can be optimized independent of the coarse particles. The
combination of first solvent
(609f) and bitumen (603f) recovered permits separation of coarse tailings
(656), once drained from
the secondary solid liquid separator for coarse solids (652). Coarse tailings
(656) isolated from the
tailings solvent recovery unit for coarse solids (654) can be sent to the
primary solid-liquid separator
(618) for residual fine solids removal, or may be recycled upstream of the
process to form the initial
slurry (605) in slurry system (604). The tailings solvent recovery unit for
coarse solids (654) may be
used to recover recyclable water (638) or solvent from the secondary solid-
liquid separator for
coarse solids (652). Coarse tailings (656) may also be removed.

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[00294] Figure 7 is a schematic representation of a system (70) according to
an embodiment
described herein. The system comprises a slurry system (71) in which a
bituminous feed is mixed
with a first solvent to form an initial slurry. A separator (73) is present,
in which a fine solids stream
and a coarse solids stream are separated from the initial slurry. An
agglomerator (75) is present in
the system, for receiving fine solids stream from separator, and in which
agglomerated slurry is
formed. A primary solid-liquid separator (77) is included in the system (70)
for receiving the
agglomerated slurry, and separating it into agglomerates and a low solids
bitumen extract. A gravity
separator (78) is included for receiving the low solids bitumen extract and a
second solvent.
Further, a primary solvent recovery unit (79) is also included in the system
(70) for recovering first
and/or second solvent arising from primary solid-liquid separator, leaving
bitumen product.

[00295] Embodiments described below may involve integration of a stream or
product from a
solvent-based extraction process into a water-based extraction process.
Further, embodiments are
described which involve integration of a stream or product of a water-based
extraction process into
a solvent-based extraction process. These integrated processes may employ a
number of different
streams and/or products, and may involve introduction of such streams at
various stages of the
process into which the streams or products are to be integrated. For example,
a bitumen product
formed as a result of the solvent-based extraction process may itself be
integrated back into a
water-based extraction process, thereby permitting solvent-based extraction to
serve as a closed
loop component of the overall process. Another example, as described below may
involve dry
tailings, having a low water content (also referred to herein as "agglomerated
tailings") being
directed into a water-based extraction process. Other streams which may be
produced as
intermediate streams or bitumen-lean streams within the solvent-based process
can be directed into
the water-based process, regardless of solvent content. A bitumen-containing
stream from the
solvent-based extraction process may be integrated into a water-based
extraction process, so as to
derive an even higher quality bitumen product than can be achieved using
solvent-based extraction
alone. Numerous options for integrating water-based and solvent-based
processes are outlined in
section (A) to section (G) below.

[00296] (A) Integration of Water-Based Extraction and Solvent-Based Extraction
Processes and Systems
[00297] An aspect described herein relates to the integration of water-based
processes for
extraction of bitumen with solvent-based processes for extraction of bitumen
in order to capture
previously unrecognized synergies between the two extraction processes.
Advantages of water-
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based extraction process include: the dominate use of water, which is
relatively an inexpensive and
environmentally benign liquid; and the production of a fungible bitumen
product when paraffinic froth
treatment is used to treat the bitumen froth. Advantages of solvent-based
extraction process
include: good recovery of bitumen from streams containing a large amount of
fines; reduced volume
of tailings produced compared to water-based extraction tailings; and that
solvent extracted bitumen
can have a reduced solids and water content compared to bitumen froth, for
example, containing 2
wt% or less of entrained solids and 1 wt% or less of entrained water in the
final product.
[00298] Figure 8 is a schematic representation of an embodiment of the process
(800) which
water-based extraction streams are directed into a solvent-based extraction
process. Recovery of
bitumen from an oil sands into a bitumen-rich stream is achieved. The bitumen
is separated (802)
from oil sands by addition of water to form a bitumen-enriched aqueous stream
and a first bitumen-
lean stream. The first bitumen-lean stream is mixed (804) with additional oil
sands to form a mixed
stream. Subsequently solvent is added (806) to the mixed stream to extract
bitumen from the mixed
stream into the solvent, forming a second bitumen-lean stream and an extracted
bitumen stream.
The extracted bitumen stream is then mixed (808) with the bitumen-enriched
aqueous stream to
form a bitumen-rich stream.
[00299] Figure 9 illustrates numerous exemplary feed streams derived from a
water-based
extraction process, which can be directed to and further extracted within a
solvent-based extraction
process. Such streams include, but are not limited to, middlings of the
primary separation vessel,
flotation tails, and froth treatment tailings, such as FSU underflow. In this
illustration, an "X" is
shown for each process component of a water-based process which could be
impacted by either
elimination or reduction by forwarding such streams into the solvent-based
extraction process.
[00300] Figure 9 depicts an example of the integration of the water-based
extraction process
with the solvent-based extraction process, and shows that many of the common
unit processes
used to handle bitumen-lean streams produced in the water-based extraction
process may be
eliminated and the bitumen-lean streams can be directed to a solvent-based
extraction process in
order to extract the bitumen within. The bitumen-lean streams may be combined
with additional oil
sands, which are minimally altered or unaltered, prior to entry into a solvent-
based extraction
process. The bitumen-lean streams may be conditioned so that the resulting
slurry with the oil
sands has a water content that does not impede solvent extraction. According
to one embodiment,
the ratio of water to solids within a bitumen-lean stream and oil sands slurry
is conducive to the
formation of agglomerates in a solvent-based extraction process employing
solids agglomeration
such as the process described in Canadian Patent Application No. 2,724,806. As
described below
with reference to Figure 9, the residual solids and water that are contained
in the solvent extracted

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bitumen stream are removed by mixing the stream with bitumen froth and
directing the combined
streams to the froth treatment unit of the water-based extraction process.
[00301] Figure 9 shows, a process (900) which is typical of those processes
used for water-
based extraction of bitumen from oil sands comprises the initial input of ore
(901) from oil sands, or
another bitumen-containing product. Primary water-based separation occurs in a
primary
separation vessel or PSV (902). The primary separation vessel typically
produces three streams, a
bitumen enriched stream containing some fines (903) that is typically directed
as froth (904) to
further treatment, a middling stream (906) with a considerable fines content,
and an underflow of
tailings (908a). Middlings (906) may be directed to secondary floatation (910)
from which residual
froth (912) can be removed and re-directed to the PSV or directed to froth
treatment. An underflow
of tailings (908b) from secondary floatation (910) can be directed to a
further settling unit (914) from
which an underflow of coarse tailings (916) is derived. The remaining fines-
containing stream (918)
can be directed to subsequent floatation (920), from which residual froth
(912) is redirected to the
PSV or directed toward downstream froth treatment, while fine tailings (922)
or "floatation tails" go
on to processes of fines capture (924), for example using centrifugation or
other means such as
consolidated tailing (CT) technology.
[00302] In a typical water-based extraction process, froth (904) is directed
to froth treatment
where the froth separation unit (930) is used to isolate bitumen from the
water and solids that
carried over to the froth stream. The tailings-containing FSU underflow (932)
is directed to a tailings
solvent recovery unit (934), in the presence of dilution water (936) where
applicable. The solvent-
containing FSU overflow (938) can be sent for solvent removal and recovery in
the solvent recovery
unit (940). A fungible bitumen product (942) may be formed upon solvent
removal.
[00303] The described embodiments are not limited by type of solvent-based
extraction
process. However, a solvent-based extraction process (944) may preferably
involve extraction with
a solvent together with a solids agglomeration process in order to produce a
low solids bitumen
product (943) and agglomerated tailings (946), which is relatively low in
water (also referred to as
"dry tailings").
[00304] The nature of this integrated system is to form a closed loop. The
solvent-based
extraction process results in a low solids bitumen product (943) that can then
be fed back into the
water-based process at one or more entry point. For example, the bitumen
product (943) of solvent-
based extraction may be included with the product of the solvent recovery unit
(940) of a water-
based extraction process, or can be combined with a bitumen enriched stream
(903) for formation of
froth (904), at which stage, further cleaning or deasphalting can occur.

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[00305] Bitumen-lean streams (for example the middlings stream), derived from
a primary
separation unit of a water-based extraction process, usually contain a
sufficient amount of bitumen
that requires additional recovery stages to be conducted in order to recover
residual bitumen.
However, such secondary and tertiary recovery stages can be expensive, energy
intensive, and
may result in an increase in water usage in the extraction process.
Furthermore, such additional
recovery stages recover much less than 90% of the residual bitumen in the
tailings streams. By
contrast, solvent-based extraction processes may result in bitumen recoveries
in excess of 90%
even for feeds containing a bitumen content lower than 10 wt%. Thus, as
described herein,
bitumen-lean streams from a water-based extraction process can be additionally
processed in a
solvent-based extraction process in order to maximize recovery of residual
bitumen.
[00306] Bitumen extracted from a solvent-based extraction process is likely to
contain fines
and water droplets that need to be removed in order to yield a fungible
bitumen product. Paraffinic
froth treatment (PFT), as a component of water-based extraction processes, is
a proven technology
that can yield a fungible bitumen product. Residual bitumen from the bitumen-
lean streams that has
been extracted in a solvent-based extraction process can thus be redirected
back to a water-based
extraction process in order to produce a fungible bitumen product. In
particular, directing a stream
resulting from solvent-based extraction to PFT of the water-based extraction
process can result in a
high quality bitumen product.
[00307] In general, water-based extraction streams that are lean in bitumen
content, and that
are likely to be high in fines content, are directed to a solvent based
extraction process in order to
recover the residual bitumen within. Recovered residual bitumen is made into a
fungible bitumen
product when mixed with a water-based extraction stream, such as bitumen
froth, prior to paraffinic
froth treatment or the bitumen product after paraffinic froth treatment.
[00308] Bitumen-lean streams derived from a water-based extraction process may
optionally
be dewatered in a water separation system before being directed to the solvent
based extraction
process, for example as described below in section (B).
[00309] Closed loop integration of water-based extraction with solvent-based
extraction is
accomplished. The product of a solvent-based extraction process is fed into a
water-based
extraction process to achieve an enhanced result in outcome of the water-based
process. The
aspects described herein relating to closed loop integration of the solvent-
based extraction with
water-based extraction permit the combining of solvent-based processes and
streams with water-
based extraction processes and streams, in order to combine the unique
advantages of each
extraction process. The utilization of solvent-based extraction processes to
recover bitumen within
intermediate streams or tailings of a water-based extraction process, and
subsequently feeding the

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bitumen, so recovered, back into a step of a water-based extraction process
offers advantages for
this closed loop integration scheme such as an overall increase in bitumen
recovery and production
of a high quality bitumen product. Additional advantages of such an integrated
process include
reduced utilization or outright elimination of process equipment typical of
water based processes,
and a commensurate reduction in water use. Other benefits include reduced
tailings volumes
resulting from water-based extraction, and a more robust water-based
extraction system, especially
for extraction feed streams produced using a no-reject slurry systems.
Furthermore, clarification
steps within a solvent-based extraction can be reduced or eliminated in
integrated processes,
because product cleaning or deasphalting can be affected in the froth
treatment process.
[00310] Operations for water-based and solvent-based extractions may be able
to integrate
streams or other operational aspects when these systems are geographically
proximal and/or when
a product of one system can be readily utilized by the other system.
Integrating such processes can
introduce efficiencies, for example increase bitumen recovery, production of a
cleaner or otherwise
desirable product, and reduction of heat loss by heat integration.
[00311] Processes and systems are described herein which integrate solvent-
based
extraction procedures with water-based extraction procedures used in
extraction of hydrocarbon
from mineable deposits.
[00312] Process streams from water-based extraction processes can be directed
to
appropriate entry points in a solvent-based extraction process. Extraction of
bitumen from high fines
streams is challenging in water-based extraction processes. By directing such
streams to a solvent-
based extraction process that promotes agglomeration of fines, the separation
of hydrocarbon from
high fines streams can be conducted with less water use. For example, high
fines streams from a
water-based extraction process can be directed into a solvent-based extraction
process involving a
water separation system (WSS), to ultimately produce a bitumen product and
agglomerated tailings.
Exemplary streams derived from water-based processes which may be directed in
this manner
include middlings, flotation tails, and froth treatment tailings, for example
the underflow from a froth
separation unit, mature fine tailings from tailings ponds, as well as other
hydrocarbon-containing
streams. Such streams include, but are not limited to streams high in fines
which are susceptible to
agglomeration.
[00313] The term "middlings" or "middling fraction" as used herein refers to
the portion of a
mixture derived from a separation vessel, for example the primary separation
vessel used in water-
based extraction process. The upper phase of the vessel, the overflow, may
comprise froth, while
the lowermost phase comprises tailings. This mid-level phase of such a
separation vessel may be
referred to as "middlings". In the case of middlings from a primary separation
vessel (PSV), the

