Note: Descriptions are shown in the official language in which they were submitted.
CA 02768522 2012-02-17
PROCESSES FOR TREATING TAILINGS STREAMS FROM OIL SANDS ORE
FIELD OF THE ART
The present disclosure relates to processes for the treatment of tailings
streams
from oil sands ore wherein carboxylic acid salts are used as process aids.
BACKGROUND
Bituminous sands, or oil sands, are a type of unconventional petroleum
deposit.
The sands contain naturally occurring mixtures of sand, clay, water, and a
dense and
extremely viscous form of petroleum technically referred to as bitumen (or
colloquially
"tar" due to its similar appearance, odor, and color). Oil sands are found in
large amounts
in many countries throughout the world, but are found in extremely large
quantities in
Canada and Venezuela. Oil sand deposits in northern Alberta in Canada
(Athabasca oil
sands) contain approximately 1.6 trillion barrels of bitumen, and production
from oil sands
mining operations is expected to reach 1.5 million barrels of bitumen per day
by 2020.
Oil sands reserves have only recently been considered to be part of the
world's oil
reserves, as higher oil prices and new technology enable them to be profitably
extracted
and upgraded to usable products. They are often referred to as unconventional
oil or crude
bitumen, in order to distinguish the bitumen extracted from oil sands from the
free-flowing
hydrocarbon mixtures known as crude oil traditionally produced from oil wells.
Conventional crude oil is normally extracted from the ground by drilling oil
wells
into a petroleum reservoir, and allowing oil to flow into them under natural
reservoir
pressure, although artificial lift and techniques such as water flooding and
gas injection are
usually required to maintain production as reservoir pressure drops toward the
end of a
field's life. Because extra-heavy oil and bitumen flow very slowly, if at all,
toward
producing wells under normal reservoir conditions, the sands may be extracted
by either
strip mining or the oil made to flow into wells by in situ techniques which
reduce the
viscosity such as by injecting steam, solvents, and/or hot air into the sands.
These
processes can use more water and require larger amounts of energy than
conventional oil
extraction, although many conventional oil fields also require large amounts
of water and
energy to achieve good rates of production.
The original process for extraction of bitumen from the sands was developed by
Dr.
Karl Clark, working with the Alberta Research Council in the 1920s. Today, the
producers
doing surface mining use a variation of the Clark Hot Water Extraction (CHWE)
process.
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CA 02768522 2012-02-17
In this process, the ores are mined using open-pit mining technology. The
mined ore is
then crushed for size reduction in relatively large tumblers or conditioning
drums. Hot
water at 40-80 C is added to the ore and the formed slurry is conditioned and
transported,
for example using a piping system called hydrotransport line, to the
extraction units, for
example to a primary separation vessel (PSV) where bitumen may be recovered by
flotation as bitumen froth. The hydrotransport line may be configured to
condition the oil
sand while moving it to the extraction. The water used for hydrotransport is
generally
cooler (but still heated) than in the tumblers or conditioning drums.
The displacement and liberation of bitumen from the sands is achieved by
wetting
the surface of the sand grains with an aqueous solution containing a caustic
wetting agent,
such as sodium hydroxide. The resulting strong surface hydration forces
operative at the
surface of the sand particles give rise to the displacement of the bitumen by
the aqueous
phase. For example, sodium hydroxide is added to maintain the pH balance of
the slurry
basic, in the range of 8.0 to 10. This has the effect of dispersing fines and
clays from the oil
sands and reducing the viscosity of the slurry, thereby reducing the particle
size of the
minerals in the oil sands.
Once the bitumen has been displaced and the sand grains are free, the phases
can be
separated by froth flotation based on the natural hydrophobicity exhibited by
the free
bituminous droplets at moderate alkaline pH values (Hot water extraction of
bitumen from
Utah tar sands, Sepulveda et al. S. B. Radding, ed., Symposium on Oil Shale,
Tar Sand,
and Related Material - Production and Utilization of Synfuels: Preprints of
Papers
Presented at San Francisco, California, August 29 - September 3, 1976; vol.
21, no. 6, pp.
110-122 (1976)).
