Note: Descriptions are shown in the official language in which they were submitted.
CA 02893552 2015-06-04
TREATING OIL SAND TAILINGS
BACKGROUND
Field of Disclosure
[0001] The disclosure relates generally to the field of treating oil sand
tailings.
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. As the costs of hydrocarbons increase, the less
accessible sources
become more economically attractive.
[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] Extracting bitumen from mined oil sand produces tailings
comprising solids,
water, and small amounts of unrecovered bitumen. It is desirable to increase
the solids content
of these tailings to assist reclamation.
[0006] Certain oil sand extraction processes are described below
to illustrate how
certain oil sand tailings may be formed. However, these descriptions are by no
means
exhaustive of the ways in which oil sand tailings may be generated.
[0007] 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.
[0008] 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 (e.g. 95 C)
water and
perhaps other agents to form a conditioned slurry of water and crushed oil
sands. 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 sands 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.
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[0009] An overall bitumen extraction process is depicted in Fig. 1. The
water and oil
sand slurry (100) is separated into three major streams in the PSC (101):
bitumen froth (102),
middlings (104) and PSC underflow (106). Further processing of each of these
streams is
explained below. Also shown in Fig. 1, is the solvent (108) added for froth
treatment (110),
bitumen (112), TSRU (tailings solvent recovery unit) tailings (114), flotation
cells (116),
recycle bitumen froth (118), flotation tailings (FT) (120), and an external
tailings area (ETA)
(122).
[0010] Regardless of the type of WBE process employed, the process will
typically
result in the production of a bitumen froth (102) that requires treatment with
a solvent. For
example, in the Clark Process, a bitumen froth stream 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 the bitumen is delivered to a refining facility for further processing.
[0012] One PFT process will now be described further, although variations
of the
process exist. The PFT process may comprise at least three units: Froth
Separation Unit
(FSU), Solvent Recovery Unit (SRU) and Tailings Solvent Recovery Unit (TSRU).
Two
FSUs may be used, as shown in Fig. 2.
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[0013]
With reference to Fig. 2, mixing of solvent with the feed bitumen froth (200)
is
carried out counter-currently in two stages: FSU-1 and FSU-2, labeled as Froth
Separation
Unit 1 (202) and Froth Separation Unit 2 (204). 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 by gravity. Examples of paraffinic solvents are pentane or
hexane, either
used alone or mixed with isomers of pentanes or hexanes, respectively. An
example of a
paraffinic solvent is a mixture of iso-pentane and n-pentane. In FSU-1 (202),
the froth (200) is
mixed with the solvent-rich oil stream (201) from the second stage (FSU-2)
(204). The
temperature of FSU-1 (202) is maintained at, for instance, about 60 C to about
80 C, or about
70 C, while the solvent to bitumen (SB) ratio may be from 1.4:1 to 2.2:1 by
weight or may be
controlled around 1.6:1 by weight for a 60:40 mixture of n-pentane: iso-
pentane. The
overhead from FSU-1 (202) is the diluted bitumen product (205) (also referred
to as the
hydrocarbon leg) and the bottom stream from FSU-1 (202) is the tailings (207)
comprising
water, solids (inorganics), asphaltenes, and some residual bitumen. The
residual bitumen from
this bottom stream is further extracted in FSU-2 (204) by contacting it with
fresh solvent
(209), for instance, in a 25 to 30:1 (w/w) SB ratio at, for instance, about 80
C to about 100 C,
or about 90 C. Examples of operating pressures of FSU-1 and FSU-2 are about
550 kPag and
600 kPag, respectively. The solvent-rich oil (overhead) (201) from FSU-2 (204)
is mixed with
the fresh froth feed (200) as mentioned above. The bottom stream from FSU-2
(204) is the
tailings (211) comprising solids, water, asphaltenes and residual solvent,
which is to be
recovered in the Tailings Solvent Recovery Unit (TSRU) (206) prior to the
disposal of the
tailings (213) in an ETA. The recovered solvent (218) from TSRU (206) is
directed to the
makeup solvent (209). Solvent from the diluted bitumen overhead stream (205)
is recovered
in the Solvent Recovery Unit (SRU) (208) and passed as solvent (217) to
Solvent Storage
(210). Bitumen (215) exiting the SRU (208) is also illustrated. 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.
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[0014] As depicted in Fig. 1, the PSC underflow (106) from the PSC (101)
is sent to
an External Tailings Area (ETA) (122). The PSC underflow (106) is a coarse
stream and is
typically used as a building material at the ETA to contain tailings ponds of
tailings with
lower solids content.
[0015] Paraffinic froth treatment (PFT) tailings (for example TSRU
tailings stream
(213)) may comprise both coarse and fine particles and is sent for further
treatment or
disposed in an ETA.