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middlings may be directed to floatation for further processing in a water-
based extraction process,
and in the integrated process described herein, may alternatively be directed
to solvent-based
extraction process.
[00314] The term "mature fine tailings" or MFT as used herein refers to the
dense mixture of
clay, silt and water found in the tailings ponds of water-based extraction
facilities. The mixture has a
typical solids content of about 30 wt%. Mature fine tailings are formed when
tailings from the water-
based extraction process is deposited within the tailings ponds. The raw
tailings separate and settle
into a coarse fraction that forms the beach of the tailings pond, a layer of
clarified water, which is
recycled back to the extraction process, and below the water layer is the
mature fine tailings layer,
which remains unconsolidated for decades or more.
[00315] Embodiments of the process which permit the elimination of certain
conventionally
used components from water-based extraction processes will advantageously
permit cost reduction
through removal of such components (when an existing operation is
retroactively fitted to include the
solvent-based extraction processes), or will stream-line new operations which
would not initially
require certain equipment that would have normally been required in a typical
water-based
extraction site. As illustrated in Figure 9, the elimination of process
equipment from the water-
based process may involve elimination or reduction in the number of floatation
vessels which are
used in secondary and tertiary recovery of bitumen after a primary separation
process in water-
based extraction. The floatation step required in a water-based extraction
process can be reduced
or eliminated, by directing such streams into the solvent-based extraction
process. In addition to
improved bitumen recovery, this integration could eliminate the need to
capture fines from the
floatation tailings, which require energy intensive processing, such as
centrifugation, or consolidated
tailing (CT) technology to decrease water content. Further, the underflow
derived from a froth
separation unit (FSU) of water-based extraction froth treatment technology,
could be directed into
the solvent-based extraction process, thereby reducing or eliminating the need
for a tailings solvent
recovery unit within the water-based extraction process and/or use of dilution
water at this particular
stage for treating the FSU underflow.
[00316] Advantageously, the solvent-based extraction components of the overall
process
may be used to process such high fines streams, and may then produce a bitumen
product that can
be further cleaned in a manner similar to bitumen froth produced in the water-
based extraction
process. Advantageously, the level of fines in solvent extracted bitumen would
be low, and tailings
derived from the product cleaning step would be minimized.
[00317] The bitumen product derived from the solvent-based extraction process
can be
directed to water-based extraction processes for further processing. For
example, the solvent
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CA 02740481 2011-05-17

extracted bitumen may be directed to the froth treatment stage of the water-
based extraction
process to undergo further product cleaning. Before being directed to the
froth treatment stage of
the water-based extraction process, the solvent extracted bitumen may first be
mixed with process
water or streams derived from the water-based extraction process such as
bitumen froth, middlings,
flotation tailings, or mature fine tailings. The resulting mixture yields a
froth-like material that can be
processed in a froth treatment unit such as paraffinic froth treatment. In
this case, the paraffinic
froth treatment has the advantage of producing a cleaner pipelineable product
from the solvent-
based extracted bitumen product, which is optimally fungible, with less than
300 ppm solids.
Furthermore, when the solvent extracted bitumen is mixed with low hydrocarbon-
containing streams
such as middlings, fine tailings, and mature fines tailings to produce a
hydrocarbon-rich bitumen
froth that is then directed to a froth treatment stage, the froth treatment
stage may provide the added
advantage of increasing the recovery of bitumen that would have been lost in
those low hydrocarbon
streams. In yet another advantage of mixing the solvent extracted bitumen with
low hydrocarbon-
containing streams and then directing the resulting bitumen froth-like
material to a paraffinic froth
treatment stage, the froth treatment stage may provide the added advantage of
producing tailings
that are more amendable to dewatering and reclamation than the original low
hydrocarbon-
containing streams. In an embodiment described herein, a low hydrocarbon-
containing stream, such
as middlings, fines tailings and mature fine tailings, may first be partially
dewatered before mixing
with the solvent extracted bitumen product.
[00318] Benefits of certain embodiments of an integrated system which combines
water-
based extraction processes with solvent-based extraction processes include
less water usage,
reduced tailings volumes, and more robust extraction systems for both water-
based and solvent-
based extraction with increased overall bitumen recovery. Furthermore, a
product cleaning step may
not be necessary within the solvent-based extraction process in those
embodiments where product
cleaning of the solvent extracted product stream occurs within the froth
treatment stage of the water-
based extraction process.
[00319] Additional advantages of integrating water-based extraction and
solvent-based
extraction include the benefit that heat integration can be introduced between
components of the
two extraction processes. Utilization of waste or heat generated by one step
of a process for
introducing heat into another step of the process can reduce costs and lower
energy intensity of the
overall process. For example, particular streams that would normally have
required de-watering in
the water-based extraction process can be utilized directly in the solvent-
based extraction process.
By utilizing such streams directly, 100% of their energy is integrated into
the solvent-based
extraction process.

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[00320] Reusing Heat in Integrated System. River-derived process or cooling
water may be
directed from a water-based extraction process to capture heat from a solvent-
based extraction
process. Major sources of heat in a solvent-based extraction process are hot
streams from the
bitumen product and tailings solvent recovery units. Hot waste streams from
water-based extraction
may be added to feed streams in the solvent-based extraction process for
preconditioning. In
particular, the tailings solvent recovery unit (TSRU) tailings from water-
based extraction may be
added to the oil sand feed for heat, or may be added to the mix box or
agglomerator feed in the
solvent-based extraction process to provide required moisture content when
forming agglomerates.
[00321] The re-utilization of heat, water, and solvent in the integrated
system can have the
benefit of reducing the overall energy intensity of a bitumen extraction
system, compared with
conventional systems in which water-based extraction is employed, and also
relative to the use of a
solvent-based extraction processes alone.
[00322] Recovery of Heat Loss from Steam. A modeling of the energy intensity
for
producing bitumen from a water-based system, versus the energy intensity for
producing bitumen
from an integrated system having both water-based extraction features and
solvent-based extraction
features would reveal that energy attributable to steam, typically lost in the
water-based extraction
process can be nearly entirely re-utilized for heat capture in the integrated
system. Further, energy
losses attributable to steam produced within the SRU and TSRU of the solvent-
based extraction
process can be reduced if the integrated system directs the steam to the water-
based extraction
process or upstream of the solvent-based extraction process.
[00323] Reducing Solvent Recovery Requirement from Water-Based Extraction
Process. According to an embodiment of the integrated process, the required
heat for the
extraction processes may be additionally reduced when the froth separation
unit tailings from the
water-based extraction process are mixed with the solvent-wetted solids of the
solvent-based
extraction process. The combined streams can then be processed in the TSRU of
the solvent-based
extraction process. In this way the tailings solvent recovery requirement of
the water-based
extraction process could be of reduced importance, or eliminated if the entire
FSU tailings stream is
combined with solvent-wetted solids.
[00324] Optimized System Layout and Component Proximity. By setting up the
various
system components to conduct the processes described herein with advantageous
proximity, further
efficiencies can be realized. The distance between the distinct processing
aspects can be optimized
so as to limit heat loss and/or to address economic considerations in those
instances where an
existing water-based extraction operation is to be retroactively fitted for
solvent-based extraction
operations.

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[00325] Building Integrated Systems for Optimal Layout. While retroactive
fitting of an
existing water-based extraction system can be conducted, efficiencies may be
optimized in an
exemplary system according to an embodiment described herein, by building an
integrated system
from the beginning. In this way, the location of solvent-based extraction
equipment can be
determined without deference to the existing location of water-based
extraction components. A
system is provided herein which encompasses components in which water-based
extraction steps
are conducted, and components in which solvent-based extraction steps are
conducted. This
system results in a site that integrates both processes for optimal
efficiency, stream proximity, heat
re-use, and solvent re-use. In this embodiment for example, a middlings stream
derived from a
primary separation vessel of a water-based extraction process may be directed
directly into the
solvent-based extraction process in relative close proximity.
[00326] Advantages of Component Proximity and/or Optimal Layout of Extraction
processes. The extraction of bitumen from low quality ore in a water-based
extraction process
typically results in poor bitumen recovery and low quality bitumen froth. Low
quality ores may be
ones in which the bitumen is either low in quantity (less than 10 wt%
bitumen), poor in quality, or in
which bitumen is entrained in such a manner that renders it difficult to
extract. High fines content in
resulting process streams may be characteristic of low quality ores. Poor
bitumen recovery is
defined as the recovery of less than 90% of the ore's bitumen in the bitumen
froth and low quality
froth is defined as froth with a bitumen content of less than 55 wt%.
[00327] In typical water-based extraction facilities, the method for improving
recovery and
froth quality of extracted low quality ores involves blending said ores with
higher quality ores. The
blending of the low quality ores with high quality ores results in an average
grade ore that gives
consistently higher bitumen recoveries and froths that have approximately 60
wt% bitumen content.
However, the blending of varying ores has significant CAPEX and OPEX
implications as mining
logistics complexity and truck requirements.
[00328] Efficiencies can be realized if the solvent-based extraction process
and the water-
based extraction process are in close proximity to each other so that the
solvent-based extraction
process can initially treat low quality ores rather than the water-based
extraction process. By
providing low quality ores to a solvent-based extraction process first, prior
to conducting any water-
based extraction steps, the solvent-based extraction serves to extract bitumen
therefrom at a higher
level of bitumen recovery (greater than 90%) and product quality. Additional
advantages include;
the volume of water used in extraction is reduced and the formation of fines
and coarse tailings is
reduced. Thus, a greater proportion of hydrocarbon entrained in such a low
quality ore can be
extracted in a more efficient manner using an integrated system.

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[00329] The bitumen product resulting from the solvent-based extraction
process may require
further cleaning in order to be pipelineable and/or fungible when held to high
standards of purity.
Efficiencies can be realized if the solvent-based extraction process and the
water-based extraction
process are in close proximity to each other so that transportation is
inexpensive to direct solvent
extracted bitumen product to a nearby paraffinic froth treatment unit of a
water-based extraction
process for product cleaning of the solvent extracted bitumen to the fungible
specifications. Further,
if the heat entrained in the product or stream derived from the solvent-based
extraction process can
be captured and contributed into the water-based extraction process through
integration, then less
heat input from other sources would be needed in the water-based extraction
process.
[00330] An exemplary solvent-based extraction process is described in Canadian
Patent
Application No. 2,724,806. In this process a solvent is combined with a
bituminous feed derived
from oil sand to form an initial slurry. The initial slurry can be separated
into a fine solids stream and
coarse solids stream followed by agglomeration of solids from the fine solids
stream to form an
agglomerated slurry. The agglomerated slurry can be separated into
agglomerates and a low solids
bitumen extract. Optionally, the coarse solids stream may be reintroduced and
further extracted in
the agglomerated slurry. A low solids bitumen extract can be separated from
the agglomerated
slurry for further processing. Solvent is recovered from the bitumen extract
to produce a bitumen
product.
[00331] When the water-based extraction process and the solvent-based
extraction process
are combined into an integrated process that accepts a stream from the water-
based extraction
process into the solvent-based extraction process, there are various optional
efficiencies, as
indicated in Figure 9 with "X" showing at different stages, to mean that
certain process components
become eligible for reduced use or elimination altogether when these two
processes are integrated
in this way. Secondary floatation (910), subsequent floatation of fines (920)
derived from coarse
tailings, and processes of fines capture (924) may be reduced or eliminated
from the process, if the
streams conventionally directed to these processes were to instead be directed
to a solvent-based
extraction process (944). The middling stream (806) derived from the primary
separation vessel
(902) could be sent directly to the solvent-based extraction process (904).
The settled mixture (918)
remaining from the further settling unit (914) could be sent directly into
solvent-based extraction,
which would have the effect of eliminating the production of fine tailings
(922) from the further
floatation, and the need for specialized equipment for subsequent processes of
fines capture (924).
[00332] By integrating the processes in a manner consistent with Figure 9,
secondary
recovery, occurring in secondary floatation (910), and tertiary recovery,
occurring in (920), can be
reduced are eliminated in the water-based extraction process since the bitumen-
lean streams are

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CA 02740481 2011-05-17

directed to a solvent-based extraction process (944). Additional oil sands
(945) can be included into
the solvent-based extraction process (944) together with the high fines
bitumen-lean streams, which
can be one of or a combination of the middlings (906), PSV tailings (908a),
flotation tailings (908b)
(918), fine tailings (922), froth treatment tailings (929) and FSU underflow
(932). In combining oil
sands with a high fines bitumen lean stream (939), a slurried mixture can be
directed into solvent-
based extraction. The product of a solvent-based extraction process (944) can
ultimately be
characterized as solvent extracted agglomerated tailings (946) and a low
solids bitumen product
(943). In the integrated scheme, the need for TSRU (934) can be reduced or
eliminated, as the
FSU underflow, which is a high fines bitumen lean stream (939) could be
directed to solvent-based
extraction (944) instead of to the TSRU. This also negates the requirement to
add dilution water
(936), which would have been needed for FSU underflow (932) to proceed to TSRU
(934).
[00333] Tailings derived from primary separation (908a) in the water-based
extraction
system, which may have been considered too energy intensive a process to
direct to further
purification in water-based extraction processes can now be further processed
through the solvent-
based extraction system in such an integrated process. The solvent-based
extraction process can
assist in deriving further amounts of bitumen from coarse tailings.
[00334] The low solids bitumen product (943) resulting from the solvent-based
extraction
(944) process may require further cleaning in order to be pipelineable and/or
fungible when held to
high standards of purity. For this reason, the low solids bitumen product
(923) is directed to the
froth treatment unit (948) of the of the water-based extraction process. It is
preferable that the froth
treatment unit (948) be a paraffinic froth treatment unit capable of producing
a fungible bitumen
product. The low solids bitumen product (943) is mixed with a bitumen enriched
stream (903) to
form bitumen froth (904) prior to froth treatment. The mixture then undergoes
a paraffinic froth
treatment in order to produce a fungible bitumen product (942). Alternatively,
in the situation where
bitumen product (942) produced by the paraffinic froth treatment process may
have a solids and
water content that is much less than the fungible limit, the low solids
bitumen product (943) from the
solvent-based extraction process may bypass the paraffinic froth treatment
process and directly mix
with the fungible bitumen product (942) and still yield a combined stream that
meets the fungible
specifications.
[00335] The low solids bitumen product (943) generally contains very low water
content.
Thus, this product may first be mixed with a water-containing stream before
being directed to the
froth treatment unit (948) of the water-based extraction process. The addition
of water to the
process may improve the froth treatment process. The water-containing stream
may comprise low
hydrocarbon-containing streams, such as a middling stream (906), tailings
(908b), a fines-containing

