Note: Descriptions are shown in the official language in which they were submitted.
CA 02933892 2016-06-23
,
,
PROCESSING OF OIL SAND STREAMS
VIA CHEMICALLY-INDUCED MICRO-AGGLOMERATION
BACKGROUND
Field of Disclosure
[0001] The disclosure relates generally to the field of oil
sand processing.
Description of Related Art
[0002] This section is intended to introduce various aspects of
the art, which may be
associated with the present disclosure. This discussion is believed to assist
in providing a
framework to facilitate a better understanding of particular aspects of the
present disclosure.
Accordingly, it should be understood that this section should be read in this
light, and not
necessarily as admissions of prior art.
[0003] Modern society is greatly dependent on the use of
hydrocarbon resources for
fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface
formations
that can be termed "reservoirs". Removing hydrocarbons from the reservoirs
depends on
numerous physical properties of the subsurface formations, such as the
permeability of the
rock containing the hydrocarbons, the ability of the hydrocarbons to flow
through the
subsurface formations, and the proportion of hydrocarbons present, among other
things.
Easily harvested sources of hydrocarbons are dwindling, leaving less
accessible sources to
satisfy future energy needs.
[0004] Recently, the harvesting of oil sand to remove heavy oil
has become more
economical. Hydrocarbon removal from oil sand may be performed by several
techniques.
For example, a well can be drilled to an oil sand reservoir and steam, hot
air, solvents, or a
combination thereof, can be injected to release the hydrocarbons. The released
hydrocarbons
may be collected by wells and brought to the surface. In another technique,
strip or surface
mining may be performed to access the oil sand, which can be treated with
water, steam or
solvents to extract the heavy oil.
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[0005] Oil sand extraction processes are used to liberate and separate
bitumen from oil
sand so that the bitumen can be further processed to produce synthetic crude
oil or mixed with
diluent to form "dilbit" and be transported to a refinery plant. Numerous oil
sand extraction
processes have been developed and commercialized, many of which involve the
use of water
as a processing medium. Where the oil sand is treated with water, the
technique may be
referred to as water-based extraction (WBE). WBE is a commonly used process to
extract
bitumen from mined oil sand. Other processes are non-aqueous solvent-based
processes. An
example of a solvent-based process is described in Canadian Patent Application
No.
2,724,806 (Adeyinka et al, published June 30, 2011 and entitled "Process and
Systems for
Solvent Extraction of Bitumen from Oil Sands"). Solvent may be used in both
aqueous and
non-aqueous processes.
[0006] One WBE process is the Clark hot water extraction process (the
"Clark
Process"). This process typically requires that mined oil sand be conditioned
for extraction by
being crushed to a desired lump size and then combined with hot water and
perhaps other
agents to form a conditioned slurry of water and crushed oil sand. In the
Clark Process, an
amount of sodium hydroxide (caustic) may be added to the slurry to increase
the slurry pH,
which enhances the liberation and separation of bitumen from the oil sand.
Other WBE
processes may use other temperatures and may include other conditioning
agents, which are
added to the oil sand slurry, or may operate without conditioning agents. This
slurry is first
processed in a Primary Separation Cell (PSC), also known as a Primary
Separation Vessel
(PSV), to extract the bitumen from the slurry.
[0007] In one bitumen extraction process, a water and oil sand slurry is
separated into
three major streams in the PSC: bitumen froth, middlings, and a PSC underflow.
As
discussed further below, the bitumen froth may undergo froth treatment with a
solvent.
[0008] From the PSC, the middlings, comprising bitumen and about 5-25 wt.
%
solids, based on the total wt. % of the middlings, is withdrawn and sent to
the flotation cells to
further recover bitumen. The middlings are processed by bubbling air through
the slurry and
creating a bitumen froth, which is recycled back to the PSC. Flotation
tailings (FT) from the
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flotation cells, comprising mostly solids and water, are sent for further
treatment or disposed
in an external tailings area (ETA).