The recovered bitumen froth generally consists of 60% bitumen, 30% water and
10% solids (sand and clay fines) by weight. The recovered bitumen froth may be
cleaned
to reject the contained solids and water to meet the requirement of downstream
upgrading
processes. Depending on the bitumen content in the ore, between 70 and 100% of
the
bitumen can be recovered using modern hot water extraction techniques from
high grade
ores. Generally, the larger sand particles and rock settle to the bottom where
it is then
pumped into settling basins commonly referred to as a tailings pond. The
intermediate
portion is often referred to as the middlings, which is relatively viscous and
typically
contains dispersed clay particles and some trapped bitumen which is not able
to rise due to
the viscosity. The middlings are then exposed to froth flotation techniques to
recover
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CA 02768522 2012-02-17
additional bitumen that did not float to the top during gravity separation,
after which it is
passed to the tailings pond.
Low grade ores are the highest in fines content and the most difficult to
recover
bitumen from. A major portion of the fines (known as the main problem with
tailings)
come from the lowest grade fraction of the feed stream. Over the next 5 to 10
years, oil
sands industry will be challenged to produce more oil from lower grade ores by
implementing methods that are more cost effective and use less water and
energy.
Hydrophilic and biwettable ultrafine solids, mainly clays and other charged
silicates and metal oxides, tend to form stable colloids in water and exhibit
a very slow
settling and dewatering behavior, resulting in tailing ponds that take several
years to
manage. The slow settling of fine (<45 m) and ultrafine clays (<1 m) and the
large
demand of water during oil sand extraction process have promoted research and
development of new technologies during the last 20 years to modify the water
release and
to improve settling characteristics of tailings. Currently, two technologies
used in the oil
sands industry are the consolidated tailings (CT) process and the paste
technology.
Gypsum is used in the CT technology as a coagulant, while polyelectrolytes,
generally
polyacrylamides of high charge density, are used as flocculants in the paste
technology.
Flocculation process is of considerable importance and various inorganic
and/or organic
flocculants are being used to overcome the above problem. The adequate dosage
of
gypsum and/or flocculants during the tailings disposition improves the oil
sands process
efficiency because these substances act as modifiers of the interaction forces
responsible
for holding particles together. Consequently, the addition of these chemicals
can enhance
the settling rate of tailings and promote the recovery of water and its
recirculation in the oil
sands process. Recently some silicates and silica microgel have been proposed
for treating
tailings and separation of ultrafine solids.
US 5804077 discloses a method for treating whole aqueous tailings produced by
a
water-based extraction process to recover bitumen from oil sand, said tailing
containing
suspended coarse sand and clay fines, comprising desanding the whole tailings
by settling
out substantially all of the sand to yield desanded tailings; adding about 100
to 200 ppm of
calcium sulfate to the desanded tailings; settling the mixture to produce
clarified water and
sludge; and recycling the clarified water to the plant as process water.
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SUMMARY
Processes are provided for treating oil sands ore tailings streams comprising:
(i)
adding at least one carboxylate salt to an aqueous slurry of oil sands ore
and/or an oil sands
ore tailings stream to form a flocculated oil sands ore tailings stream; and
(ii) separating
the flocculated solids from the tailings stream. Processes are also provided
for extracting
bitumen from an oil sand ore, comprising: (i) mixing oil sands ore with water
or an
aqueous solution to form a slurry; (ii) aerating or conditioning the slurry to
form a froth
containing bitumen within the slurry; (iii) separating the froth from the
slurry; (iv) adding
at least one carboxylate salt to the slurry prior to or during one or more of
the preceding
steps; and (v) liberating bitumen from the froth.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a photograph of the settled tailings after 24 hr from flotation of
ore LG1.
Figure 2 is a photograph of the settled tailings after 24 hr from flotation of
ore after
treatment with various concentrations of sodium formate.
Figure 3 shows a graph of the tailings settling vs. time for experiments with
and
without sodium formate.
DETAILED DESCRIPTION
Processes for treating oil sands ore tailings streams which utilize
biodegradable
carboxylate salts as process aids, in particular for low grade ores, are
provided. The
processes may be used as part of a water-based extraction process for bitumen
recovery to
reduce the use of sodium hydroxide. The processes may also be used to enhance
settling of
flocculated solids, especially ultrafine solids, in oils sands ore tailing
streams. The
processes may be readily incorporated into current processing facilities and
may provide
economic and environmental benefits.
Tailings Streams
The expressions "tailings", "tailings stream", "process oil sand tailings", or
"in-
process tailings" as used herein refer to tailings that are directly generated
as bitumen is
extracted from oil sands. Generally, tailings are the discarded materials
generated in the
course of extracting the valuable material from ore. In tar sand processing,
tailings
comprise the whole tar sand ore and any net additions of process water thus
missing the
recovered bitumen. Any tailings fraction obtained from the process, such as
tailings from
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primary separation cell, primary flotation and secondary flotation, process
tailings and
mature fine tailings or combination thereof. The tailings may comprise
colloidal sludge
suspension containing clay minerals and/or metal oxides/hydroxides.