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stream (918), or fine tailings (922), and mature fine tailings. In these
cases, the froth treatment
stage may provide the added advantage of increasing the recovery of the
bitumen that would have
been lost in those low hydrocarbon streams.
[00336] The froth separation unit of a water-based extraction system is
generally in
communication with a solvent recovery unit (SRU) (940), which receives a
bituminous solvent-
containing stream, relatively free of fines and water. This SRU serves to
remove solvents, resulting
in a bitumen product. This type of solvent removal can also be conducted
within the solvent-based
extraction process. Thus, in an integrated system, the SRU may be a
consolidated unit, accepting
streams from both the water-based extraction and the solvent-based extraction
processes.
[00337] Solvent-based extraction processes (944) which tolerate a bitumen feed
having water
entrained therein can be extracted according to the described method. This
permits a feed
containing more water than typical oil sands to be processed with the solvent-
based extraction
process (944), and even permits enrichment of an aqueous stream with
additional oil sands (945).
[00338] (B) Recovery of Bitumen from Aqueous Sources
[00339] Processes will now be described in which bitumen can be recovered from
aqueous
streams arising from water-based extraction. Such techniques can operate
efficiently in the
presence of fines, or which are largely unaffected by the presence of fines.
[00340] Streams derived from water-based extraction processes that may be
bitumen-lean
are not necessarily utilized to full advantage within the water-based
extraction process. Integration
of a water-based extraction process with a solvent-based extraction process is
a way of utilizing
aqueous streams that would not necessarily have resulted in bitumen recovery
within a water-based
process. Such aqueous streams may be referenced herein as bitumen-lean, as
waste-streams,
aqueous hydrocarbon-containing streams, or simply as aqueous streams.
[00341] Aspects described herein which generally relate to a process and
system for
recovery of hydrocarbon associated with or entrained within an aqueous stream.
Such aqueous
streams may be ones having in excess of 50% water. Such streams may be ones
produced or
rejected from water-based bitumen extraction processes, or may be streams that
are directly
derived from oil sands which include a high water content, but which were not
necessarily intended
for a water-based bitumen extraction process. Certain rejected streams from
water-based bitumen
extraction processes (generally, bitumen-lean streams), as well as
intermediate streams produced
in the extraction process which may be intended for further bitumen-recovery
steps, may be
relatively high in water content, and thus can advantageously be processed
further through solvent-
based extraction once the water content of the high water stream streams is
reduced to a level

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acceptable within the solvent-based extraction process, such as for example
reduced below 40%
water.
[00342] Recovery of bitumen from relatively high fines aqueous feed streams
may involve
using a combination of solvent-based extraction and agglomeration of solids.
In such a solvent-
based extraction and solids agglomeration process the desired amount of water
in the feed mixture
is between 5 to 50 wt% or more preferably between 5 to 20 wt%. Thus, solvent-
based extraction
and solid agglomeration processes can employ aqueous feed streams, provided
the water content is
not so high as to negatively impact the agglomeration aspect. Aqueous feed
streams may be used,
despite a high fines content, and in this way, such aqueous streams that may
have previously been
considered difficult to recover because of the fines content, can be
effectively utilized. High fines
content is a characteristic previously considered problematic in conventional
methods for extracting
hydrocarbon from aqueous feed streams. For example, bitumen-lean streams
arising from water-
based methods of hydrocarbon recovery, which may have previously been directed
to tailings
ponds, can be used in the solvent-based extraction processes described herein,
provided the water
content is in an appropriate range to permit use of the stream without causing
excessive dilution to
the solvent-based extraction process thereby impeding efficient agglomeration
of fines. Thus,
bitumen-lean streams arising from conventional water-based extraction
processes, intermediate
streams from conventional water-based extraction processes, or any bituminous
aqueous stream
can be used in the solvent-based extraction process if pre-conditioned to
achieve desired
characteristics. The process is described herein for utilization of streams
that are high in water
content, which may require concentration through pre-treatment in order to be
effectively used in
solvent-based extraction process.
[00343] Hydrocarbon-containing streams bearing levels of water that are not in
excess of a
level that would be of detriment to a solvent-based extraction process (such
as streams containing
less than about 40 wt% water), can be fed directly into the solvent-based
extraction processes as
described herein, without the need for concentration through a water removal
pre-treatment
process. Such streams that already contain water at a lower, acceptable level
for solvent-based
extraction are encompassed in the processes described herein.
[00344] One embodiment provides a process for pre-treating an aqueous
hydrocarbon-
containing feed for downstream solvent-based extraction processing for bitumen
recovery, the
aqueous hydrocarbon-containing feed comprising from 50 wt% to 95 wt% water,
from 0.1 wt% to 10
wt% bitumen, and from 5 wt% to 50 wt% solids, wherein the solids comprise
fines, the process
comprising: removing water from the aqueous hydrocarbon-containing feed to
produce an effluent
comprising 40 wt% water or less; and providing the effluent to a downstream
solvent-based

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extraction and solids agglomeration process to recover bitumen. The step of
removing water from
the aqueous hydrocarbon-containing feed may comprise: flowing the aqueous
hydrocarbon-
containing feed into a primary water separation system to remove water from
the aqueous
hydrocarbon-containing feed, producing a reduced-water stream of from 30 wt%
to 60 wt% solids,
and recycled water; and removing water from the reduced-water stream using a
secondary water
separation system to produce an effluent comprising 40 wt% water or less. The
primary water
separation system may comprise a clarifier, a settler, a thickener or a
cyclone. Flocculant may be
added to the aqueous hydrocarbon-containing feed in the clarifier. A solvent
or flocculant may be
mixed with the aqueous hydrocarbon-containing feed prior to water separation
in the clarifier. The
solvent may be mixed with the aqueous hydrocarbon-containing feed with a
solvent:bitumen ratio of
less than about 2:1. A low boiling point cycloalkane solvent may be mixed with
the aqueous
hydrocarbon-containing feed. The secondary water separation system may
comprise a centrifuge
with filtering capacity, a shale shaker, a vacuum belt filter, or one or more
clarifiers.
[00345] In an optional embodiment, the values may be thathe aqueous
hydrocarbon-
containing feed comprises from 60 wt% to 95 wt% water, from 0.1 wt% to 10 wt%
bitumen, and from
wt% to 40 wt% solids,
[00346] The aqueous hydrocarbon-containing feed may comprise middlings from a
primary
separation vessel. The aqueous hydrocarbon-containing feed may comprise
effluent of a froth
separation unit. The aqueous hydrocarbon-containing feed may comprise tailings
from a tailings
solvent recovery unit.
[00347] There are many sources of aqueous hydrocarbon-containing feed streams
in excess
of 50 wt% water which can be subjected to processing as described herein, so
that hydrocarbon
may be extracted. Such streams that are referred to as aqueous hydrocarbon-
containing feed
streams may interchangeably be referenced herein as "high water content
streams". The variety of
aqueous hydrocarbon-containing feed streams which could be used as feed
streams in the
processes described herein contains over 50 wt% water. Thus, possible streams
for processing
according to the processes described herein include streams derived either as
intermediates, as
bitumen-lean streams, or as an end-products of water-based extraction
processes. For example,
streams that may not normally have been considered for further bitumen-
recovery processing within
in a conventional water-based extraction process can now be subjected to
processing, and recovery
of hydrocarbon. While such streams need not be designated as waste streams per
se, they may be
bitumen-lean streams, and/or intermediate streams which would have normally
proceeded to further
processing within an water-based extraction process. Aqueous streams need not
be derived from a
water-based extraction process, but may contain water for other reasons, such
as steam exposure,

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water-heating, slurry transport, or due to mixing of water with oil sands that
have not yet been
subjected to any extraction process, but which have been rendered aqueous for
alternative reasons.
[00348] The integration of the solvent-based extraction and agglomeration
process described
herein with a conventional water-based extraction process,is problematic that,
except for oversized
rejects, other potential feed streams have a very large proportion of water.
This large proportion of
water is higher than the optimum needed for effective fines agglomeration in
the process. An
advantage of the utilization of high water content streams, as described
herein is that pre-
conditioning of such streams can reduce water content to permit such streams
to be used as feed
streams in solvent-based extraction process, thereby addressing this
challenge. Another advantage
is that the aqueous hydrocarbon-containing stream with reduced water content
will have enough
water to provide the needed bridging liquid for the agglomeration process. The
treatment process
for bitumen-lean streams according to embodiments described herein permits
aqueous streams with
high fines content to be used as feed streams for the solvent-based extraction
and solids
agglomeration process, so as to permit successful recovery of bitumen that
would have otherwise
been lost.
[00349] Typical aqueous hydrocarbon-containing feed streams for use in the de-
watering
process include, but are not limited to middlings derived from a primary
separation vessel (PSV),
froth treatment tailings, floatation tails which may not yet have been
directed to a tailings pond,
and/or mature fine tailings (MFT), which may have already been present in a
tailings pond.
Appropriate aqueous hydrocarbon-containing feed streams may be ones containing
bitumen and/or
other hydrocarbon components, which may or may not include bitumen.
[00350] Bitumen-lean feed streams arising from conventional water-based
extraction
processing techniques are particularly attractive for pre-conditioning as
described herein, to reduce
water content prior to use as a feed in an solvent-based extraction process.
The pre-conditioning
process described herein may have previously been considered as an effective
way to recover
waste water; however, it has not been viewed as an optimal way to recover
bitumen that would have
otherwise been lost. By pre-treating a bitumen-lean stream in this way, in
preparation for
subsequent recovery in a solvent-based extraction process, both a reduction in
waste, recovery of
waste water, and an increase in recovery of bitumen from bitumen-lean aqueous
streams can be
realized.
[00351] Advantageously, the middlings from a primary separation vessel used in
a
conventional water-based extraction process may be processed less efficiently
on the assumption
that further hydrocarbon components can be recovered in downstream solvent-
based extraction

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processes. This results in an energy saving at this step, as not all bitumen
need be removed in a
water-based bitumen extraction process.
[00352] A mixer may be used as the aqueous hydrocarbon-containing stream
enters a
primary water separation system or vessel. One or more points of entry of the
hydrocarbon-
containing feed stream may be used on the way to a primary water separation
vessel, so as to allow
turbulence to occur. As an exemplary embodiment, multiple injection points of
an aqueous
hydrocarbon-containing feed are used on the way to the primary water
separation vessel.
[00353] Flocculants or other additives, such as coagulants or pH modifiers may
be added to
the aqueous hydrocarbon-containing feed streams. Typically, a pH of 8.5 is
achieved, and a drop in
pH may be achieved. Thus, pH may be modified from a level above pH 7 to a
level below pH 7. A
reduction in pH may reduce surface activities of the clays, which may result
in precipitation of fines.
A solvent may be added to the aqueous hydrocarbon-containing feed streams, for
example a
solvent may be used which may be lighter or heavier than water. When solvent
is present, deriving
recycled water may be accomplished in an appropriate way so that the recycled
water may be
recovered separately from the solvent. Further, small quantities of solvent
may adhere to solids and
thus sink to the bottom in a dewatering unit, permitting concentration of
solids in the underflow.
[00354] In the primary water separation step for water removal, a clarifier, a
settler, thickener,
or a cyclone may be used in single or multiple units which may be in
communication in serial, or
employed in parallel. Thus, the dewatering unit may comprise one or more of
such units. The
resulting effluent may contain from 30 wt% to 60 wt% solids. The hydrocarbon
content of the
effluent arising from this stage of the process is enriched, relative to the
initial aqueous feed. A
doubling of the hydrocarbon content, or a further enriched content, may be
achieved. However, the
effluent from this stage is still pumpable so as to permit transport and
movement through to further
aspects of the process. The content of solids may in fact be above a level of
60 wt%, and water
content could be lower that 40%, provided the effluent from the underflow
derived from the primary
water separation is still pumpable or made to be pumpable by the addition of
extraction liquor from
the solvent-based extraction process.
[00355] When present, a secondary water separation system of the dewatering
unit may be
employed. Similar types of apparatuses may be employed in such secondary
separation, or a filter,
filter centrifuge, centrifuge, vacuum filter, or vibration filter may be
employed. The system may
employ a single dewatering unit, or the dewatering unit may comprise
individual components, such
as primary water separation system and a secondary water separation system.
Each of the primary
and secondary water separation systems may have multiple individual components
operating in
parallel or in serial.

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[00356] A feed stream comprising bitumen, water and solids with or without
residual solvent
is pre-conditioned according to the process described herein. The feed stream
may be derived from
a mixture of oils and, oversized rejects stream, and high water content
streams or blends thereof.
An exemplary high water content stream may be one derived from a middling
stream of a primary
separation vessel, or from secondary flotation tails and/or froth treatment
tailings from a water-
based extraction process. Such feed streams or blends thereof are processed
via a single or dual
staged water separation system (WSS) in order to be adequately pre-conditioned
for use as a feed
stream in solvent-based extraction and agglomeration processes.
[00357] Figure 10 is a schematic representation of the process (1000) in which
an aqueous
hydrocarbon-containing feed stream is conditioned according to the process
described herein. The
initial aqueous hydrocarbon-containing feed (1030) is one derived from a water-
based extraction
process, for example, it may be a bitumen-lean stream derived from a
conventional water-based
extraction process. Advantageously, the feed may have high fines content, as
such fines can be
subsequently removed. The feed (1030) contains 50% to 95% water on a weight
basis, and also
contains from 0.1 wt% to 10 wt% bitumen, and from 5 wt% to 40 wt% solids. The
step of water
removal (1032) is conducted in any manner that would be acceptable so as to
achieve an effluent
(1034) having about 40% water, or less, by weight. This effluent goes on to
downstream solvent-
based extraction (1035), for example using a process that involves solids
agglomeration.
[00358] Figure 11 represents processes (1100) for pre-treating an aqueous
hydrocarbon-
containing stream or feed (1102) with water content of from 50 wt% to 95 wt%
water, with from 0.1
wt% to 10 wt% bitumen, and with 5 wt% to 40 wt% solids.
[00359] The aqueous hydrocarbon-containing stream or feed (1102) is passed
into a primary
water separation system or PWSS (1104). In the PWSS, a portion of the water
contained in the feed
(1102) is recovered as recycled water (1106). The remaining portion is a
reduced-water stream
(1108) is then fed into a secondary water separation system or SWSS (1110) to
produce an effluent
(1112) having the consistency of a pumpable slurry or made to have a
consistency of a pumpable
slurry by downstream processing. The effluent (1112) contains predominantly
fine solids and
hydrocarbon, and has a water content of up to 40 wt%. More recycled water
(1106) is recovered
from the secondary water separation system (1110). The effluent (1112) of the
secondary water
separation system, having the consistency of a pumpable slurry or made to have
the consistency of
pumpable slurry, may be combined with oversized rejects (1114) and/or recycled
extraction liquor
from a solvent-based extraction process (1116) in proportions which permit the
water content of the
resulting slurry (1118) to remain within the desired level for solids
agglomeration in later
downstream processing. The recycled extract liquor may be added to the
effluent (1112) of the