[0009] In ETA tailings ponds, a liquid suspension of oil sand fines in
water with a
solids content greater than 2 wt. %, but less than the solids content
corresponding to the
Liquid Limit are called Fluid Fine Tailings (FFT). FFT settle over time to
produce Mature
Fine Tailings (MFT), having above about 30 wt. % solids.
[0010] Regardless of the type of WBE process employed, the process will
typically
result in the production of a bitumen froth that requires treatment with a
solvent. For example,
in the Clark Process, a bitumen froth comprises bitumen, solids, and water.
Certain processes
use naphtha to dilute bitumen froth before separating the product bitumen by
centrifugation.
These processes are called naphtha froth treatment (NFT) processes. Other
processes use a
paraffinic solvent, and are called paraffinic froth treatment (PFT) processes,
to produce
pipelineable bitumen with low levels of solids and water. In the PFT process,
a paraffinic
solvent (for example, a mixture of iso-pentane and n-pentane) is used to
dilute the froth before
separating the product, diluted bitumen, by gravity. A portion of the
asphaltenes in the
bitumen is also rejected by design in the PFT process and this rejection is
used to achieve
reduced solids and water levels. In both the NFT and the PFT processes, the
diluted tailings
(comprising water, solids and some hydrocarbon) are separated from the diluted
product
bitumen.
[0011] Solvent is typically recovered from the diluted product bitumen
component
before a resultant bitumen stream is delivered to a refining facility for
further processing.
[0012] The PFT process may comprise at least three units: Froth
Separation Unit
(FSU), Solvent Recovery Unit (SRU) and Tailings Solvent Recovery Unit (TSRU).
Mixing of
the solvent with the feed bitumen froth may be carried out counter-currently
in two stages in
separate froth separation units. The bitumen froth comprises bitumen, water,
and solids. A
typical composition of bitumen froth is about 60 wt. % bitumen, 30 wt. %
water, and 10 wt. %
solids. The paraffinic solvent is used to dilute the froth before separating
the product bitumen
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by gravity. The foregoing is only an example of a PFT process and the values
are provided by
way of example only. An example of a PFT process is described in Canadian
Patent No.
2,587,166 to Sury.
[0013] It would be desirable to have an alternative or improved method of
processing
an oil sand stream.
SUMMARY
[0014] It is an object of the present disclosure to provide a method of
processing an oil
sand stream.
[0015] Disclosed is a method comprising providing an oil sand stream
comprising
bitumen, solids, and water; conditioning the oil sand stream with an aluminate
to produce a
conditioned stream; treating the conditioned stream with a silicate to produce
a treated stream
comprising chemically-induced micro-agglomerates to assist bitumen extraction
or froth
cleaning; and processing the treated stream to form a bitumen stream and a
tailings stream.
[0016] The foregoing has broadly outlined the features of the present
disclosure so
that the detailed description that follows may be better understood.
Additional features will
also be described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] These and other features, aspects and advantages of the disclosure
will become
apparent from the following description, appending claims and the accompanying
drawings,
which are briefly described below.
[0018] Fig. 1 is a flow chart of a method of processing an oil sand
stream.
[0019] Fig. 2 is a flow diagram of a method of processing an oil sand
stream.
[0020] It should be noted that the figures are merely examples and no
limitations on
the scope of the present disclosure are intended thereby. Further, the figures
are generally not
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drawn to scale, but are drafted for purposes of convenience and clarity in
illustrating various
aspects of the disclosure.
DETAILED DESCRIPTION
[0021] For the purpose of promoting an understanding of the principles of
the
disclosure, reference will now be made to the features illustrated in the
drawings and specific
language will be used to describe the same. It will nevertheless be understood
that no
limitation of the scope of the disclosure is thereby intended. Any alterations
and further
modifications, and any further applications of the principles of the
disclosure as described
herein are contemplated as would normally occur to one skilled in the art to
which the
disclosure relates. It will be apparent to those skilled in the relevant art
that some features that
are not relevant to the present disclosure may not be shown in the drawings
for the sake of
clarity.