Oil sands process tailings contain a majority of coarse particles having
diameters
between 44 and 1000 m and above, and fine and ultrafine solids. Fines are
essentially
comprised of silicates and clays with average diameter <44 m that can be
easily
suspended in the water. Ultrafine solids (<1 m) may also be present in the
tailings stream
and primarily composed of clays. The tailings can be one or more of any of the
tailings
streams produced in a process to extract bitumen from an oil sands ore. The
tailings are
one or more of the coarse tailings, fine tailings, and froth treatment
tailings. In exemplary
embodiments, the tailings may comprise paraffinic or naphthenic tailings, for
example
paraffinic froth tailings. The tailings may be combined into a single tailings
stream for
dewatering or each tailings stream may be dewatered individually. Depending on
the
composition of the tailings stream, the additives may change, concentrations
of additives
may change, and the sequence of adding the additives may change. Such changes
may be
determined from experience with different tailings streams compositions.
In one embodiment, the tailings stream is produced from an oil sands ore and
comprises water, sand and fines. In one embodiment, the tailings stream
comprises at least
one of the coarse tailings, fine tailings, ultrafine tailings or froth
treatment tailings. In
particular, the processes may be used advantageously for treating ultrafine
solids. In one
embodiment, the tailings stream comprises a fine (particle size <44 m)
content of about
10 to about 70 wt% of the dry tailings. In one embodiment, the tailings stream
contains
about 0.01 to about 5 wt% of bitumen. In an exemplary embodiment, the oil
sands ore
tailings stream comprises process tailings. In an exemplary embodiment, the
oil sands ore
tailings stream comprises sand, fines and water.
Carboxylate Salts
In exemplary embodiments, at least one carboxylate salt is used in any of the
processes described herein. Exemplary carboxylate salts include, but are not
limited to, C1-
C7 alkyl carboxylate salts, for example formate salts or acetate salts, or
mixture thereof. In
certain embodiments, the at least one carboxylate salt is selected from the
group consisting
of C1-C2 alkyl carboxylate salts and mixtures thereof. In one embodiment, the
at least one
carboxylate salt comprises a monocarboxylate salt. The cation is not intended
to be limited
and can be, for example, sodium, potassium, cesium, ammonium, and the like.
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CA 02768522 2012-02-17
In exemplary embodiments, the at least one carboxylate salt is selected from
the
group consisting of: sodium formate, potassium formate, sodium acetate,
potassium acetate
and mixtures thereof. In a particular embodiment, the at least one carboxylate
salt
comprises sodium formate. In another particular embodiment, at least one
carboxylate salt
comprises sodium acetate.
In the exemplary embodiments, the carboxylate salts may be used in the
processes
described herein a dry powder or as a suspension in water.
Processes for Bitumen Recovery or Treating Oil Sands Ore Tailings Streams
In exemplary embodiments, the process for treating oil sands ore tailings
streams
comprises: (i) adding at least one carboxylate salt to an aqueous slurry of
oil sands ore
and/or an oil sands ore tailings stream to form a flocculated oil sands ore
tailings stream;
and (ii) separating the flocculated solids from the tailings stream. The
addition of the at
least one carboxylate salt may be used, for example, to enhance the settling
of the
flocculated solids, to accelerate the consolidation and/or sedimentation of
fines or the
flocculated solids in the tailings streams.
According to the embodiments, the separation step may be accomplished by any
means known to those skilled in the art, including but not limited to
centrifuges,
hydrocyclones, decantation, filtration, thickeners, or another mechanical
separation
method.
In exemplary embodiments, the process may provide enhanced flocculation of
solid
materials in the tailings, better separation of the solids from water, an
increased rate of
separation of the solids from the water, and/or may expand the range of
operating
conditions which can be tolerated while still achieving the desired level of
separation of
solids from the water within a desired period of time.
The exemplary processes described herein may provide flocculated bed with
higher
densities, leading to compact beds that can dewater faster and build yield
strength faster
than comparable treatments without carboxylate salts. In an exemplary
embodiment, the
processes accelerate dewatering of tailings.
In certain embodiments, the processes may achieve a clarified water phase with
less
than 0.5% solids within 8 hours. In exemplary embodiments, the processes may
achieve a
clarified water phase with less than 0.01% solids within 24 hours.