[0016] As depicted in Fig. 1, from the PSC (101), the middlings stream
(104),
comprising bitumen and about 10-30 wt. % solids, or about 20-25 wt. % solids
is withdrawn
and sent to the flotation cells (116) to further recover bitumen. The
middlings (104),
comprising bitumen, solids and water are processed by bubbling air through the
slurry and
creating a bitumen froth (118), which is recycled back to the PSC (101). The
flotation tailings
(FT) (120) from the flotation cells (116), comprising mostly solids and water,
are sent for
further treatment or disposed in an ETA.
[0017] 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. Further densification
to a solid
state can be very slow.
[0018] It would be desirable to have an alternative or improved method of
treating oil
sand tailings.
SUMMARY
[0019] It is an object of the present disclosure to provide methods of
treating oil sand
tailings.
[0020] Disclosed is a method of treating oil sand tailings including
passing the tailings
through a pipe having a length, and producing treated tailings by adding an
agglomerating
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polymer at multiple locations along the length of the pipe to disperse the
polymer into the
tailings.
[0021] 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
[0022] 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.
[0023] Fig. 1 is a flow diagram of a prior art process for extracting
bitumen from
mined oil sand.
[0024] Fig. 2 is a flow diagram of a prior art paraffinic froth treatment
process.
[0025] Fig. 3A is a schematic of a T-junction delivery system.
[0026] Fig. 3B is a schematic of a T-junction delivery system.
[0027] Fig. 3C is a schematic of a T-junction delivery system.
[0028] Fig. 4 is a flow chart of a method of treating oil sand tailings.
[0029] Fig. 5A is a schematic of a delivery system.
[0030] Fig. 5B is a schematic of a delivery system.
[0031] Fig. 5C is a schematic of a delivery system.
[0032] Fig. 6 is a flow chart of a method of delivering an agglomerating
polymer to a
flowing tailings stream.
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. .
[0033] Fig. 7 is a flow chart of method of retrofitting a pipe for
carrying a tailings
stream with an agglomerating polymer injection system.
[0034] 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
drawn to scale, but are drafted for purposes of convenience and clarity in
illustrating various
aspects of the disclosure.
DETAILED DESCRIPTION
[0035] 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.
[0036] 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.
[0037] Throughout this disclosure, where a range is used, any
number between or
inclusive of the range is implied.
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[0038] 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
liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be
straight chained,
branched, or partially or fully cyclic.
[0039] "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.) % aliphatics (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. %).
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.
[0040] "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 10.0 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
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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
possible. The reduced viscosity makes the drainage or dissolution quicker and
therefore
directly contributes to the recovery rate.
[0041] "Fine particles" or "fines" are generally defined as those solids
having a size
of less than 44 microns ( m), that is, material that passes through a 325 mesh
(44 micron).
[0042] "Coarse particles" are generally defined as those solids having a
size of greater
than 44 microns (pm).
[0043] The term "solvent" as used in the present disclosure should be
understood to
mean either a single solvent, or a combination of solvents.
[0044] 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.
[0045] 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.
[0046] The term "paraffinic solvent" (also known as aliphatic) 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
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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 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.
[0047] An agglomerating polymer may be used to agglomerate solids in oil
sand
tailings, to facilitate solid-liquid separation. However, mixing of an
agglomerating polymer
with oil sand tailings can be challenging.
[0048] More broadly, mixing of a viscous material with a dense slurry can
be
challenging. Typically, mixing is assumed to occur if the dense slurry reaches
a high enough
Reynolds number. In reality, however, it has been discovered that this can
prove insufficient,
especially if the Reynolds number is not high enough to achieve mixing given
the viscous
forces as defined by the mixing viscous material, rather than by the dense
slurry. As a result,
inline flocculation mechanisms can under-achieve in the field of mixing. Much
effort at
improving contacting a flocculating polymer with a slurry has taken the form
of enhanced
mixing. Enhanced mixing can include static and dynamic mixers. In many cases,
the increase
in mixing energy also increases shear, which can have a negative effect of
degrading
shear-sensitive polymers.
[0049] Industry solutions to this problem have included introducing the
viscous
material, like a polymer, in a Venturi mixer. Computational Fluid Dynamics
(CFD) modeling
indicates flow mix and shear based on classical fluid dynamics. However, for
larger pipes (for
instance having diameters larger than 8 inches), even turbulent conditions
that are typically
sufficient for mixing can be insufficient for ensuring good contact between a
polymer and a
slurry. In addition, excess shear, typical of mixing, can result in
destruction of flocs which are
shear sensitive. These challenges may be aggravated by slurries that defy
classical numerical
modeling and which demand other solutions. T-injectors and Venturi mixers have
proven
inadequate, but are still recommended in the industry. More robust mixing can
have some
positive results, and static or dynamic mixers have been tried with some
success, but these
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methods come with other challenges such as increased pressure drop, several
moving parts,
dependence on flowrates, etc. The oil sands industry has used an airline
spigot or a jet injector
system to introduce polymer into a pipe carrying oil sand tailings.