[0022] At the outset, for ease of reference, certain terms used in this
application and
their meaning as used in this context are set forth below. To the extent a
term used herein is
not defined below, it should be given the broadest definition persons in the
pertinent art have
given that term as reflected in at least one printed publication or issued
patent. Further, the
present processes are not limited by the usage of the terms shown below, as
all equivalents,
synonyms, new developments and terms or processes that serve the same or a
similar purpose
are considered to be within the scope of the present disclosure.
[0023] Throughout this disclosure, where a range is used, any number
between or
inclusive of the range is implied.
[0024] A "hydrocarbon" is an organic compound that primarily includes the
elements
of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any
number of other
elements may be present in small amounts. Hydrocarbons generally refer to
components
found in heavy oil or in oil sand. However, the techniques described are not
limited to heavy
oils but may also be used with any number of other reservoirs to improve
gravity drainage of
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liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be
straight chained,
branched, or partially or fully cyclic.
[0025] "Bitumen" is a naturally occurring heavy oil material. Generally,
it is the
hydrocarbon component found in oil sand. Bitumen can vary in composition
depending upon
the degree of loss of more volatile components. It can vary from a very
viscous, tar-like,
semi-solid material to solid forms. The hydrocarbon types found in bitumen can
include
aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be
composed of:
19 weight (wt.) % aliphaties (which can range from 5 wt. % - 30 wt. %, or
higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % -50 wt. %, or higher); and
some amount of sulfur (which can range in excess of 7 wt. %), the weight %
based
upon total weight of the bitumen.
In addition, bitumen can contain some water and nitrogen compounds ranging
from less than
0.4 wt. % to in excess of 0.7 wt. %. The percentage of the hydrocarbon found
in bitumen can
vary. The term "heavy oil" includes bitumen as well as lighter materials that
may be found in
a sand or carbonate reservoir.
[0026] "Heavy oil" includes oils which are classified by the American
Petroleum
Institute ("API"), as heavy oils, extra heavy oils, or bitumens. The term
"heavy oil" includes
bitumen. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or
more, 10,000 cP or
more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has
an API gravity
between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920
grams per
centimeter cubed (g/cm3)) and 10.00 API (density of 1,000 kg/m3 or 1 g/cm3).
An extra heavy
oil, in general, has an API gravity of less than 10.0 API (density greater
than 1,000 kg/m3 or
1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous
sand, which is a
combination of clay, sand, water and bitumen. The recovery of heavy oils is
based on the
viscosity decrease of fluids with increasing temperature or solvent
concentration. Once the
viscosity is reduced, the mobilization of fluid by steam, hot water flooding,
or gravity is
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possible. The reduced viscosity makes the drainage or dissolution quicker and
therefore
directly contributes to the recovery rate.
[0027] "Fine particles" or "fines" are generally defined as those solids
having a size
of less than 44 microns (km), as determined by laser diffraction particle size
measurement.
[0028] "Coarse particles" are generally defined as those solids having a
size of greater
than 44 microns (lam), as determined by laser diffraction particle size
measurement.
[0029] The term "solvent" as used in the present disclosure should be
understood to
mean either a single solvent, or a combination of solvents.
[0030] The terms "approximately," "about," "substantially," and similar
terms are
intended to have a broad meaning in harmony with the common and accepted usage
by those
of ordinary skill in the art to which the subject matter of this disclosure
pertains. It should be
understood by those of skill in the art who review this disclosure that these
terms are intended
to allow a description of certain features described and claimed without
restricting the scope
of these features to the precise numeral ranges provided. Accordingly, these
terms should be
interpreted as indicating that insubstantial or inconsequential modifications
or alterations of
the subject matter described and are considered to be within the scope of the
disclosure.
[0031] The articles "the", "a" and "an" are not necessarily limited to
mean only one,
but rather are inclusive and open ended so as to include, optionally, multiple
such elements.