In certain embodiments, the at least one carboxylate salt is present in an
amount of
about 0.01 to about 10 weight percent, or about 0.05 to about 5 weight
percent, by weight
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CA 02768522 2012-02-17
of the oil sands ore or dry tailings. In one embodiment, the carboxylate salt
is in an amount
about 0.05, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 1,
about 2, about 3,
about 4, about 5, about 6, about 7, about 8, about 9, or about 10 weight
percent by weight
of the oil sands ore or dry tailings. In one embodiment, the at least one
carboxylate salt is
in an aqueous solution.
In one embodiment, the dosage of the at least one carboxylate salt added to
the oil
sands ore-water slurry or process streams derived therefrom is in the range of
about 100 to
about 100,000 grams carboxylate salt per dry ton (g/t) of ore (e.g., for the
slurry) or of dry
suspended solids (e.g., for other process streams) or of dry tailings. In some
embodiments,
the dosage of the carboxylate salt is from about 500 to about 50000 g/t, about
1000 to
about 50000 g/t, about 1000 to about 5000 g/t, about 5000 to about 25000 g/t,
about 10000
to about 20000 g/t,. In one embodiment, the dosage of the carboxylate salt is
about 5000
g/t, about 5500 g/t, about 6000 g/t, about 6500 g/t, about 7000 g/t, about
7500 g/t, about
8000 g/t, about 8500 g/t, about 9000 g/t, about 9500 g/t, about 10000 g/t,
about 10500 g/t,
about 11000 g/t, about 11500 g/t, about 12000 g/t, about 13000 g/t, about
14000 g/t, about
15000 g/t, about 16000 g/t, about 17000 g/t, about 18000 g/t, about 19000 g/t,
about 20000
g/t, about 25000 g/t, about 30000 g/t, about 35000 g/t, about 40000 g/t, about
45000 g/t, or
about 50,000 g/t.
In exemplary embodiments, the at least one carboxylate salt can be added prior
to
and/or during a bitumen extraction process. In one embodiment, the at least
one
carboxylate salt is contacted with the oil sands ore at a primary separation
step or in a
primary separation vessel.
In exemplary embodiments, the at least one carboxylate salt may be provided in
an
aqueous solution, such that the aqueous slurry of oil sands ore and/or the oil
sands ore
tailings stream are contacted with an aqueous solution comprising at least one
carboxylate
salt. In certain embodiments, the aqueous solution containing the at least one
carboxylate
salt can be added directly to the oil sands ore or to an aqueous slurry of oil
sands ore.
In another embodiment, the at least one carboxylate salt is added during the
conditioning step of a water-based extraction process of oils sands ore. By
way of
example, the at least one carboxylate salt may be added to an aqueous solution
with hot
water at a temperature within a range of about 40 C to about 90 C to condition
the oil sand
ore. As referred to herein, the water-based extraction process of oil sands
ore refers to any
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known extraction process producing aqueous tailings, such as the Hot Water
Process
(HWP).
In one embodiment, the oil sands ore may be low grade ore. In one embodiment,
the oil sands ore may be high grade ore.
In exemplary embodiments, the aqueous solution containing the carboxylate salt
may be mixed with the oil sands ore in the large tumblers or conditioning
drums or an
extraction pipeline without the addition of hot water. In a further
embodiment, wherein the
process further comprises conditioning steps, heating during the conditioning
steps is
optional. In certain embodiments, the conditioning steps of the process may
not require
heating, thereby providing significant energy savings. In still other
embodiments, the at
least one carboxylate salt may be contacted with the aqueous slurry of oil
sands ore and/or
an oil sands ore tailings stream at a temperature of between about 0 C to
about 60 C.
In one embodiment, the aqueous slurry of oil sands ore is contacted with the
at least
one carboxylate salt. In an exemplary embodiment, the aqueous slurry of oil
sands ore is
contacted with the at least one carboxylate salt in a primary separation
vessel. In another
exemplary embodiment, the aqueous slurry of oil sands ore is contacted with
the at least
one carboxylate salt in a secondary separation vessel. In another embodiment,
the aqueous
slurry of oil sands ore is an aqueous slurry of oil sands ore which has been
aerated to form
a froth. In an exemplary embodiment, the oil sands ore tailings stream is
contacted with the
at least one carboxylate salt.