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CA 02740481 2011-05-17

secondary water separation system to ensure that the effluent has the
consistency of a pumpable
slurry.
[00360] The primary water separation system (1104) may preferably be a
clarifier unit or
cyclone which takes advantage of inherent or induced high settling
characteristics of the high water
content feeds. The primary water separation system my optionally be a
thickener unit or more
preferably a paste thickener. In contrast to conventional water-based
extraction processes in which
additives are employed to disperse fines in water and prevent slime coating of
bitumen, flocculants
or coagulants may optionally be used to induce the aggregation of fines and
hydrocarbons within the
water-based extraction process or within the clarifier. Large quantities of
recycled water, which is
low in total suspended solids, may thus be recovered. Advantageously, by
recovering water at this
stage, efficiencies are introduced, due to the reduced volume forwarded for
downstream processing
in a solvent-based extraction process.
[00361] The secondary water separation unit (1110) may be a filtering device
that can provide
one or a combination of pressure, centrifugal or vibrational forces for phase
separation. A slurry of
coarse solids may be added to the secondary water separation system to promote
efficient
dewatering. In exemplary embodiments, the secondary water separation system
(1110) may
comprise a centrifuge with filtering capacity, shale shaker, or a vacuum belt
filter. It may be possible
in certain embodiments that the dewatering achieved in the secondary water
separation system is
enough to allow for direct feed of the effluent (1112), without addition of
oversize rejects or oil
sands, into a solvent-based extraction process.
[00362] As shown in Figure 11, optionally, solvent (1120) may be added to the
feed (1102)
entering the primary water separation system (1104) so as to dissolve bitumen
and decrease the
feed density sufficiently for selective phase separation under gravity or for
application of a
centrifugal force field. If solvent is added, an exemplary solvent:bitumen
ratio is less than 2:1.
[00363] As a further option, a flocculant (1122) with selective reactivity for
the fines may be
added to aggregate clays contained in the feed (1102) thus promoting faster
settling or drainage.
The flocculant may be added prior to entry of the feed (1102) into the primary
water separation
system (1104), via a mixer (1121) or may be added directly into the primary
water separation
system. The resulting reduced-water stream (1108) resulting from the primary
water separation
system (1104) is passed through the secondary water separation system (1110)
and the effluent
(1112) may be subsequently combined with the oversize rejects (1114) to
produce a slurry (1118)
ready for processing via the solvent-based extraction process.
[00364] The resulting slurry (1118) may be combined with any other appropriate
feed source
as a bituminous feed (1130) for later downstream processing in a process
(1132) capable of

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separating fines out of a high fines content aqueous bituminous feed, such as
one capable of
agglomerating tailings (1134) while forming a hydrocarbon product (1136).
[00365] Figure 12 is a schematic illustration of a process (1200)
incorporating the preparation
of a aqueous hydrocarbon-containing stream according to Figure 10 and Figure
11 together with an
exemplary solvent-based extraction and solids agglomeration process for
recovery of bitumen. An
aqueous hydrocarbon-containing feed is derived (1230) from water-based
extraction of oil sands
and has at least 50% water. The feed may have, for example, from 50 wt% to 95
wt% water, from
0.1 wt% to 10 wt% bitumen, and from 5 wt% to 40 wt% solids. This feed is
potentially derived from
bitumen-lean streams recovered from water-based extraction processes, but may
also be derived
from intermediate streams from a water-based extraction process. Further, an
aqueous
hydrocarbon-containing stream meeting these criteria that has not been
prepared through a water-
based extraction process may nevertheless be used as a feed stream.
[00366] Water is removed (1232) from the aqueous hydrocarbon-containing feed
having 50
wt% to 95 wt% water, resulting in an effluent comprising 40 wt% water or less,
which goes on to be
used (1234) as bituminous feed either alone or in combination with further
hydrocarbon-containing
sources. Other hydrocarbon-containing sources may include oversized rejects,
recycled extraction
liquor, or other sources of bitumen. The resulting mixture should have the
consistency of a
pumpable slurry. After extraction liquor is added (1212) to form the pumpable
slurry, the slurry may
be directed to further processing. Fine solids and coarse solids are separated
(1214) from the slurry
as a fine solids stream and a coarse solids stream from the initial slurry.
Fine solids are
agglomerated (1216) from the fine solids stream to form an agglomerated slurry
comprising
agglomerates and low solids bitumen extract. A low solids bitumen extract is
separated (1218) from
the aggregated slurry. In the depicted embodiment, a second solvent is added
(1220) to the low
solids bitumen extract to recover a bitumen extract that may be essentially
free of solids. In this way,
a hydrocarbon product is derived from an aqueous hydrocarbon-containing
stream.

[00367] (C) Extracting Hydrocarbons from PFT Tailings by Directing Tailings
into a
Solvent-Based Extraction Process
[00368] Approximately 10% of the bitumen extracted in a conventional water-
based extraction
process is lost in the tailings of paraffinic froth treatment (PFT). Although
a majority of these
hydrocarbons are asphaltenes, they still have sufficient amount of value to
justify recovery, which
would result in an increase the overall volume of bitumen produced. The aspect
of the process
described herein relates to the use of solvent-based extraction to recover the
hydrocarbons in
paraffinic froth treatment tailings. It is desirable to further increase
recovery of hydrocarbons from

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CA 02740481 2011-05-17

paraffinic froth treatment tailings by directing such tailings into a solvent-
based extraction and solids
agglomeration process. Advantageously, when the solvent-based extraction
process used involving
fines agglomeration, the extraction of residual hydrocarbons from the tailings
and the formation of
agglomerates from solids in the tailings can occur simultaneously during the
agglomeration step. In
this way, the agglomerated solids may be readily separated from the bitumen
extract.
[00369] A conventional water-based extraction process may include flotation
separation steps
that result in the formation of a bitumen froth. The bitumen within the
bitumen froth includes about 5
to 15 wt% asphaltenes. To remove solids and water from the bitumen froth,
solvent deasphalting is
conducted within a froth treatment unit. In the froth treatment unit, the
bitumen froth is mixed with a
deasphalting solvent and is subjected to one or more settling stages. The
solvent can be, for
example, a paraffinic hydrocarbon solvent having a chain length from about 5
to about 8 carbons.
An exemplary solvent combination may be a mixture of pentane and hexane. The
precipitated
asphaltenes flocculate with the solids and water droplets resulting in large
flocs that rapidly settle
out of the hydrocarbon solution as the froth settling unit (FSU) underflow.
The residual solvent
within the FSU underflow is typically recovered and recycled, to avoid release
to the environment.
Separation of the solvent can occur, for example, in a tailings solvent
recovery unit (TSRU).
Conventionally, the solvent is recycled and the tailings that exit the TSRU
are disposed of as a
waste product.
[00370] In an exemplary process, the PET tailings may comprise froth
separation unit
underflow. Additionally, the PFT tailings may comprise tailings from a
tailings solvent recovery unit
(TSRU). Advantageously, when froth separating unit (FSU) underflow is employed
as the PFT
tailings that are directed to a solvent-based extraction and solids
agglomeration process, this allows
exclusion of the TSRU component from a conventional froth treatment processes.
The residual PFT
tailings solvent recovery would occur in the solvent recovery units of the
solvent-based extraction
process described herein. Thus, in a conventional process that would typically
treat underflow from
a FSU using TSRU, the use of the FSU underflow in the solvent-based extraction
process negates
the requirement for recovery of solvent in a TSRU of the froth treatment unit.
[00371] In embodiments described herein, paraffinic froth treatment tailings
are contacted
with additional oil sands and a solvent (or solvent mixture), or extraction
liquor, capable of dissolving
asphaltenes to form a slurry. The slurry is mixed to dissolve the hydrocarbons
and to agglomerate
fines within the slurry. The extracted hydrocarbon solution can then be
separated from the majority
of the solids and water, including the solids and water originally present in
the paraffinic froth
treatment tailings.

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[00372] In an exemplary embodiment, the paraffinic froth treatment tailings
stream is
dewatered to a water content of less than about 40 wt%. The dewatered tailings
stream is mixed
with additional oil sands and a solvent to form a slurry. The fines within the
slurry are agitated to
agglomerate with each other, and then most of the solids are separated from
the extracted
hydrocarbon solution. The agglomerating stage of the process advantageously
permits a majority of
the fines present in the froth treatment tailings to agglomerate with the
fines from the additional oil
sands, so that the agglomerates can be easily separated from the extracted
hydrocarbon solution.
The recovered hydrocarbon solution, which is low in solids content, can then
proceed through the
later stages of a solvent-based extraction process, ultimately forming a
bitumen product, of which a
portion would have otherwise been lost as a waste product of the water-based
extraction process.
[00373] Figure 13 is a schematic representation of an exemplary process (1300)
in which
paraffinic froth treatment tailings are directed to a solvent-based extraction
process to recover
bitumen. The process permits recovery of hydrocarbon from said tailings. A
froth treatment tailings
stream from a paraffinic froth treatment process is accessed (1302). The froth
treatment tailings
stream is combined (1304) with a solvent and additional oil sands to form a
slurry. The solvent may
comprise a combination of different solvents, and may be an extraction liquor
which contains
bitumen entrained within the solvent. The slurry is agitated (1306) to
dissolve hydrocarbons into the
solvent and agglomerate the fines. The extracted hydrocarbons are separated
from the solids
(1308) to form a low solids extracted hydrocarbon stream and an extracted
tailings stream. The
solvent is then recovered (1310) from the extracted tailings stream.
[00374] Figure 14 is a schematic representation of an embodiment of the
process (1400)
depicted in Figure 13, in which hydrocarbons from paraffinic froth treatment
tailings are extracted in
a solvent-based extraction and solids agglomeration process. The process
involves providing
bitumen froth (1402) to a paraffinic froth treatment (PFT) process (1404)
within which separation
occurs, and PFT tailings (1406) are produced. PFT tailings (1406) are then
directed into a solvent-
based extraction process (1408) that employs fines agglomeration. In another
embodiment of this
process, underflow (1426) from a froth settling unit (FSU) (1428) bypasses the
tailings solvent
recovery unit (TSRU) of the PFT plant (1404) and serves in lieu of the PFT
tailings as input into the
solvent-based extraction process (1408), as illustrated by the dashed line
representing underflow
(1426) being directed into slurry preparation unit (1412).
[00375] The PFT tailings (1406) and/or FSU underflow (1426) are combined with
oil sands
(1410) and an extraction liquor (1411) in a slurry preparation unit (1412) to
form a slurry. The fines
within the slurry are agglomerated within the agglomerator (1413) to allow for
easy solid-liquid
separation within the belt filter (1414). Solvent (1422 and 1416) from the
solvent recovery units

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(1424 and 1417) can be used in a countercurrent washing of the solids on a
belt filter (1414).
Solvent is recovered from the solvent-wet solids in a tailings solvent
recovery unit (1419) to form dry
tails (1420). Solvent is recovered from the bitumen extract in a solvent
recovery unit (1417) to form a
low solids bitumen product (1418). The process described herein permits
integration PFT tailings
(1406) of a water-based extraction process into a solvent-based extraction
process (1408), to
recover further amounts of bitumen therefrom, which would have otherwise been
difficult or
inefficient to recover.

[00376] (D) Directing Bitumen-Rich Stream into a Solvent-Based Extraction
Process
[00377] An embodiment described below relates to a process directing a bitumen-
rich stream
into a solvent-based extraction process. The bitumen-rich stream may be
derived from a
conventional water-based extraction process, and thus its utilization may
capture synergies between
the water-based and solvent-based extraction processes.
[00378] This embodiment addresses the issue of the source of "recycle bitumen"
(RB)
needed to form "bitumen product" (BP). Typically, a ratio of RB:BP employed in
solvent-based
extraction processes can be as high as 3:1. Recycling such a large amount of
bitumen entrained in
the solvent has several advantages. Importantly, the recycle bitumen (RB)
reduces the required
inventory of solvent needed for bitumen extraction from the oil sands. In a
solvent-based extraction
process, the extraction liquor that is mixed with the oil sand may contain as
much as 50 wt%
bitumen, the remainder being attributable to solvent. Herein the term
extraction liquor refers to the
solution of bitumen with the solvent prior to extraction. Further, when a non-
aromatic or partially
aromatic solvent is used, such as naphtha, cycloalkanes, paraffinic solvents
or crude distillates, the
presence of dissolved bitumen within the extraction liquor advantageously
increases the ability of
the extraction liquor to dissolve additional bitumen into the liquor. Another
advantage of having
dissolved bitumen in the extraction liquor is that the presence of bitumen
reduces the liquor's vapor
pressure, which can allow for higher operating temperatures for the solvent-
based extraction
process.
[00379] Although the recycling of bitumen has its advantages, it does mean
that the
extraction and solid-liquid separation equipment employed in the solvent-based
extraction process
must be sized to process a majority of bitumen that is not produced. This is
costly because the
process equipments used in solvent extraction of oil sands have certain
sealing and safety
requirements to ensure that solvent remains contained. These requirements are
significantly more
expensive to meet than are the requirements of water-based extraction
equipments. Thus, it is

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desirable to reduce the amount of recycle bitumen while maintaining the
advantages provided by
having dissolved bitumen in the extraction liquor.
[00380] The embodiment described herein additionally addresses the issue of
directing large
solid streams to a solvent-based extraction process. Solids that are directed
to a solvent-based
extraction process necessarily come into contact with solvents that absorb
into the pores of the
solids and coat the surface of the solids. In order for these solids to be
introduced back into the
environment, almost all the solvent must be removed from them. Unfortunately,
a tremendous
amount of energy is usually required to evaporate the solvent from the solids
in typical tailings
solvent recovery units of a solvent-based extraction process. This energy
requirement has been
one of the major factors preventing the wide application of solvent-based
extraction technology to
the oil sands industry. Thus, it is also desirable to reduce the amount of
solids processed within a
solvent-based extraction process per unit of bitumen produced.
[00381] An embodiment described herein discloses the use of a water-based
extraction
process to extract from oil sands a bitumen-rich stream comprising a bitumen
to solids ratio that is
greater than that of the oil sands. Specifically the bitumen-rich stream has a
bitumen to solids ratio
of greater than 0.2:1. The water extracted bitumen-rich stream is mixed with a
solvent to produce
the extraction liquor that is then used to solvent extract bitumen from
additional oil sands.
[00382] Further, there is described herein an embodiment in which a water-
based extraction
process is used to extract from oil sands a bitumen-rich stream comprising a
majority bitumen with
water and solids making up the minority components of the stream. The water
extracted bitumen-
rich stream is mixed with a solvent to produce the extraction liquor that is
then used to solvent
extract bitumen from additional oil sands. The bitumen-rich stream may be a
bitumen forth stream
from a water-based extraction process.
[00383] Utilization of a bitumen-rich stream from water-based extraction
process, as a source
of bitumen for the extraction liquor of a solvent-based extraction process has
advantages over the
conventional option of further processing said bitumen-rich stream in the
water-based extraction
process. For example, a reduction in water use and/or required water quality
within the water-based
extraction process may be realized since the bitumen-rich stream will be
further processed in a
solvent-based extraction process. Another advantage include that the bitumen
yield of a solvent-
based extraction process can be three-fold higher, or even greater, than
conventional solvent-based
extraction processes where bitumen in the extraction liquor is bitumen that is
recycled within the
process. While the cost of the solvent-based extraction facilities is high,
this increased yield may
more than offset the added cost associated with operating and integrating
water-based and solvent-
based extraction facilities.

