Note: Descriptions are shown in the official language in which they were submitted.
CA 02832931 2013-11-13
INTEGRATED PROCESSES FOR RECOVERY OF
HYDROCARBON FROM OIL SANDS
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application is a division of application number 2,797,513,
filed in Canada
on November 21, 2012 which is a divisional of application number 2,740,481,
filed in Canada
on May 17, 2011.
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-
1
CA 02832931 2013-11-13
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 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
2
CA 02832931 2013-11-13
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.
[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
3
CA 02832931 2013-11-13
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 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.
4
CA 02832931 2013-11-13
[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.
[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.
CA 02832931 2013-11-13
[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 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
6
CA 02832931 2013-11-13
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 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.
7
CA 02832931 2013-11-13
[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
8
CA 02832931 2013-11-13
describes a process of bitumen recovery from oil sands using a mixture of
light naphtha and
methanol.
[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.
9
CA 02832931 2013-11-13
[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. 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.
CA 02832931 2013-11-13
[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 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
11
CA 02832931 2013-11-13
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 vit% 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.
[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,
12
CA 02832931 2013-11-13
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 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
13
CA 02832931 2013-11-13
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 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.
14
CA 02832931 2013-11-13
[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.
CA 02832931 2013-11-13
[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 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
16
CA 02832931 2013-11-13
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.
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.
17
CA 02832931 2013-11-13
[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.
[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.
18
CA 02832931 2013-11-13
[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 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
19
CA 02832931 2013-11-13
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 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
CA 02832931 2013-11-13
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
[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
21
CA 02832931 2013-11-13
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
22
CA 02832931 2013-11-13
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.
[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
23
CA 02832931 2013-11-13
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.
[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%.
24
CA 02832931 2013-11-13
[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
[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
CA 02832931 2013-11-13
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
[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.
26
CA 02832931 2013-11-13
[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 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
27
CA 02832931 2013-11-13
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.
[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
28
CA 02832931 2013-11-13
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 underf low 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.
29
CA 02832931 2013-11-13
[00170] Recovery of bitumen may occur within a settling vessel, or within
flotation
cells.
[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.
CA 02832931 2013-11-13
[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 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
31
CA 02832931 2013-11-13
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 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.
32
CA 02832931 2013-11-13
[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 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.
33
CA 02832931 2013-11-13
[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 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.
34
=
CA 02832931 2013-11-13
[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 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
CA 02832931 2013-11-13
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
36
CA 02832931 2013-11-13
is a 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".
37
CA 02832931 2013-11-13
[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 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
38
CA 02832931 2013-11-13
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.
[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
39
CA 02832931 2013-11-13
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.
[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.
CA 02832931 2013-11-13
[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.
[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
41
CA 02832931 2013-11-13
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 th'e 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.
[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
42
CA 02832931 2013-11-13
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-C10 cyclic and/or open chain aliphatic solvents
would also be
appropriate. For example, it can be a mixture of C.4-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
43
CA 02832931 2013-11-13
to accomplish further washing and/or bitumen extraction, without effectively
deasphalting the
stream during the solvent-based extraction process.
[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
44
CA 02832931 2013-11-13
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.
[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
CA 02832931 2013-11-13
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 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.
46
CA 02832931 2013-11-13
[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 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
47
CA 02832931 2013-11-13
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 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
48
CA 02832931 2013-11-13
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 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
49
CA 02832931 2013-11-13
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 substantially dissolves asphaltenes. The first solvent may
also be a
CA 02832931 2013-11-13
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.
51
CA 02832931 2013-11-13
[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 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.
52
CA 02832931 2013-11-13
[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 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 (4220 may
also be added
to the secondary solid-liquid separator (432) if needed.
53
CA 02832931 2013-11-13
[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 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
54
CA 02832931 2013-11-13
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 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).
CA 02832931 2013-11-13
[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 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
56
CA 02832931 2013-11-13
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
57
CA 02832931 2013-11-13
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.
[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
58
CA 02832931 2013-11-13
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-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
59
CA 02832931 2013-11-13
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
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
CA 02832931 2013-11-13
(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.
[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
61
CA 02832931 2013-11-13
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 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
62
CA 02832931 2013-11-13
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
63
CA 02832931 2013-11-13
separation vessel may be referred to as "middlings". In the case of middlings
from a primary
separation vessel (PSV), the 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 MET 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.
64
CA 02832931 2013-11-13
[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 lbw, 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
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
CA 02832931 2013-11-13
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.
[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 agglonnerator 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
66
CA 02832931 2013-11-13
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.
[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
67
CA 02832931 2013-11-13
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.
[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-
68
CA 02832931 2013-11-13
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 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
69
CA 02832931 2013-11-13
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
CA 02832931 2013-11-13
stream may comprise low hydrocarbon-containing streams, such as a middling
stream (906),
tailings (908b), a fines-containing 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
71
CA 02832931 2013-11-13
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 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.
72
CA 02832931 2013-11-13
[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 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 5 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
73
CA 02832931 2013-11-13
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, 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
74
CA 02832931 2013-11-13
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 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
CA 02832931 2013-11-13
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.
[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
76
CA 02832931 2013-11-13
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
77
CA 02832931 2013-11-13
recycled extract liquor may be added to the effluent (1112) of the 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
78
CA 02832931 2013-11-13
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 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
79
CA 02832931 2013-11-13
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 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.
CA 02832931 2013-11-13
[00370] In an exemplary process, the PFT 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.
[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
81
CA 02832931 2013-11-13
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 (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.
82
CA 02832931 2013-11-13
[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 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
83
CA 02832931 2013-11-13
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.
84
CA 02832931 2013-11-13
[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.
CA 02832931 2013-11-13
[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 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 0612) 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
86
CA 02832931 2013-11-13
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).
[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
87
CA 02832931 2013-11-13
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 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
mm, or more preferably in the range of 500 to100 gm.
[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)
88
CA 02832931 2013-11-13
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 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,
89
CA 02832931 2013-11-13
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 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
CA 02832931 2013-11-13
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 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
91
CA 02832931 2013-11-13
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 pi.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
92
CA 02832931 2013-11-13
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.
[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
93
CA 02832931 2013-11-13
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.
[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.
[00416] 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,
94
CA 02832931 2013-11-13
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.
[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).
CA 02832931 2013-11-13
[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.
[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
96
CA 02832931 2013-11-13
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 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 vvt% 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
97
CA 02832931 2013-11-13
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 a solvent recovery unit (2014) to
ultimately produce
a fungible bitumen product (2024). The bitumen product (2026) derived from SRU
(2014) may
98
CA 02832931 2013-11-13
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 (5 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 (5
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
99
CA 02832931 2013-11-13
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.
[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,
100
CA 02832931 2013-11-13
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 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.
101
CA 02832931 2013-11-13
[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.
[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.
102
CA 02832931 2013-11-13
[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.
[00443] Dewatering of fine tailings derived from conventional water-based
extraction
processes may involve the use of expensive fiocculants 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,
103
CA 02832931 2013-11-13
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 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.
104
CA 02832931 2013-11-13
[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 separation stage and/or within the tailings solvent
recovery stage of a
105
CA 02832931 2013-11-13
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
106
CA 02832931 2013-11-13
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 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
agglomemtor (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.
107
CA 02832931 2015-06-04
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.
108