[0032] The term "paraffinic solvent" as used herein means solvents
comprising
normal paraffins, isoparaffins or blends thereof in amounts greater than 50
wt. %. Presence of
other components such as olefins, aromatics or naphthenes may counteract the
function of the
paraffinic solvent and hence may be present in an amount of only 1 to 20 wt. %
combined, for
instance no more than 3 wt. %. The paraffinic solvent may be a C4 to C20 or C4
to C6
paraffinic hydrocarbon solvent or a combination of iso and normal components
thereof The
paraffinic solvent may comprise pentane, iso-pentane, or a combination thereof
The
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paraffinic solvent may comprise about 60 wt. % pentane and about 40 wt. % iso-
pentane, with
none or less than 20 wt. % of the counteracting components referred above.
[0033] The ease of separation of bitumen from solids is a function of
bitumen and
fines content. Generally, the higher the bitumen content and the lower the
fines content, the
easier it is to extract bitumen from the oil sand. Oil sand that is high in
bitumen content and
low in fines content are termed "good processing ores". High fines, low
bitumen ores
typically yield low bitumen recoveries by conventional methods and are termed
"poor
processing ores". The low bitumen recovery may at least partially be
attributed to slimes
coating the bitumen surfaces which inhibit bitumen-air attachment.
Conventionally, caustic
plays a role in the dispersion of fines from bitumen, thereby improving
bitumen recovery and
froth quality by promoting the release of natural surfactants from bitumen to
the aqueous
phase, precipitating divalent cations such as calcium and magnesium, and
modifying the
electrical surface potential of bitumen and solids, rendering the solids more
hydrophilic.
Despite the benefits of caustic, extraction of poor processing ores can be a
challenge due to
reduction in the bitumen-air attachment as a result of the surface of bitumen
and air bubbles
being covered by clay fines. Generally, the higher the fines content, the
higher the caustic
dosage required to disperse the fines. Because higher caustic addition may
hinder settling of
fines and tailings treatment and may also complicate froth treatment by
emulsifying bitumen,
reducing caustic addition may be desirable.
[0034] The present disclosure provides a method of processing an oil sand
stream.
The present disclosure provides a method in which chemically-induced micro-
agglomerates
(CIMA) are formed in an oil sand stream. With reference to Figure 1, the
method may
comprise providing (102) an oil sand stream comprising bitumen, solids, and
water;
conditioning (104) the oil sand stream with an aluminate to produce a
conditioned stream;
treating (106) the conditioned stream with a silicate to produce a treated
stream comprising
chemically-induced micro-agglomerates to assist bitumen extraction or froth
cleaning; and
processing (108) the treated stream to form a bitumen stream and a tailings
stream.
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[0035] Without being bound by theory or promise, by adding aluminate and
silicate to
the oil sand stream, the CIMA may be more easily agglomerated or flocculated,
for instance
using an agglomerating or flocculating polymer. With improved agglomeration,
bitumen
recovery may be improved by reducing slime coating while improving fines
settling velocity.
The use of caustic alone may fail to provide acceptable bitumen recovery
and/or froth quality
for high fines ores.
[0036] The following potential benefits may be realized by methods
described herein.
[0037] The combined use of aluminate and silicate may yield micro-
agglomerates of
fines which scavenge fine silica and clays from bitumen surfaces, thereby
reducing slime
coating while increasing bitumen liberation and recovery.
[0038] The agglomerates may have higher settling velocities compared to
dispersed
fines, and flocculation of the micro-agglomerates may further increase fines
separation.
[0039] The addition of an aluminate and caustic may have a synergistic
effect,
improving bitumen recovery and froth quality in poor processing ores and good
ores due to
increased fines dispersion by the caustic followed by charge neutralization by
the reaction of
the trivalent ions and the negatively charged fines.
[0040] The tailings generated from the flocculation of CIMA may have
better settling,
dewatering, and may tend to form higher strength deposits.
[0041] The "oil sand stream" is any suitable stream stemming from oil
sand and
comprising bitumen, solids, and water. For instance, the oil sand stream may
be crushed oil
sand with added water and/or one or more conditioning agents. As discussed
herein, a water
based extraction (WBE) followed by paraffinic froth treatment (PFT) may
comprise
conditioning, primary separation, and froth treatment in that order; the "oil
sand stream" may
be the bitumen-rich stream during these steps, prior to solvent addition in
the froth treatment.