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[00384] In the application of certain described embodiments, an amount of the
solids within
the oil sands are separated from the bitumen-rich stream prior to the bitumen-
rich stream mixing
with the solvent. Advantageously, these separated solids will not add to the
load on the tailings
solvent recovery unit of the solvent-based extraction process. Furthermore, in
the cases where the
oil sands processed in the water-based extraction process are high or medium
grade oil sands, or
more preferably only high grade oil sands, the separated solids are mostly
coarse sands grains that
may be easily dewatered and prepared for reclamation.
[00385] In the exemplary solvent-based extraction and solids agglomeration
processes
described above, a bridging liquid (i.e. water) is added to the extraction
process in order to
agglomerate fines for improved solid-liquid separation. Water may be added,
for example, in the
form of steam to heat the initial slurry or as a component of an input stream.
The bitumen-rich
stream, derived from water-based extraction, may have a water content from 40
to 20 wt%, and thus
can serve as the water source needed for solids agglomeration in the solvent-
based extraction
process.
[00386] The majority of the water and solids within the bitumen-rich stream
can bind with the
solids of the solvent extracted oil sands. Thus, the solvent-based extraction
process can effectively
displace or reduce the function of the froth treatment unit used in a
conventional water-based
extraction process. The produced bitumen from the solvent-based extraction
process, which
comprises bitumen from the bitumen-rich stream as well as bitumen derived
directly from solvent
extraction of oil sands, may have a BS&W of approximately 2 to 3 wt%, ore more
preferably
between 0.1 to 2wt%. This bitumen quality is similar to the quality of bitumen
produced from the
naphthenic froth treatment process of a conventional water-based extraction
process.
[00387] Advantageously, this embodiment combines product cleaning of bitumen
froth with
additional bitumen extraction from oil sands. The produced bitumen ultimately
formed as a result of
the solvent extraction steps, as is, may be sent to an upgrader. An additional
product cleaning step
may be utilized to advantageously remove residual solids and water in order
for the produced
bitumen to meet the fungible specification. Gas flotation or membrane
filtration may be used as
suitable product cleaning methods.
[00388] Figure 15 shows a flow chart of the steps involved in the embodiment
in which a
bitumen-rich stream of a water-based extraction process is directed to solvent-
based extraction. The
process (1500) permits recovery of bitumen from oil sands. The process
comprises: extracting
(1502) bitumen from oil sands in a water-based extraction process to form a
bitumen-rich stream
and a bitumen-lean streams. The bitumen-rich stream is defined as a stream
with a bitumen to
solids ratio that is greater than that of the oil sands. Instead of further
processing the bitumen-rich

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stream within a water-based extraction process, such as a naphthenic froth
treatment unit, the
bitumen-rich stream is directed to a solvent-based extraction process. The
bitumen-rich stream is
mixed (1504) with a solvent to form an extraction liquor. The solvent may be
derived from a
recycled source of solvent, and may be interchangeably referred to as an
extraction liquor. The
bitumen-rich stream may optionally mix with a solvent with recycled bitumen
entrained therein. The
extraction liquor is then mixed (1506) with additional oil sands to form a
slurry comprising solids and
bitumen extract. The solids are then separated (1508) from the slurry to form
a low solids bitumen
extract. Solvent is then recovered (1510) from the bitumen extract to form a
solvent extracted
bitumen product.
[00389] Figure 16 illustrates a process (1600) in which extraction liquor
(1602) used in a
solvent-base extraction process (1604) is produced by mixing solvent (1614)
with a bitumen-
enhanced stream (1606), which may specifically be froth, derived from a water-
based extraction
process (1608). High grade (low fines) oil sands (1610) may preferentially be
directed to the water-
based extraction process (1608) in order to reduce the required intensity of
the this process when
compared with the intensity of the process if a lower grade oil sands are
used. Low grade oil sands
(1612) and/or medium grade oil sands can be directed to the solvent-based
extraction process
(1604) to maximize bitumen recovery. The bitumen-enhanced stream (1606) from
the water-based
extraction process (1608) is mixed with the solvent (1614) in an extraction
liquor mixing vessel
(1616) to form an extraction liquor (1602). The solvent (1614) may have
recycle bitumen dissolved
therein.
[00390] The extraction liquor (1602) derived from the mixing vessel (1616) is
mixed with oil
sands (1612) in the solvent-based extraction process to extract bitumen from
the low grade oil
sands (1612). The solvent (1614) is eventually recovered from the bitumen
extract and solvent wet
solids formed in the solvent-based extraction process (1604), yielding a
bitumen product (1618) and
solid dry tailings (1620). Some of the recovered solvent is then redirected
back to the extraction
liquor mixing vessel (1616), while the bitumen product can be directed to
further processing,
rendering a fungible product, and/or can be utilized as is. Solid dry tailings
(1620) resulting from the
solvent-based extraction process will generally have a low bitumen, low
solvent, and low water
content, and are suited for storage, for example as backfill to a spent mine.
In this way, the volume
of water wet tailings (1622) formed as a result of water-based extraction, can
be reduced when the
bitumen-enhanced stream (1606) is ultimately processed by the solvent-based
extraction process
(1604).

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[00391] (E) Water-Assisted Deasphalting Technologies for Streams Derived from
Solvent-Based Extraction
[00392] As described below, a process of deasphalting is described through
which residual
fine solids and residual water droplets can be removed from a bitumen stream
derived from a
solvent-based extraction process, utilizing a water-assisted deasphalting
technology.
[00393] A goal in the extraction of bitumen from a mining operation such as
oil sands mining
is ultimately to produce a fungible bitumen product that can be pipelined and
sold to refineries
located considerable distances from the mining operation. An exemplary
fungible bitumen product is
a product that has been partially deasphalted and has a solids content of 300
ppm or less on a
bitumen basis. Paraffinic froth treatment (PFT) of the water-based extraction
process is the only
technology in current use that produces a fungible bitumen product from water
extracted bitumen.
[00394] A bitumen product meeting the fungible requirement of less than 300
ppm solids may
be refined in a downstream process, such as hydroprocessing, without danger of
dramatically
fouling the downstream equipment. In some of the previously known solvent-
based extraction
processes, such as those discussed above within the background section, the
resulting bitumen
product may typically have a solids content of approximately 0.1 to 2 wt% on a
bitumen basis. The
water content of such a bitumen product is usually less than 1 wt%. Although
the solids and water
content of a product of a solvent-based extraction process is much less than
that of bitumen froth
produced in a conventional water-based extraction process, the residual fine
solids and water
content may still render the solvent extracted bitumen product unsuitable for
marketing. Removing
residual fine solids and water droplets from solvent extracted bitumen to
achieve a fungible product
is difficult using conventional solids separation methods such as gravity
settling, centrifugation or
filtering. A water-assisted deasphalting process, similar to what is used to
produce a fungible
bitumen product from water-based extraction froth, is described herein for the
final product cleaning
of solvent extracted bitumen.
[00395] The water-assisted deasphalting step can be integrated with the
solvent-based
extraction process in the following manner. The bitumen extraction occurs in
an extraction stage
using a solvent that dissolves the bitumen from the oil sands, forming a
solvent-based extraction
slurry. The slurry is then directed to a solids separation stage where most of
the solids are removed
from the diluted bitumen. In an exemplary embodiment, the resulting low solid
content diluted
bitumen is then sent to a solvent recovery unit where the extraction solvent
is separated from the
bitumen. The resulting low solids bitumen, with some or all solvent removed,
is then directed to the
product cleaning unit, where it is mixed in a controlled fashion with a water-
containing stream and
optionally with a solvent. Examples of water-containing streams, which are not
limiting but provided

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CA 02740481 2011-05-17

here by way of example, include process water and water-based extraction
streams such as
bitumen froth, middlings, flotation tails, froth treatment tails, and mature
fine tailings. The water-
containing stream is added in an amount no greater than that which keeps the
hydrocarbon phase
as the dominant phase by volume of the mixture. However, the water-containing
stream is also
added in a sufficient amount such that when the mixture is partially
deasphalted and introduced into
a gravity settling vessel, relatively large asphaltene flocs comprised of
water, solids, and precipitated
asphaltenes form. Large asphaltene flocs are generally defined as flocs that
are significantly
greater in size than the asphaltene flocs that would form in the absence of
added water.
Specifically, the large asphaltene flocs have a hydraulic diameter in the
range of 1000 to 10 m, or
more preferably in the range of 500 tol 00 m .
[00396] In the water-assisted deasphalting process, the bitumen and water-
containing stream
mixture is well mixed so that a water-in-bitumen emulsion is formed,
containing water droplets of
about 100 microns or less in size. A mixture with these properties is similar
to froth formed in a
conventional water-based extraction process, and thus may be partially
deasphalted in a system
similar to or the same as existing paraffinic froth treatment (PFT) units.
Thus, the known advantages
of PFT units over conventional deasphalting units may be applied to the
product cleaning of solvent
extracted bitumen.
[00397] The process described herein may have an advantage over previously
proposed
deasphalting technologies for solvent extracted bitumen products. Formation of
a water-in-bitumen
emulsion can facilitate the removal of asphaltenes from bitumen. One possible
explanation for this
advantage is the heteroflocculation of water droplets, fine solids and
asphaltenes into larger and
denser flocs. In the process described herein, added water and optionally
added water-wet fine
solids are made to flocculate with the residual solids and residual water
remaining in solvent
extracted bitumen and the precipitated asphaltenes to form flocs that are
larger and denser than
those formed in the absence of added water. For this reason, the flocs formed
according to the
process described herein will settle at a much faster rate and result in much
faster throughputs for
the deasphalting unit compared to in traditional deasphalting processes.
[00398] In an exemplary embodiment of the process, a water-containing stream
is added in a
sufficient amount such that when the mixture is partially deasphalted and
introduced into a gravity
settling vessel, the dominant fluid within the settling phase is water. The
presence of water as the
dominant fluid limits the entrainment of bitumen (specifically maltenes) and
solvent within the
underflow of the settler. Thus, this embodiment allows for higher bitumen
yield. Also, the reduced
amount of solvent in the underflow may allow for a tailings solvent recovery
unit that consists of

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CA 02740481 2011-05-17

flash drums rather than the energy intensive fractionation towers used in
traditional deasphalting
units.
[00399] In traditional deasphalting processes, the tailings solvent recovery
unit must be
heated above the minimum asphalt pumping temperature to ensure that the
asphaltenes will be
pumpable after the solvent is removed. This high temperature requirement
reduces the thermal
efficiency of the deasphalting unit. The addition of a water-containing stream
to the solvent extracted
bitumen, as described herein, eliminates the need to melt the asphaltenes. The
presence of water
ensures that the precipitated asphaltenes and other solids remain fluidized
both within the bottom of
the settling vessel and within the tailings solvent recovery unit (TSRU) at
moderate temperatures.
[00400] Appropriate sources of water and water-wet fines for use in the
process described
herein include water-based extraction streams such as mature fines tailings,
middlings and flotation
tails. Mixing one or more of these streams with the bitumen product from the
solvent-based
extraction, may allow for the recovery of some of the bitumen entrained within
these water-based
extraction streams. Thus, increase bitumen recovery from low hydrocarbon-
containing streams of
water-based extraction may be realized in the application of the water-
assisted deasphalting
process described herein.
[00401] The solvent extracted bitumen product mixed with water and optionally
water-wet
fines, bears similarity to deaerated bitumen froth formed in a conventional
water-based extraction
process. For this reason, conventional paraffinic froth treatment
methodologies can be readily
adapted with minor modification, to serve as the basis of the water-assisted
deasphalting technology
for the mixture of the solvent extracted bitumen product and the water-
containing stream
[00402] Processes are described herein for product cleaning of bitumen from a
solvent-based
extraction process to produce a fungible bitumen product. The bitumen may have
a combined
solids and water content of about 2 to 5 wt. %, while the cleaned bitumen
product may be a fungible
product with less than 300 ppm solids. To achieve pipeline specifications, a
product can be
produced having 0.5 wt. % or less of bottom sediment and water. The product
cleaning may be
accomplished using the water-assisted deasphalting process described herein.
[00403] Embodiments of the water-assisted deasphalting process described
herein result in a
solvent extracted bitumen stream with a reduced solids and water content. The
resulting bitumen
product may be a fungible product appropriate for transportation and refining.
For example, a
fungible product may be one with a fines content of less than 300 ppm on a
bitumen basis. Should
the pipeline and downstream refining requirements be adjusted to require a
solids content of less
than 300 ppm, the water-assisted deasphalting process has been shown to
produce bitumen