In certain embodiments, the at least one carboxylate salt can be used to
replace
some or all of the sodium hydroxide or other process aid chemicals in a
process for
recovering bitumen from oil sands ore. In one embodiment, the process does not
comprise
the addition of any sodium hydroxide or other process aid chemicals other than
the at least
one carboxylate salt. In exemplary embodiments, the processes may comprise the
addition
of sodium hydroxide. In one embodiment, the sodium hydroxide is added to the
aqueous
slurry of oil sands ore and/or the oil sands ore tailings stream. The addition
of sodium
hydroxide may be used, for example, to maintain the pH of the aqueous slurry
of the oil
sands ore or the tailings stream in the range of about 8.5 to about 10. The pH
may be
adjusted prior to or after the addition of carboxylate salts(s). In a
particular embodiment,
sodium hydroxide is added to adjust the pH after the addition of the at least
one
carboxylate salt. In exemplary embodiments, the pH is adjusted to at least
about 8.5.
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In certain embodiments, the processes do not comprise the addition of sodium
hydroxide.
In exemplary embodiments, the processes produce a treated slurry, in the
presence
or absence of sodium hydroxide, which begin settling within 1 to 60 minutes
upon resting
to provide a substantially clear middling phase within 24 hours. In certain
embodiments,
the froth formed with the at least one carboxylate salt will settle faster
than with froth
treatment with sodium hydroxide to form a sediment layer and clear supernatant
water.
In exemplary embodiments, when the at least one carboxylate salt is added to
the
oil sand ore tailings stream, the carboxylate salt(s) may be added before or
after desanding.
Desanding is a process wherein the tailings are settled for a period of time
to form
desanded tailings as the supernatant. Desanding can be done also for example
by using a
hydrocyclone.
In exemplary embodiments, the processes may further comprise at least one
additive. Exemplary additives which may be used are any additives known to
those of skill
in the art, including for example a surfactant, an anti-foaming agent, a
polymer, a
flocculent, a mineral oil or a mixture thereof. In one embodiment, the
additives are in an
amount of 0.01 to 50 weight percent based on a total weight of dry ore or
tailings.
In another embodiment, a process for extracting bitumen from an oil sand ore
includes: (i) mixing oil sands ore with water or an aqueous solution to form a
slurry; (ii)
aerating or conditioning the slurry to form a froth containing bitumen within
the slurry;
(iii) separating the froth from the slurry; (iv) adding at least one
carboxylate salt to the
slurry prior to or during one or more of the preceding steps; and (v)
liberating bitumen
from the froth.
In another embodiment, a process for extracting bitumen from an oil sand ore
includes: (i) mixing oil sands ore with water or an aqueous solution to form a
slurry; (ii)
aerating or conditioning the slurry to form a froth containing bitumen within
the slurry;
(iii) separating the froth from the slurry; (iv) liberating bitumen from the
froth; (v)
subjecting the slurry to additional mixing, aerating and/or conditioning steps
to form a
froth containing remaining bitumen; (vi) separating the froth from the slurry;
(vii)
subjecting the slurry to a tailings treatment; and (viii) adding at least one
carboxylate salt
to the slurry prior to or during one or more of the preceding steps:
In exemplary embodiments, sodium hydroxide may also be added to the slurry. In
exemplary embodiment, the at least one carboxylate salt is added during the
tailings
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treatment. In exemplary embodiments, the slurry is contacted with the at least
one
carboxylate salt.
In exemplary embodiments of any of the processes described herein, the at
least
one carboxylate salt may be added in any mixing, conditioning, or separation
step in the
bitumen extraction process or treatment of oil sand ore tailings stream
process. In view of
the embodiments described herein, it will be understood that the at least one
carboxylate
salt could be added at other points in the bitumen recovery/extraction process
as necessary
or desired.
In one embodiment, the at least one carboxylate salt may be added to the oil
sand
ore-water slurry during any point before or during the mixing stage. In
exemplary
embodiments, mixing of the ore-water slurry may be achieved by any known
process or
apparatus. For example, after the oil sands ores have been mined and crushed,
the oil
sands ores may be transported by conveyor to a slurry preparation plant, where
hot water is
added to make the oil sand ore-water slurry.
In exemplary embodiments, the temperature of the water and/or the slurry may
be
any temperature as necessary or desired. In an exemplary embodiment, the
temperature of
the water and/or the slurry may be elevated to provide an effective amount of
heat to the
slurry to substantially release the bitumen from sand surface. In one
embodiment, the water
or aqueous solution used in the process may be between at a temperature of
about 0 C to
about 90 C; about 20 C to about 80 C; about 40 C to about 80 C; or about 40 C
to about
60 C. In. exemplary embodiments, depending, for example, on the temperature of
the
water, and/or the availability of thermal energy in the process, the
temperature of the slurry
may be elevated to and/or maintained at about 40 C to about 60 C. In the
exemplary
embodiments, the at least one carboxylate salt may be added before or during
any of the
mixing and conditioning stages described above, or their respective
equivalents.