The "oil sand stream" may be, for instance, within a hydrotransport pipeline
(or mixing
vessel), between a hydrotransport pipeline (or mixing vessel) and a primary
separation
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process, within the primary separation process, or a bitumen froth between a
primary
separation process and froth treatment. However, the "oil sand stream" is not
a tailings
stream. The oil sand stream may comprise at least 5 weight % bitumen, based on
a total
weight of the oil sand stream.
[0042] Figure 2 illustrates a method for processing an oil sand stream to
yield a
bitumen stream and a tailings stream. Hot water (202) and conditioning agents
(204) are
added to mined crushed oil sand (206) to form an oil sand stream (208). The
oil sand stream
(208) is flowed in a hydrotransport pipeline (210) to a primary separation
cell (PSC) (212).
The PSC (212) produces bitumen froth (214), middlings (216), and a PSC
underflow (218)
also known as coarse tailings. The bitumen froth (214) is treated in froth
treatment. A known
paraffinic froth treatment (PFT) is illustrated in Figure 2. As illustrated in
Figure 2, froth
treatment may include adding the bitumen froth (214) into a first froth
settling unit (FSU-1)
(217). FSU-1 overflow is a diluted bitumen product (219) from which solvent
(220) is
removed in a solvent recovery unit (SRU) (222) yielding a bitumen stream
(224). FSU-1
underflow (226) is sent to a second FSU (FSU-2) (228) with a paraffinic
solvent (230).
FSU-2 overflow (231) is passed upstream to FSU-1 (217) with the bitumen froth
(214).
FSU-2 underflow (232) is passed to a tailings solvent recovery unit (TSRU)
(234) to remove
solvent (236) yielding a tailings stream (238).
[0043] The aluminate and silicate addition are illustrated in Figure 2 in
three locations
by way of example, namely within the hydrotransport pipeline (210) (aluminate
addition
(240) and silicate addition (241)), within the primary separation (aluminate
addition (242) and
silicate addition (243)), and to the bitumen froth (214) (aluminate addition
(244) and silicate
addition (245)) between the primary separation process and froth treatment.
The number of
aluminate and silicate addition points may be one or more than one. The
aluminate may be
added before, or concurrently, with the silicate. Some silicate may also be
added before the
aluminate to disperse ultrafines from the bitumen.
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[0044] The aluminate and/or silicate may be added at the site of, in
addition to or
instead of, caustic addition, which may be added along with the water in the
ore preparation
as the oil sand stream enters hydrotransport.
[0045] The chemically-induced micro-agglomerates are predominately much
less than
1 mm in diameter, with the weight majority between 2 and 100 microns, and they
principally
comprise fine particles of the oil sand.
[0046] The oil sand stream may be of poor quality, such as one having a
fines content
above 8 weight % or a bitumen content below 15 weight %, both based on a
weight of the oil
sand stream.
[0047] The aluminate used for conditioning the oil sand stream to produce
a
conditioned stream may comprise sodium aluminate or a similar species
including, but not
limited to, potassium aluminate, aluminum sulfate, aluminum oxide, aluminum
chloride,
polyaluminum chloride, polyaluminum sulfate, or a mixture thereof. In alkaline
environments
(e.g. oil sand streams), fine particles and clays carry a negative charge
characterized by a
negative zeta potential. Aluminate complexes can neutralize the negative
charge and form a
layer of coating around the fine particles and clays. When this occurs,
natural coagulation
begins due to van der Waals interactions. 1 to 500 ppmw of elemental Al in the
form of
aluminate may be added to the oil sand stream.
[0048] The silicate used for treating the conditioned stream to produce a
treated
stream comprising chemically-induced micro-agglomerates may be a polysilicate.
The
polysilicate may be sodium silicate, potassium silicate, or a mixture thereof.