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product of much less than 300 ppm solids content on a bitumen basis. For
example, product quality
of 50 ppm or less is achievable.
[00404] Embodiments of the process may differ from previously described
deasphalting
processes for product cleaning of bitumen in that water, and optionally water-
wet fines, may be
mixed with a solvent extracted bitumen stream prior to asphaltene
precipitation. Mixing occurs, so
that a water-in-bitumen emulsion is formed which contains water droplets, on
average of less than
100 microns in size. The addition of water to the solvent extracted bitumen
stream may result in
advantages in the deasphalting process, compared to traditional deasphalting
processes used in the
absence of a significant amount of water, such as those used in refineries to
process heavy crude
oils to upgrade heavy bottoms streams to deasphalted oil. Potential advantages
include increased
thermal efficiency, increased settling rates leading to higher throughputs,
and a higher product yield.
Processes and systems which can be integrated with solvent-based extraction
processes are
described herein.
[00405] The solvent-based extraction process, with which the water-assisted
deasphalting
processes and systems described herein may be integrated, produces a low
solids bitumen product.
The solvent-based extraction process may be, but is not limited to, solvent-
based extraction
processes described below or a part thereof, or may be a known solvent-based
extraction process,
such as processes described herein as background, or a part thereof. For
example, the solvent-
based extraction process which produces a low solids bitumen product may be,
but is not limited to,
the one described in Canadian Patent Application No. 2,724,806,
[00406] In a solvent extraction and solids agglomeration process such as
described herein,
the resulting diluted bitumen stream may have a solid content of approximately
0.1 to 2 wt% on a
bitumen basis. The water content of the diluted bitumen may be much less than
1 wt%. Although
the solids and water content of the solvent extracted bitumen stream are much
less than that of
bitumen froth produced in a typical water-based extraction process, the
residual fine solids and
water content still render the solvent extracted bitumen stream unsuitable for
marketing. Removing
residual fine solids and water from the solvent extracted bitumen is difficult
using conventional solid
separation methods such as gravity settling, centrifugation or filtering. For
this reason, a water-
assisted deasphalting process, similar to what is used to produce a fungible
bitumen product from
bitumen produced in a water-based extraction process, is employed in the
processes described
herein, for the final product cleaning of solvent extracted bitumen.
[00407] The water-assisted deasphalting process described herein is generally
integrated
with the solvent-based extraction and solids agglomeration process in the
following manner.
Solvent extraction of bitumen occurs in an extraction stage using a solvent
that dissolves the
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CA 02740481 2011-05-17

bitumen from the oil sands to form an oil sand slurry. Some asphaltene
precipitation may be
allowed to occur in the extraction step if it is deemed beneficial to product
cleaning and/or solids
agglomeration. A bridging liquid, such as water, is added to the slurry to
agglomerate the solids.
The agglomerated slurry is sent to a solids separation stage where most of the
solids are removed
from the diluted bitumen. In an embodiment described herein, the low solids
content diluted
bitumen stream is then sent to a solvent recovery unit where the extraction
solvent is separated
from the bitumen to form a low solids bitumen product.
[00408] The resulting low solids bitumen, which is no longer diluted by
solvent, is then
directed to the product cleaning unit, where it is mixed in a controlled
fashion with a water-
containing stream and optionally with a solvent. Examples of water-containing
streams include, but
are not limited to, process water and water-based extraction streams such as
bitumen froth,
middlings, flotation tails, froth treatment tails and mature fine tailings.
The water-containing stream
is added in an amount no greater than that which keeps the hydrocarbon phase
as the dominant
phase by volume of the mixture. However, the water-containing stream is also
added in a sufficient
amount such that when the mixture is partially deasphalted and introduced into
a gravity settling
vessel, relatively large asphaltene flocs comprised of water, solids and
precipitated asphaltenes
form. Large asphaltenes flocs are generally defined as flocs that are
significantly greater in size
than the asphaltene flocs that would form in the absence of added water.
Specifically the large
asphaltene flocs have a hydraulic diameter in the range of 1000 to 10 m, or
more preferably in the
range of 500 to 100 m . Furthermore, the bitumen and water-containing stream
mixture is well
mixed so that the formed water-in-bitumen emulsion contains water droplets of
less than 100
microns in size. A mixture with these properties is similar to water-based
extraction froth, and thus
the mixture may be partially deasphalted in a system similar to existing
paraffinic froth treatment
(PFT) units. Thus, the known advantages of PFT units over conventional
deasphalting units may be
applied to the product cleaning of solvent extracted bitumen.
[00409] The integration of a deasphalting process with a solvent-based
extraction and
agglomeration process may have potential advantages over existing product
cleaning processes for
solvent extracted bitumen. For instance, the fungible product may be produced
regardless of the
wetting behaviour of the residual solids. A single solvent or a solvent
mixture of two or more
solvents (for examples, aromatic and paraffinic solvents) may be used for a
combined bitumen
extraction in the agglomerator and water-assisted deasphalting in the product
cleaning unit. Such a
system would require only one solvent recovery unit. Additionally, the
tailings solvent recovery unit
for the product cleaning unit may be integrated with that of an existing
solvent-based extraction
process.

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CA 02740481 2011-05-17

[00410] Advantageously, a water-in-bitumen emulsion, as described herein, may
facilitate the
partial or full deasphalting of a bitumen stream. See Fuel Processing
Technology Vol 89 (2008) 933-
940 and Fuel Processing Technology, Vol 89 (2009) 941-948. These articles
suggest that a water-
in-bitumen emulsion may facilitate the removal of asphaltene from bitumen.
Although the
mechanism by which emulsified water-in-bitumen facilitates the removal of
asphaltenes from
bitumen is not fully understood, one possible explanation, given in the above
articles, is the
heteroflocculation of water droplets, fine solids and asphaltenes into larger
and denser flocs. As
described herein, added water and optionally added water-wet fine solids are
made to flocculate
with the residual solids and residual water remaining in solvent extracted
bitumen and the
precipitated asphaltene to form flocs that are larger and denser than those
formed when added
water is absent. For this reason, the flocs formed according to the process
described herein may
settle at a faster rate and result in faster throughputs for the water-
assisted deasphalting unit than
traditional deasphalting units.
[00411] As described herein, a water-containing stream is said to be added at
a sufficient
amount such that when the mixture is partially deasphalted and introduced into
a gravity separation
vessel, the dominant fluid within the settling phase is water. The presence of
water as the dominant
fluid limits the entrainment of bitumen (specifically maltenes) and solvent
within the underflow of the
settler. This advantageously allows for higher bitumen production. Also, a
reduced amount of
solvent in the underflow may allow for a tailings solvent recovery unit that
consists of flash drums
rather than the energy intensive fractionation towers used in traditional
deasphalting units.
[00412] In traditional deasphalting technology, the tailings solvent recovery
unit must be
heated above the minimum asphalt pumping temperature to ensure that the
asphaltenes will be
pumpable after the solvent is removed. This high temperature requirement
reduces the thermal
efficiency of the deasphalting unit. The addition of water to the solvent
extracted bitumen as
described herein eliminates the need to melt the asphaltenes. The presence of
water ensures that
the precipitated asphaltenes, and other solids, remain fluidized both within
the bottom of the
separation vessels and within the tailings solvent recovery unit (TSRU) at
moderate temperatures.
[00413] Good sources of water and water-wet fines as described herein include
water-based
extraction streams such as mature fines tailings, middlings and flotation
tails. Mixing one or more of
these streams with the bitumen product from the solvent-based extraction may
allow for the
recovery of some of the bitumen within these water-based extraction streams.
Thus, embodiments
described herein may permit increased bitumen recovery when integrated with
water-based
extraction streams that contain bitumen.

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[00414] The solvent extracted bitumen product mixture with water, and
optionally water-wet
fines, may be similar to the deaerated bitumen froth of the water-based
extraction process. For this
reason, a conventional paraffinic froth treatment technology can be adapted
for use in streams
derived from solvent-based extraction processes with minor modifications, and
thus can possibly be
used as the deasphalting unit for the mixtures within embodiments described.
Advantageously, in
one embodiment, a solvent extracted bitumen product is mixed in a ratio of
1:3, or less, with a
deaerated bitumen froth from a water-based extraction process. In this way,
the solvent extracted
bitumen product can undergo product cleaning in existing paraffinic froth
treatment units of a water-
based extraction facilities.
[00415] Figure 17 provides an overview of an exemplary process (1700) for
product cleaning
a bitumen stream derived from a solvent-based extraction process. The process
permits removal of
solids from oil sands. An oil sands slurry is formed (1702) by mixing the oil
sands with a first
solvent, where the amount of solvent added is greater than 10 wt% of the oil
sands. Subsequently a
majority of the solids are separated (1704) from the oil sands slurry, forming
a solids-rich stream
and a bitumen-rich stream, wherein the bitumen-rich stream comprises residual
solids and residual
water. The bitumen-rich stream is emulsified (1706) with a water-containing
stream to form a
hydrocarbon-external emulsion, wherein hydrocarbons form an external phase of
the emulsion. The
hydrocarbon-external emulsion is mixed (1708) with a second solvent in
sufficient quantity to cause
some asphaltene precipitation, wherein precipitated asphaltenes flocculate
with at least a portion of
the residual solids and water droplets. Subsequently the asphaltene flocs,
comprised of water,
solids and precipitated asphaltenes, are separated (1710) from the hydrocarbon-
external emulsion,
thereby forming a cleaned hydrocarbon stream comprising fungible bitumen and
solvent, and
tailings comprising water, solids, and precipitated asphaltenes.
[00416] Figure 18 provides a schematic representation of the integration of
solvent-based
extraction with a water-assisted deasphalting process (1850) for the
production of a fungible
bitumen product. An optional stage of solvent recovery (1807) is used to
remove some or all of the
solvent from the bitumen extract. The resulting stream of low solids bitumen
(1808) is mixed with a
water containing stream (1812) in an emulsification unit (1811). Examples of
water-containing
streams include, but are not limited to, process water, bitumen froth, mature
fine tailings, middlings,
flotation tails and froth treatment tailings. In general, the requirement of
the water-containing stream
is that it is added to the bitumen stream in a sufficient amount that when the
formed emulsion is
deasphalted, water is the dominant fluid within the settling phase, where the
settling phase is
additionally comprised of precipitated asphaltenes and solids. The water-
containing stream may
optionally have water-wet fines within.

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[00417] In the depicted process (1850), an oil sands feed (1800) is extracted
in an extraction
stage (1802), in the presence of an extraction solvent (1801). A diluted
bitumen slurry (1803) is
formed. For a solvent-based extraction and solid agglomeration process, such
as described herein,
the extraction stage may include a mixbox and an agglomerator. The mixbox is
used to from a slurry
comprised of the oil sands feed (1800) and extraction solvent (1801). Bridging
liquid may be added
to the slurry within the agglomerator to agglomerate the fine solids. The
diluted bitumen slurry
(1803) is forwarded to a solid liquid separation stage (1804), whereupon
solvent wet solids (1806)
are removed in and sent to a tailings solvent recovery unit (1809), from which
dry tailings (1810) are
produced. Diluted bitumen (1805) derived from the solid liquid separation
stage (1804) is sent on to
solvent recovery (1807), from which a stream of low solids bitumen (1808) is
derived. A
countercurrent washing is often included in the solid-liquid separation stage
to minimize the amount
of bitumen extract remaining with the solids. For example, solid-liquid
separation may involve a
combination of a gravity settler and belt filter with countercurrent washing.
A second solvent of
lower boiling point and/or lower solids adsorption energy than the extraction
solvent (1801) may be
used as the washing solvent in order to improve solvent recovery in the
tailing solvent recovery unit
(1809).
[00418] In the solvent-based extraction and solids agglomeration process
described herein,
the stream of low solids bitumen (1808) may be of sufficient quality that it
may be directed to an on-
site upgrader. However, if a fungible bitumen product is desired; the low
solids bitumen (1808) must
be directed to a special product cleaning unit; that is a water-assisted
deasphalting unit (1816). As
illustrated in Figure 18, the stream of low solids bitumen (1808) is forwarded
to a water-assisted
deasphalting unit (1816) comprising an emulsification unit (1811) and a
deasphalting unit (1813).
Within the water-assisted deasphalting unit (1816), the emulsification unit
(1811) receives the
stream of low solids bitumen (1808) arising from the solvent-based extraction
process, and
combines the stream with a water containing stream (1812). Within the
emulsification unit (1811), a
water-in-bitumen emulsion (1822) is formed, and forwarded to the deasphalting
unit (1813). A
deasphalting solvent (1814) is added to the emulsion (1822) within the
deasphalting unit, and froth
separation occurs to ultimately produce a fungible bitumen product (1815).
[00419] Similar to the paraffinic froth treatment unit of a water-based
extraction process, the
deasphalting unit (1813) utilized in this process may comprise two settling
units. The first settling
unit (FSU 1) is used to separate the clean diluted bitumen from the water
phase containing
precipitated asphaltenes and solids. The second settling unit (FSU 2) is used
to wash the underflow
of FSU 1 in order to recover the maltenes entrained in the FSU 1 underflow.