In one embodiment, the at least one carboxylate salt may be added to the oil
sand
ore-water slurry during any point before or during a conditioning stage.
Conditioning of
the slurry, as described herein, may include further mixing or churning of the
slurry,
aeration of the slurry to form a froth, breaking of lumps in the slurry into
smaller lumps,
liberation of bitumen from sand grains, breaking of bitumen into smaller
droplets,
attaching liberated bitumen droplets to air bubbles, mixing the slurry with
optional
additives and other process aids, or the like. Generally, the effect of the
conditioning stage
is to enhance or maximize the liberation of bitumen from the sand grains and
separation of
CA 02768522 2012-02-17
bitumen or the froth containing bitumen from the slurry. Conditioning of the
slurry may be
achieved by any means known in the art and is not limited to the embodiments
described
herein.
In exemplary embodiments, after the slurry has been prepared and mixed, the
ore-
water slurry may be conditioned by any known process or apparatus. For
example, after
the slurry is formed, the slurry may be transported through a slurry
hydrotransport pipeline,
which may be used to condition the slurry. In the slurry hydrotransport
pipeline, the
hydrodynamic forces from speed of the slurry may liberate bitumen from the
sand grains,
break the liberated bitumen into smaller droplets, and promote attachment of
the liberated
bitumen droplets to entrained air bubbles. In exemplary embodiments, the size,
shape,
configuration, and length of the hydrotransport pipeline may be predetermined
to provide
any necessary or desired results. For example, the length of the
hydrotransport pipeline
may be determined, at least in part, on the processing plant location, the
slurry temperature,
the initial lump size, or other conditions that may affect the conditioning of
the slurry. In
some embodiments, the hydrotransport pipeline may be up to about 5 kilometers.
The
speed of the slurry through the hydrotransport pipeline may be predetermined
to provide
any necessary or desired result. For example, in an exemplary process, the
slurry is
transported through the pipeline at about 3 to about 5 meters per second. In
the exemplary
embodiments, the at least one carboxylate salt may be added before or during
any of the
mixing and conditioning stages described above, or their respective
equivalents.
Aerating the slurry (or a derivative of the slurry) may be achieved by any
means
known in the art. In exemplary embodiments, aerating the slurry promotes the
formation of
froth and may be achieved, for example by mixing or churning the slurry in a
mixing or
transport vessel or apparatus, such as the transport of the slurry in a slurry
hydrotransport
pipeline. In some embodiments, the slurry or a derivative thereof may be
aerated, for
example, by sparging the slurry or derivative thereof in a vessel or apparatus
(e.g., during
the secondary separation process, described below). In one embodiment, the at
least one
carboxylate salt may be added to the oil sand ore-water slurry (or any
derivative thereof)
before or during any extraction process. As used herein, an "extraction"
process may
include any process step or stage that furthers the liberation, separation, or
isolation of
bitumen from the other components of the oil-water slurry or its derivatives.
In one embodiment, the at least one carboxylate salt may be added to the oil
sand
ore-water slurry (or any derivative thereof) before or during a primary
separation process.
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As referred to herein, the "primary separation process" is the first
separation of bitumen
froth from solids after the oil sands ore-water slurry is formed and
conditioned. In
exemplary embodiments, primary separation of the bitumen froth from the solids
may be
accomplished by any known process or apparatus. For example, at the end of the
slurry
hydrotransport pipeline, the conditioned slurry may be discharged to one or
more large
stationary particle separation cells (PSC) or vessels. In the PSC, the aerated
bitumen may
float through the slurry upwards to the top of the cell where it may overflow,
and be
collected as primary bitumen froth. Within the PSC, the coarse solids may
settle, forming a
dense slurry at the bottom of the PSC which can be removed from the bottom of
the PSC
as "tailings" stream. Within the PSC, fine solids with some un-aerated
fugitive fine
bitumen droplets may remain suspended in the slurry. This low-density slurry
may be
removed from the middle of the separation cell as a "middlings" stream. In
various
embodiments, the at least one carboxylate salt may be added before or during
any of the
primary separation stages described herein, or their respective equivalents.
For example,
the at least one carboxylate salt may be added to the oil sand ore-water
slurry in the PSC.
In exemplary embodiments, one or more of the streams from the primary
separation
processes may optionally undergo further processing to further the bitumen
separation and
isolation from the other components of the streams. These processes are
referred to as
"secondary separation processes." In exemplary embodiments, the at least one
carboxylate
salt may be added to the slurry or any derivative thereof in a secondary
separation process.