The silicate may
comprise colloidal silica. The colloidal silica may comprise cationic silica,
anionic silica,
modified colloidal silica, ammonium silica, low sodium silicate, or a mixture
thereof The
colloidal silica may be 7 to 50 nm, with a surface area between 60 and 400
m2/g Si02. The
colloidal silica may be 7 nm with a surface area between 320 and 400 m2/g
Si02, 12 nm with
a surface area of between 198 and 258 m2/g Si02, 22 nm with a surface area
between 110 and
150 m2/g Si02, 50 nm with a surface area between 60 and 90 m2/g Si02, or a
combination
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thereof. In the treating stage, a series of polycondensation reactions begin
to occur as soluble
silica reacts instantaneously or quickly with aluminate complexes to form a
stable, chemical
bond. The net effect of this in situ bonding is the rearrangement of the fine
particles and clays
into a chemically-induced micro-agglomerate (CIMA). 1 to 500 ppmw of elemental
Si in the
form of silicate may be added to the conditioned stream.
[0049] The aluminate may comprise sodium aluminate and the silicate may
comprise
colloidal silica.
[0050] An organic agglomerating polymer may be added to the treated steam
to assist
in agglomerating solids by forming macro-agglomerates. In Figure 2, the
agglomerating
polymer is shown by three addition streams (250, 251, and 252). The "macro-
agglomerates"
are generally greater than 500 microns, up to millimeters in size. These
"macro-agglomerates"
comprise both the fine particles and sand grains of the oil sand. The organic
agglomerating
polymer may comprise a flocculating polymer. The flocculating polymer may
comprise a
synthetic polymer. The synthetic polymer may be polyacrylamide (PAM) or
polyethylene
oxide. The flocculating polymer may comprise a natural polymer. The natural
polymer may
be starch. The organic agglomerating polymer may be a cationic, anionic,
nonionic or
amphoteric polyacrylamide, a copolymer of acrylamide and diallyl dimethyl
ammonium
chloride, a copolymer of acrylamide and diallylaminoalkyl (meth) acrylates, a
copolymer of
acrylamide and dialkyldiaminoalkyl (meth) acrylamide, or a mixture thereof. 1
to 500 ppmw
of flocculating polymer may be added to the treated stream.
[0051] Caustic soda or sodium citrate may be added to the oil sand stream
prior to the
conditioning with the aluminate for increasing the oil sand stream's pH level
and dispersing
fines from bitumen.
[0052] A pH modifier may be added to the oil sand stream to assist
agglomeration.
The pH modifier may be an organic or inorganic acid, or carbon dioxide.
[0053] The treated stream may be mixed by hydrotransport in a pipeline or
turbulence
in a primary separation cell (PSC) feedwell.
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[0054] The step of processing the treated stream to form a bitumen stream
and a
tailings stream may comprise recycling at least one oil sand bitumen
containing tailings
stream back into the oil sand steam prior to the aluminate addition to assist
bitumen recovery
or fines treatment.
[0055] The aluminate and silicate may be added upstream of bitumen froth
treatment.
[0056] The aluminate and silicate may be added into a primary separation
cell (PSC)
for separating the oil sand stream. Bitumen froth from the PSC may be treated
to produce the
bitumen product, for instance using paraffinic froth treatment (PFT).
[0057] The aluminate and silicate may be added during hydrotransport of
the oil sand
stream.
[0058] Following hydrotransport, the treated stream may be introduced
into a primary
separation cell (PSC) for separating the treated stream. The bitumen froth
from the PSC may
be treated to produce the bitumen stream, for instance using paraffinic froth
treatment (PFT).
[0059] It should be understood that numerous changes, modifications, and
alternatives
to the preceding disclosure can be made without departing from the scope of
the disclosure.
The preceding description, therefore, is not meant to limit the scope of the
disclosure. Rather,
the scope of the disclosure is to be determined only by the appended claims
and their
equivalents. It is also contemplated that structures and features in the
present examples can be
altered, rearranged, substituted, deleted, duplicated, combined, or added to
each other.
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