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[00420] In embodiments of the process described below with respect to Figures
19 and
Figure 20, processes are depicted in which a solvent-based extraction facility
is integrated with
water-based extraction facility in order to take advantage of synergies gained
from the integration of
the processes. One advantage of integrating solvent-based extraction with
water-based extraction
is that paraffinic froth treatment, which is traditionally used to produce a
fungible bitumen product
from bitumen froth, may also be used to remove the residual contaminants
within solvent extracted
bitumen. Paraffinic froth treatment can be utilized with product streams
derived from both solvent-
based extraction and water-based extraction in order to remove residual solids
and water from these
streams.
[00421] In an embodiment of the process described herein, paraffinic froth
treatment of a
water-based extraction process is integrated with a solvent-based extraction
process. Bitumen
extraction occurs in an extraction stage of the solvent-based extraction
process using a solvent that
readily dissolves the bitumen from oil sands, thereby forming a slurry. The
oil sands slurry is sent to
a solids separation stage where most of the solids are removed from the oil
sands slurry to form a
low solids bitumen extract. A residual amount of solids and water remain with
the low solids
bitumen extract. Further residual solids and water need to be removed from the
bitumen extract
because they hinder downstream processing of the bitumen. The bitumen extract
is then sent to a
solvent recovery unit where the extraction solvent is separated from the
bitumen. The solvent-free
bitumen with residual solids and residual water (low solids bitumen) is then
directed to the paraffinic
froth treatment unit of a water-based extraction process in order to remove
residual solids and water
from the low solids bitumen.
[00422] In another embodiment of the process described herein, a low solids
bitumen product
derived from a solvent-based extraction process, which has a solids and water
content higher than
desired in a fungible product, may be combined with a cleaner stream derived
from paraffinic froth
treatment of a water-based extraction process to achieve, on balance, a
fungible product. A
fungible bitumen product contains bitumen together with a solids content of
less than 300 ppm on a
bitumen basis. Removing residual fine solids from the solvent extracted
bitumen is difficult using
conventional solid separation methods such as gravity settling, centrifugation
or filtering, and thus,
allowing some residual solids and water to remain in a solvent extracted
product, while mixing with a
fungible bitumen product, which has a solids content much less than 300 ppm,
permits formation of
a combined product that still meets the required specifications.
[00423] Figure 19 provides an overview of a process (1900) in which paraffinic
froth
treatment of a water-based extraction process is used to remove residual
solids and residual water
within a bitumen product stream derived from solvent-based extraction. The
process (1900) permits
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removal of solids from oil sands comprising bitumen and solids. Oil sands are
mixed (1902) with a
first solvent to form an oil sands slurry, wherein the amount of solvent added
is greater than 10 wt%
of the oil sands. A majority of the solids are separated (1904) from the oil
sands slurry to form a
solids-rich stream and an initial bitumen-rich stream, where the initial
bitumen-rich stream comprises
residual solids and residual water. The solvent is removed (1906) from the
initial bitumen-rich
stream to form a solvent depleted bitumen-rich stream. Optionally, additional
oil sands are mixed
(1908) with water, wherein the amount of water added is greater than 50 wt% of
the oil sands, to
form bitumen froth, wherein the bitumen froth comprises bitumen, solids and
water. The optionally
formed bitumen froth is directed (1910) to a paraffinic froth treatment
process of a water-based
extraction process. Further, at least a portion of the solvent-depleted
bitumen-rich stream is
directed (1910) to the paraffinic froth treatment process of a water-based
extraction process. A
fungible bitumen product is thus derived (1912) from the paraffinic froth
treatment process.
[00424] Figure 20 shows a typical paraffinic froth treatment unit (2000)
having at least two
settling vessels or settling regions. The first froth settling unit FSU 1
(2004) is used to precipitate a
fraction of the asphaltenes found in the bitumen froth (2008). Precipitated
asphaltenes form large
flocs with the residual solids and water that rapidly settle out by gravity
separation or enhanced
gravity separation. In FSU 1 (2004) it desirable to minimize the amount of
asphaltenes precipitated
to the minimum amount needed to flocculate all the solids and water.
[00425] Low solids bitumen may feed into the paraffinic froth treatment unit
of Figure 20 at
various potential stages upstream of the paraffinic froth treatment unit FSU 1
(2004).
[00426] A low solids bitumen stream derived from a solvent-based extraction
process can be
mixed with the other feeds going to FSU 1 (2004). Although not depicted, the
low solids bitumen
may mix with a feed going to an intermediate settling vessel. It is not
desired to mix low solids
bitumen with the feed entering the last settling vessel of a paraffinic froth
treatment unit, depicted
here as the second froth settling unit FSU 2 (2006), because this settling
vessel is typically used to
limit loss of bitumen to the tailings, and specifically the loss of the
maltene components of bitumen
to the tailings.
[00427] Bitumen froth (2008) is provided to a mixer (2010), optionally with
the low solids
bitumen (2002b) derived from the solvent-based extraction process. A mixed
solution including
overflow (2012) from the second froth settling unit (2006) can also be added.
The composition so
mixed is directed to FSU 1 (2004), from which underflow is mixed with solvent
from the solvent
recovery unit (2014), and then the mixture is directed to FSU 2 (2006). The
underflow of the FSU 2
(2006) can be directed to a tailings solvent recovery unit (2016), from which
a tailings stream (2018)
comprising asphaltenes, solids and water is derived. The overflow (2005) from
FSU 1 is directed to

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a solvent recovery unit (2014) to ultimately produce a fungible bitumen
product (2024). The bitumen
product (2026) derived from SRU (2014) may optionally be combined with
additional low solids
bitumen (2002a) from a solvent-based extraction process not shown, in order
that the combined
streams becomes a fungible product (2024), as it meets the threshold of
fungible specifications.
The resulting fungible product (2024) can be transported via pipeline and
utilized in downstream
refining processes.
[00428] In an optional embodiment, Figure 20 represents a process in which the
bitumen
product (2026) arising from solvent recovery unit (2014) produced by
paraffinic froth treatment may
have a solids content that is much less than the fungible limit. In that case,
the low solids bitumen
(2002a) from the solvent-based extraction process may bypass the paraffinic
froth treatment
process and directly mix with the bitumen product (2026) arising from SRU
(2014) and still yield a
combined stream (2024) that meets fungible specifications.

[00429] (F) Directing Solvent Extracted Bitumen Product to Water-based
Extraction
[00430] The embodiment described herein involves directing the product of a
solvent-based
extraction process into a water-based extraction process at one or more stages
prior to froth
treatment, resulting in increased bitumen recovery and a higher quality
bitumen froth.
[00431] Often a poor froth quality and low recovery rates (<_ 90 %) of bitumen
from extraction
of low grade oil sands ore are problems encountered when using conventional
water-based
extraction processes. Recovery of bitumen from oil sands via a water-based
extraction processes
may drop below the desired recover rate of 90% or greater when the oil sands
feed quality (ore
grade) contains relatively low amounts of bitumen (<_ 10 wt%) and relatively
high amounts of solid
fines. Additionally, the quality of the recovered bitumen froth from the water-
based extraction of low
grade ore is also poor. Good bitumen froth has a bitumen content of
approximately 60 wt%.
However, the extraction of low grade ore typically yields a froth with bitumen
content less than 50
wt%. The mining and extraction of oil sands is an energy intensive and
expensive process. For
these reasons, maximizing the recovery of mined bitumen is determinative of an
operation's rate of
return.
[00432] In water-based extraction processes for low grade oil sands, the
majority of un-
recovered bitumen remains in the middlings. Due to the reduced amount of
bitumen, the small
bitumen droplets in the middlings fail to collide at a sufficient frequency to
coalesce into larger
droplets that can readily attach to the air bubbles needed for recovery. The
aeration of the bitumen
droplets is also hindered by fine particles or "fines" coating the surface of
the small bitumen droplets.
Fines may act as barriers preventing both coalescing of bitumen droplets and
air bubble attachment.
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[00433] Improved bitumen recovery and froth quality from low grade oil sand
can be realized
in a conventional water-based extraction process by blending of different
grades of oil sands in
order to create a more consistent feed to the front end stage of the water-
based extraction process,
such as in the oil sands crushing stage. Blending of varying grade of oil sand
ores allows for high
grade oil sands (>_ 10 wt% bitumen) to be blended with low grade oil sands
(510 wt% bitumen) in
order to produce an average grade ore that gives more consistent bitumen
recoveries of >_ 90 % and
froths that have of approximately 60 wt% bitumen content. However, the
blending of varying ores
has significant capital expenditure (CAPEX) and operational expenditure (OPEX)
implications as
mining logistics complexity increases and trucking requirements increase.
[00434] According to the process described herein, the bitumen product
generated in a
solvent-based extraction process, which is a low-solids bitumen product, is
blended with a bitumen
feed and directed to a stage within a water-based process of bitumen recovery,
which is preferably
upstream of the froth treatment process. Examples of such feed streams with
which the solvent-
based extraction product stream can be mixed include the oil sands slurry in
the slurry preparation
plant and hydrotransport pipeline. The low-solids bitumen product from solvent-
based extraction
may also be mixed with middlings streams undergoing the secondary and/or
tertiary bitumen
recovery stages within a water-based extraction process. The increased levels
of bitumen in the
process will improve the recovery of the original bitumen that was in the
water-based extraction
stream. The increased level of bitumen within the combined stream will also
improve the quality of
the recovered bitumen stream formed at the end of the water-based extraction
process.
[00435] While the mechanism behind the improved bitumen extraction is not
limited by any
one particular physical explanation, it is nevertheless possible that the
added bitumen coalesces
with the small bitumen droplets during stages of the water-based extraction
process to form larger
bitumen droplets that are readily recoverable, for example by attaching to air
bubbles more readily.
Large bitumen droplets are more likely to attach to small bitumen droplets
even in presence of fine
particles which may coat the bitumen droplets. Furthermore, the added bitumen
may also increase
the level of bitumen derived surfactants in the slurry, assisting in the
overall recovery process.
[00436] Figure 21 depicts a flow chart of a process (2100) in which a stream
from solvent-
based extraction is added to an input stream of a water-based extraction
process. According to this
process, a first oil sands ore is contacted (2102) with a solvent to form a
solvent-based slurry
comprising solids together with a bitumen extract. The solids are separated
(2104) from the solvent-
based slurry to produce a low solids bitumen extract. Subsequently, solvent is
removed (2106) from
the low solids bitumen extract to form a solvent extracted bitumen product. In
a step that need not
be conducted sequentially, but which may be conducted in parallel, a second
oil sands ore is

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contacted (2108) with water to form an aqueous slurry. Exemplary aqueous
slurries may be from a
water-based extraction processes such as slurry preparation unit effluent,
primary separation feed,
and secondary and tertiary recovery unit feeds. Subsequently, the solvent
extracted bitumen formed
as a result of the solvent-based extraction process is mixed (2110) with the
aqueous slurry to form a
bitumen enriched slurry. Bitumen may then be recovered (2112) from the bitumen
enriched slurry in
the extraction stages of a water-based extraction process.
[00437] Figure 22 shows a schematic of a process (2200) in which solvent
extracted bitumen
is used to improve bitumen recovery in a water-based extraction process. In
the depicted process,
various locations within a generic water-based extraction facility are
depicted where the solvent
extracted bitumen may be added. Regarding the ore preparation stage (2208),
hydrotransport
pipeline stage (2212), and separation stage (2214), solvent extracted bitumen
(2202a, 2202b,
2202c) may be added at any one or more of these stages. In general, solvent
extracted bitumen
(2202a, 2202b, 2202c) from a solvent-based extraction process is added to a
water-based
extraction process at some stage prior to the froth treatment stage (2204). An
added advantage of
the described embodiment is that the added solvent extracted bitumen will
ultimately be processed
in the froth treatment stage (2204) of a froth treatment unit in the water-
based extraction facilities.
Thus, in the case of paraffinic froth treatment, the residual solids and
residual water that are within
the solvent extracted bitumen will be removed in this final bitumen product
cleaning stage of the
water-based extraction process to produce a fungible bitumen product.
[00438] In the depicted process (2200), oil sand (2206) is prepared for
extraction in an ore
preparation stage (2208). It may be at this stage, when water (2210) is added,
that solvent
extracted bitumen (2202a) may be added, forming a stream containing water,
crushed ore, and
solvent extracted bitumen. It is preferable the solvent extracted bitumen is
added after the oil sand
(2206) and water (2210) slurry is prepared; that is, the effluent of slurry
preparation stage. It is
optional to add the solvent extracted bitumen at this stage, as downstream
optional additions may
alternatively be utilized. From the "slurry preparation" or ore preparation
stage (2208), solvent
extracted bitumen may be directed to any acceptable location upstream of the
separation stage
(2214), such as within a hydrotransport pipeline (2212) as depicted here.
During transport along the
hydrotransport pipeline (2212), solvent extracted bitumen (2202b) may
optionally be added to the
aqueous slurry comprising oil sands. The solvent extracted bitumen (2202b) may
be added at any
point along the hydrotransport pipeline. However, it is advantageous to add
the solvent extracted
bitumen further upstream of the pipeline so as to provide the mixing energy
needed to properly
disperse the solvent extracted bitumen into the aqueous slurry.

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[00439] The separation stage (2214) typically comprises of a primary
separation step and a
secondary separation and optionally a tertiary separation steps. In the
primary separation vessel,
the upper phase may comprise froth, while the lowermost phase comprises of
tailings. The mid-
level phase of such a vessel is comprised of middlings. The middlings and
tailings may be directed
to secondary and tertiary separation steps to recover additional bitumen
froth. The low bitumen
content of the middlings and tails makes additional bitumen recovery in the
secondary and/or tertiary
separation steps difficult. The solvent extracted bitumen (2202c) may be added
to the secondary
and tertiary separation vessels so as to increase the bitumen content within
these vessels. The
added bitumen may coalesce with the small bitumen droplets from the middlings
and tailings during
the separation stages of the water-based extraction process to form larger
bitumen droplets that are
more readily separated from the slurry. For example, large bitumen droplets
are more likely to
attach to small bitumen droplets even in presence of fine particles which may
coat the bitumen
droplets. Furthermore, the added bitumen may also increase the level of
bitumen derived
surfactants in the slurry, assisting in the overall recovery process.
[00440] The bitumen (2218) produced within the separation stage (2214) may be
in the form
of bitumen froth, comprised of both water extracted bitumen and the added
bitumen from the
solvent-based extraction process. The bitumen froth is then directed to a
froth treatment stage
(2204), while tailings (2216) of the separation stage (2214) are processed
separately. The froth
treatment stage is preferably a paraffinic froth treatment unit, which would
yield a fungible bitumen
product (2222) and froth treatment tailings (2220). Thus, the described
embodiment has the added
advantage that the solvent extracted bitumen, which is not a fungible bitumen
product, may
ultimately be processed in a paraffinic froth treatment unit of a water-based
extraction process to
produce a fungible bitumen product suitable from for pipeline transport and
downstream refining.
[00441] (G) Directing Solvent Extracted Tailings to Water-Based Extraction
Process
[00442] A further embodiment described herein involves directing tailings of a
solvent-based
extraction process to a water-based extraction process. Advantages of a
process which combines
solvent extraction with fines agglomeration (particle enlargement) include
improve solid-liquid
separation and improve solvent removal from solid tailings. Further,
production of nominally dry
tailings from this solvent-based extraction process will result in
improvements to tailings
management versus currently practiced water-based extraction processes.
Additionally, the
agglomeration of the fine particles within the dry tailings allows for most of
the solids within the dry
tailings to behave as coarse particles, which may have certain advantages.