For example, the middlings stream may be further processed using flotation
technology to
enhance bitumen-air attachment. An exemplary flotation technology may be, for
example,
mechanical flotation process or a flotation column in which air is added to
enhance
bitumen-air attachment. In this flotation process, middlings may be subjected
to vigorous
agitation and aeration, and the aerated fine bitumen droplets may be recovered
as
secondary bitumen froth. The secondary bitumen froth may be returned to the
PSC for
further cleaning or sent with the primary bitumen froth from PSC to a
subsequent bitumen
froth cleaning stage. In exemplary embodiments, the tailings stream from the
PSC may be
further processed, for example, in a tailings oil recovery (TOR) unit. The TOR
may
include a secondary separation cell or a flotation cells for further recovery
of bitumen from
the tailing stream. In the secondary separation processes, additional air or
water may be
added to the process streams to further enhance the separation or isolation of
bitumen. In
the embodiments, the at least one carboxylate salt may be added to the slurry
or process
12
CA 02768522 2012-02-17
streams thereof to further enhance the separation or isolation of bitumen from
these
streams, or to accelerate the consolidation and/or sedimentation of the
flocculated solids in
the oil sands ore tailings stream.
In exemplary embodiments, the streams from separation processes may optionally
undergo additional processing to further the bitumen separation and isolation.
For
example, the primary separation process and/or the secondary separation
process, or any of
the steps related thereto may be repeated in order to achieve the necessary or
desired result.
In the exemplary embodiments, the at least one carboxylate salt process aid
may be used in
these additional processing steps to further the bitumen separation and
isolation, or to
accelerate the consolidation and/or sedimentation of the flocculated solids in
the oil sands
ore tailings stream.
In exemplary embodiments, the at least one carboxylate salt may be added to
the oil
sands ore-water slurry, or any process streams derived therefrom, or the oil
sands ore
tailings stream, in any amount to provide a necessary or desired result. For
example, the
dosage of the at least one carboxylate salt may be added in an amount
effective to provide
the maximum yield of bitumen at that point in the process or to accelerate the
consolidation and/or sedimentation of the flocculated solids or fines in the
oil sands ore
tailings stream. In exemplary embodiments the at least one carboxylate salt
may be added
in a broad range of dosages without adversely impacting bitumen extraction or
release
water chemistry.
In one embodiment, after addition of the at least one carboxylate salt, the at
least
one carboxylate salt is permitted to remain in contact with the oil sands ore-
water slurry (or
process streams derived therefrom) for a predetermined amount of time prior to
separation
of the bitumen. In some embodiments, the at least one carboxylate salt remains
in contact
with the ore-water slurry or a process stream for about 10 minutes to about
180 minutes,
about 15 minutes to about 120 minutes, about 20 minutes to about 90 minutes,
or about 20
minutes to about 60 minutes prior to the separation of the bitumen. In
exemplary
embodiments, the at least one carboxylate salt remains in contact with the ore-
water slurry
or a process stream for an amount of time that is determined based on
necessary or desired
results.
In order that the disclosure may be more readily understood, reference is made
to
the following examples, which are intended to illustrate the invention, but
not limit the
scope thereof.
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EXAMPLES
Denver flotation cell and a laboratory scale hydrotransport loop were utilized
to
evaluate the effect of chemical dosage and operating parameters on the
processability of
low grade oil sands samples from Athabasca region. Process tailings were
examined for
properties such as suspended solids, settling rate and ease of tailing
treatments. The
following results demonstrate that carboxylic acid salts can be used as
process aids to
achieve an improvement in tailings settling and treatment.
Testing Methods
The experiments were conducted in a laboratory Denver flotation cell (Metso
Minerals, Danville, PA) under semi-batch conditions (batch water, continuous
air). In a
typical experiment, 300 g of oil sand ore was added to 1.5 1 pre-heated water
at 50 C at an
impeller speed of 1000 rpm in a 2 1 rectangular cell. The flotation cell was
kept at 50 C by
using a hot water circulating bath. The pH of water/slurry may be pre-adjusted
with
sodium hydroxide, carboxylate salt, or a combination therein prior to addition
of ore and
monitored during the flotation process. The slurry was pre-conditioned for 5
min before air
bubble flotation using an airflow rate of 200 ml/min. Then, froths were
collected at time
intervals of 2, 5, 10, 20, and 60 min after flotation while agitation was
paused for 30 sec.