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[00443] Dewatering of fine tailings derived from conventional water-based
extraction
processes may involve the use of expensive flocculants and the capital
intensive paste thickener
technology. In the non-segregating tailings technology, the dewatered fine
tailings can be mixed
with dewatered coarse tailings to form a pumpable slurry. The pumpable slurry
is usually made
non-segregating by the addition of coagulants to the slurry and/or lowering
the pH of the slurry. This
technology, in various embodiments, has been proposed for use in new oil sands
mining facilities,
such as, Canadian Natural's Horizon Oil Sands Project. However, dewatering of
the non-
segregating tailings takes a significant amount of time, and depending on
applied shear on the
slurry, it can readily lose its non-segregating properties. Furthermore,
holding areas, or dedicated
disposal areas (DDAs), are needed for the non-segregating tailings since they
are not free-standing.
These holding areas are expensive to maintain. The above described challenges
and others
suggest that there is a need to develop alternative strategies to meeting
tailings management
requirements.
[00444] In an integrated scheme, the dry tailings from the solvent-based
extraction process
may be combined with tailings or partially dewatered tailings (or mature fine
tailings) from the water-
based extraction process in order to yield a combined higher volume of
tailings that are easier to
reclaim. For example, the agglomerated fines produced in the solvent-based
extraction process may
be treated using heat or chemicals so as to reduce the possibility of the
agglomerates disintegrating
in the presence of water. These agglomerated and treated fines can be directed
to the water-based
extraction process where they may serve similar functions as the wet coarse
tailings produced
within the water-based extraction process. For example, the agglomerated fines
can be used in
dyke construction, mine refill, soil enhancement and for direct reclamation
purposes. In a preferred
embodiment, the agglomerated fines may serve the same function of the water
extracted coarse
tailings in the formation of non-segregating tailings.. The increase volume of
coarse-like tailings,
provided by the agglomerated dry tailings from the solvent-based extraction
process, may yield
several advantages. The dry tailings reduces the water content of the non-
segregating tailings,
which translates to a tailings that is more quickly reclaimable. The dry
tailings may also result in the
non-segregating tailings having a higher hydraulic conductivity at a given
solids content, which will
result in faster dewatering and reclamation.
[00445] In an embodiment described herein, dry tailings produced from a
solvent-based
extraction process are mixed with wet tailings produced from a water-based
extraction process to
produce a strengthened tailings mixture. The strengthened tailings are
expected to have improved
properties compared to tailings mixtures produced only with water extracted
tailings. The dry
tailings produced from the solvent-based extraction process preferably contain
fines that have been

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agglomerated during the solvent-based extraction process. It is also preferred
that the dry tailings
produced from solvent-based extraction be heat treated and/or chemically
treated in order to impart
additional strength and/or water-resistance to the tailings. The agglomerated
and treated dry tailings
are expected to behave as material with a particle size distribution similar
to that of coarse particle
tailings even in the presence of water.
[00446] Figure 23 is a flow diagram illustrating steps involved in a process
that integrates dry
tailings from solvent-based extraction into a water-based extraction process.
According to the
process (2300), ore is contacted (2302) with a first solvent to form a first
slurry comprising solids
and a bitumen extract. The bitumen extract is then separated (2304) from the
first slurry to form
solvent wet tailings comprised of the solids and the first solvent. The first
solvent is then removed
(2306) from the solvent wet tailings to form dry tailings. The dry tailings
are then combined (2308)
with water wet tailings produced from a water-based extraction process to form
strengthened
tailings.
[00447] Figure 24 is an illustration of a process (2400) by which a solvent-
based extraction
plant (2402) may be integrated with a water-based extraction and fines
thickening plant (2404) in
order to produce strengthened tailings (2406) of superior quality when
compared with thickened fine
tailings (2407) derived from the thickener (2426) and/or non-segregating
tailings (2408) derived from
the combination of coarse tailings (2432) and thickened fine tailings (2407),
produced as a result of
the water-based extraction process in the water-based extraction and fines
thickening plant (2404).
Dry agglomerates (2410) from the solvent-based extraction plant (2402), also
referred to as
agglomerated tailings, are mixed with non-segregating tailings (2408) from the
water-based
extraction and fines thickening plant (2404). A portion of dry agglomerates
(2410) may be sent to
mine refill (2411), and a portion of dry agglomerates (2410) may be mixed with
non-segregating
tailings (2408). The resulting mixture of strengthened tailings (2406) has a
higher solids content and
greater strength than the non-segregating tailings (2408). Additionally, the
strengthened tailings
(2406) may have improved dewatering properties when compared with the non-
segregating tailings
if the dry agglomerates (2410) are heat treated and/or chemically treated
(process not shown) to
remain intact even in an increased water environment.
[00448] In one embodiment, agglomerates formed in the agglomerator (2438) of
the solvent-
based extraction plant (2402) may be chemically treated by including within
the bridging liquid
(2439) water-soluble adhesives and/or emulsion type adhesives. In another
embodiment,
agglomerates formed in the aggomerator (2438) may be chemically treated by
including within the
bridging liquid (2439) dissolved salts. In yet another embodiment, the
agglomerates may be
chemically treated downstream of the agglomeration process, such as within a
solid-liquid

-90-


CA 02740481 2011-05-17

separation stage and/or within the tailings solvent recovery stage of a
solvent-based extraction
process. In another embodiment, the agglomerates may, in addition to chemical
treatment or in lieu
of chemical treatment, be heat treated by heating the agglomerates to
temperatures greater than
500 C so as to sinter or partially sinter the agglomerates.
[00449] Beneficially, low grade oil sands ore, with a high fines content,
depicted in Figure 24
as high fines ore (2412), can be preferentially directed to solvent-based
extraction in a solvent-
based extraction plant (2402) while medium to high grade oil sands ore, with
medium to low fines
content, depicted as low fines ore (2414), can be preferentially directed to
the water-based
extraction in the water-based extraction and fines thickening plant (2404).
The processing of ore in
this selective fashion, as shown in Figure 24, would reduce the volume of
thickened fine tailings
produced by the water-based extraction process. The fine particles, which are
preferentially directed
to the solvent-based extraction process, may be agglomerated and treated in
order to impart coarse
particle-like properties to these solids. A portion of the coarse tailings
produced as a result of the
water-based extraction process, as described below, can be used for dike
construction as currently
done in existing conventional water-based extraction operations. A portion of
the dry tailings
produced as result of the solvent-based extraction process can be used in dyke
construction, mine
refill, and/or for direct reclamation.
[00450] In the depicted embodiment, a high fines ore (2412) from oil sands is
processed
within the solvent-based extraction plant (2402), while a low fines ore (2414)
from oil sands is
processed in a water-based extraction and fines thickening plant (2404), so
that fines can be
directed primarily to agglomeration steps. Within the water-based extraction
process, the low fines
ore (2414) is directed in a conventional manner to a mix-box (2416) in
preparation for hydrotransport
(2418) toward a primary separation vessel (2420), from which bitumen froth
(2422) is produced and
forwarded to further processing. Middlings derived from the primary separation
vessel are
processed within flotation cells (2424), and fine tailing derived therefrom
are forwarded to a
thickener (2426), resulting in removal of recycle water (2428). The underflow
(2430) from the
primary separation vessel (2420) is dewatered within hydrocyclones (2431) to
produce the
underflows, referred to as coarse tailings (2432) and overflows that are
directed to the flotation cells
(2424). Thickened fine tailings (2407), derived from de-watering of the fine
tailings within the
thickener (2426), is mixed with a portion of the coarse tails derived in this
embodiment from the
hydrocyclones (2431) to produce non-segregating tailings (2408). The non-
segregating tailings
(2408) are combined with a portion of the dry agglomerates (2410) from the
solvent-based
extraction plant (2402) to produce strengthened tailings (2406). A fraction of
coarse tailings (2432)
derived from hydrocyclones (2431) may additionally be used within the mine
site for construction
-91-


CA 02740481 2012-05-10

material and/or reclamation purposes; for example, dike construction.
Likewise, a fraction
of dry agglomerates (2411) may additionally be used within the mine site for
mine refill, as
depicted in Figure 24, or as construction material, and/or for direct
reclamation.
[00451] An exemplary solvent-based extraction plant (2402) is depicted in
Figure
24. This plant conducts a solvent-based extraction and agglomeration process
involving
directing high fines ore (2412) to a mix box (2434) where a slurry is formed
with a solvent
extraction liquor (2436). A slurry is formed, and fines within the slurry are
agglomerated
in an agglomerator (2438), in the presence of a bridging liquid (2439), and
may be
washed on a belt filter (2440) using, for example, countercurrent washing with
progressively cleaner solvent. The bridging liquid (2439) added to the
agglomerator
(2438) may contain an adhesive to help strengthen and impart water resistance
to the
agglomerates. Solvent recovery from the agglomerates can occur in a solvent
recovery
unit (2442), while a hydrocarbon-containing product (2444) is obtained and
forwarded to
further processing. The agglomerates formed in the agglomerator (2438) may be
treated
in the solvent recovery unit (2442) with an adhesive. Additionally, the
solvent recovery
unit may contain a temperature region (or a separate process unit) to heat
treat the
agglomerates to a strengthened state. Dry agglomerates (2410), or tailings,
from the
solvent-based extraction plant (2402) can then be combined with non-
segregating tailings
(2408) produced from the water-based extraction process to provide a
strengthened
tailings (2406). The strengthened tailings (2406) may have improved dewatering
properties and adequate strength so as to be used in formation of reclaimed
land (2454)
in much less time than conventional non-segregating tailings produced only
within a
water-based extraction process. The strengthened tailings (2406) may be pumped
by
pumps (2452) to the reclaimed land (2454) as part of an integrated reclamation
scheme
(2450).

[00452] In the preceding description, for purposes of explanation, numerous
details
are set forth in order to provide a thorough understanding of the embodiments
described
herein. However, it will be apparent to one skilled in the art that these
specific details are
not required in order to practice the described processes.
[00453] The above-described embodiments are intended to be examples only.
Alterations, modifications and variations can be effected to the particular
embodiments
by those of skill in the art.

-92-

A single figure which represents the drawing illustrating the invention.

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Admin Status

Title Date
Forecasted Issue Date 2013-02-12
(22) Filed 2011-05-17
Examination Requested 2011-05-17
(41) Open to Public Inspection 2011-11-21
(45) Issued 2013-02-12

Court Order

Court Order Number 2015 FC 1218
Court Name Federal Court of Canada
Date Received 2015-10-28
English Description The following inventors are removed: Fritz Pierre Jr., Emilio Alvarez, Robert D. Kaminsky, Justin D. Pace, Thomas R. Palmer, David C. Rennard, Payman Esmaeili, Brian C. Speirs.
French Description Les inventeurs suivants sont retirés du brevet : Fritz Pierre Jr., Emilio Alvarez, Robert D. Kaminsky, Justin D. Pace, Thomas R. Palmer, David C. Rennard, Payman Esmaeili, Brian C. Speirs.

To see the full version of the court order please visit the corresponding court's web site.

Maintenance Fee

Description Date Amount
Last Payment 2019-04-15 $200.00
Next Payment if small entity fee 2020-05-19 $100.00
Next Payment if standard fee 2020-05-19 $200.00

Note : If the full payment has not been received on or before the date indicated, a further fee may be required which may be one of the following

  • the reinstatement fee set out in Item 7 of Schedule II of the Patent Rules;
  • the late payment fee set out in Item 22.1 of Schedule II of the Patent Rules; or
  • the additional fee for late payment set out in Items 31 and 32 of Schedule II of the Patent Rules.

Payment History

Fee Type Anniversary Year Due Date Amount Paid Paid Date
Request for Examination $800.00 2011-05-17
Filing $400.00 2011-05-17
Registration of Documents $100.00 2011-09-02
Registration of Documents $100.00 2011-09-02
Special Order $500.00 2012-02-29
Final $420.00 2012-11-27
Maintenance Fee - Patent - New Act 2 2013-05-17 $100.00 2013-04-24
Maintenance Fee - Patent - New Act 3 2014-05-20 $100.00 2014-04-15
Maintenance Fee - Patent - New Act 4 2015-05-19 $100.00 2015-04-13
Maintenance Fee - Patent - New Act 5 2016-05-17 $200.00 2016-04-12
Maintenance Fee - Patent - New Act 6 2017-05-17 $200.00 2017-04-13
Maintenance Fee - Patent - New Act 7 2018-05-17 $200.00 2018-04-12
Maintenance Fee - Patent - New Act 8 2019-05-17 $200.00 2019-04-15
Current owners on record shown in alphabetical order.
Current Owners on Record
IMPERIAL OIL RESOURCES LIMITED
Past owners on record shown in alphabetical order.
Past Owners on Record
None
Past Owners that do not appear in the "Owners on Record" listing will appear in other documentation within the application.

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Abstract 2011-05-17 1 21
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Claims 2011-05-17 18 709
Drawings 2011-05-17 24 400
Representative Drawing 2011-10-20 1 13
Cover Page 2011-11-17 2 55
Description 2012-05-10 92 6,050
Claims 2012-05-10 4 164
Claims 2012-07-11 4 171
Representative Drawing 2013-01-24 1 14
Cover Page 2013-01-24 2 53
Prosecution-Amendment 2012-02-29 1 37
Prosecution-Amendment 2012-03-07 1 16
Prosecution-Amendment 2012-04-03 4 168
Prosecution-Amendment 2012-05-10 7 300
Prosecution-Amendment 2012-06-07 2 82
Prosecution-Amendment 2012-07-11 4 152
Correspondence 2012-11-27 1 35
Correspondence 2015-10-28 8 249