Bitumen recovery rates, as well as solid and water contents were determined by
solvent
extraction on standard Soxhlet extractor units using toluene solvent.
Triplicate experiments
indicated recovery rates being reproducible within 5%. Compositions of oil
sands
samples used in this invention are given in Table 1.
Table 1: General composition of oil sand ores used in this study
Low Grade Oil Sands High Grade Oil Sand
No.I No.2 No.I
Bitumen % 9.28% 9.03% 12.46%
Water % 1.27% 4.10% 3.60%
Total Solids % 89.45% 86.87% 83.94%
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Example 1: Comparison of Bitumen Recovery for Low-Grade Oil Sand
Initial tests compared flotation of low-grade ore sample LG1 with water
adjusted to pH 8.5
with sodium hydroxide or adjusted to pH 8.5 with sodium hydroxide followed by
the
addition of either sodium formate (NaFm) or sodium acetate (NaAc) at a
concentration of
40,000 or 50,000 g/t, respectively. The bitumen recovery data is summarized in
Table 2
and the tailings settling results shown in Figure 1.
Table 2: Comparison of bitumen recovery data for oil sand LG1 treated with
NaOH and
NaOH + NaFm or NaAc.
Initial Bitumen Recovery
Treated with Final pH
PH
NaOH 8.49 7.46 71.3
NaFm + NaOH 8.81 7.59 64.4
NaAc + NaOH 8.76 7.67 66.8
Example 2: Comparison of Bitumen Recovery for High-Grade Oil Sand
Table 3: Comparison of bitumen recovery data for oil sand HGI treated with and
without
NaFm or NaAc.
Initial Bitumen Recovery
Treated with Final pH
pH (0/0)
None 7.27 7.51 84.7%
NaFm 7.17 7.87 91.1%
NaAc 7.25 7.82 88.7%
The results in Table 1 demonstrate that the use of salt at doses of 40,000-
50,000 wt%
combined with NaOH result in similar bitumen recoveries to the use of NaOH
alone. The
initial pH of the experiments also displayed the ability of the salts to
increase the pH of the
slurry, which could help in lowering the amount of NaOH necessary to reach pH
8.5. At
the same time, the photographs in Figure 1 show that the clarity of the
supernatant was
vastly improved with the addition of the salts, due to the enhanced settling
of fine solids.
CA 02768522 2012-02-17
Example 3: Effect of Dosage of NaFm on Bitumen Recovery Rate for Low-Grade Oil
Sand
The dosage necessary to improve tailings settling was established by comparing
flotation
of low-grade ore sample LG2 with water adjusted to pH 8.5 with sodium
hydroxide or with
a concentration of sodium formate from 1000-10,000 g/t. The bitumen recovery
data can
be found in Table 3, while the 24 hr settling results are shown in Figure 2
and the settling
of the tailings over time shown in Figure 3.
Table 4: Comparison of bitumen recovery for LG2 as a function of NaFm
concentration
Bitumen
Amt. NaFm Initial Final Recovery
NaOH (g/t) pH pH %
Yes 0 8.51 7.56 56.6
No 1000 7.54 7.47 54.2
No 3000 7.69 7.48 59.3
No 5000 7.71 7.45 55.0
No 10,000 7.72 7.41 58.7
As shown in Figure 3, the use of sodium hydroxide results in tailings which do
not settle at
all within 24 hours, compared to 4000 or 5000 g/t NaFm which almost completely
settle
with supernatant clarity achieved.
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Example 4: Effect of Dosage of NaFm on Bitumen Recovery Rate for High-Grade
Oil
Sand
Table 5: Comparison of bitumen recovery for HG1 as a function of NaFm
concentration
Bitumen
Amt. NaFm Initial Recovery
NaOH (g/t) pH Final pH %
Yes 0 7.48 7.70 91.6%
No 5000 7.04 7.77 94.0%
No 10,000 7.14 7.86 87.2%
No 25,000 7.37 7.85 86.3%
No 50,000 7.17 7.87 91.1%
As the concentration of sodium formate was increased, the flocculated bed
height or mud
line became more visible and improved the clarity of the supernatant. The use
of NaFm at
doses as low as 5000 g/t produced a transparent supernatant. At the same time,
the bitumen
recovery for all NaFm experiments was found to be similar to the NaOH
experiment.
Therefore with ore sample LG2, a dosage of NaFm at or above 5000 g/t has the
ability to
provide similar bitumen recovery data as a NaOH experiment at pH 8.5, while
providing a
transparent supernatant.
17