[0050]
Certain polymer injection point configurations have one (a T-junction) to nine
introduction points, often in an annulus (i.e. arranged radially like numbers
around a clock) in
a Venturi mixer. Where insufficient mixing occurs, these nine points lead to a
large "ribbon"
of viscous material flowing into the dense material. To achieve sufficient
contact at a large
scale, this ribbon should have a diameter comparable to that achieved at a
smaller scale. This
requires more injection points around the annulus (again, radially like
numbers around a
clock). However, the increase in injection points drives up the cost for
piping and distribution
of polymer. Such an arrangement is illustrated in Figs. 3A, 3B and 3C by way
of, from top to
bottom, a simplified side view, a side view, and a cross-section view. Line
301 carries slurry
(illustrated as flow from left to right). Line 302 carries polymer
(illustrated as flow from top
to bottom). Lines 301 and 302 meet at one or more T locations (intersections
at the pipe), but
the T injection is at the same axis along the pipe. The polymer is injected at
a single pressure
because it is injected at a single point in the axis of the pipe.
[0051] To
date, the emphasis relies on mixing rather than on dispersion. It has now
been recognized that mixing itself is not the goal; it is the means to the
goal of dispersing a
polymer with the slurry.
[0052] It
has now been recognized that by adding an agglomerating polymer at
multiple locations along the length of a pipe carrying the tailings, the
polymer can be
dispersed into the tailings.
[0053]
Fig. 4 is a flow chart of a method of treating oil sand tailings. A method of
treating oil sand tailings may comprise passing (402) the tailings through a
pipe having a
length, and producing (404) treated tailings by adding an agglomerating
polymer at multiple
locations along the length of the pipe to disperse the polymer into the
tailings.
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[0054] The pipe may be any suitable pipe. The diameter of the pipe may be
between 2
inches and 36 inches, or between 3 inches and 24 inches, or between 6 inches
and 16 inches,
or greater than 8 inches. The length of the pipe may be between 50 m and 20
km, or between
500 m and 8 km, or less than 100 m, or greater than 1 km, or between 100 m and
1 km.
[0055] The method may comprise using a single pump to pump the polymer
into the
pipe using a network of injection tubes distributed along the length of the
pipe. The network
of injection tubes may comprise pressure gauges and flow regulators to adjust
a flow rate of
the polymer into the pipe. The network of injection tubes may comprise tubes
of different
diameter for regulating polymer flow, for instance to achieve proportional
flow at the
different pressures along the pipe. The network of injection tubes may
comprise a static flow
regulating system for regulating polymer flow, such as flow constrictors,
valves, chokes. The
injection points where the injection tubes meet the pipe may be spaced greater
than 1 cm
apart, or greater than 1 m apart, or greater than 10 m apart. A single pump
may be used to
split a flow of the polymer into a series of tubing to deliver polymer to
multiple injection
points along the pipe. Such an apparatus may be constructed off-site out of
flexible tubing so
that installation requires only the drilling of holes and placement of
fittings into the holes.
Such an apparatus may also be fitted with pressure gauges and flow
restrictors, if desired, to
adjust the flowrate in each tube for achieving consistent flow throughout
without adding more
pumps. In this way, only one pump may be needed to adjust polymer dosage. Such
an
arrangement is illustrated in Figs. 5A, 5B and 5C by way of three side views.
Line 501 carries
slurry (illustrated as left to right). Multiple tubes (illustrated as 502,
503, 504, 505, 506, 507,
508, 509, 510, 511, and 512) connect with line 501 to inject polymer, but at
different axial
locations along the line 501.
[0056] The network of injection tubes may comprise injection tubes of
different
diameters for regulating polymer flow. The network of injection tubes may
comprise a static
flow regulating system for regulating polymer flow, such as, but not limited
to, flow
constrictors, valves, or chokes.
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[0057] The multiple locations may be greater than ten locations, or
between 12 and 40
locations, or between 4 and 12 locations. The multiple locations may be
greater than 10 cm
apart from one another along the length of the pipe, or greater than 1 m
apart, or greater than
3m apart. The multiple locations may be spaced along the length of the pipe at
intervals
greater than 2-20 times the diameter of the pipe.
[0058] The method may further comprise adjusting one or more rheological
properties
of one of both of the tailings and agglomerating polymer to bring their one or
more
rheological properties closer together, to assist in dispersing the polymer
into the tailings. The
adjustment of the rheological properties may be achieved by adding a component
to the slurry
to change a physical or chemical component of the slurry. For example, the
slurry may be
subjected to shear, heated, diluted, introduced to a viscosity reducer, etc.
in order to adjust the
rheological properties. The one more rheological properties may comprise
static yield stress,
viscosity, or density.
[0059] The tailings and the agglomerating polymer together may have a
Reynolds
number below 10,000, or below 3000, or below 1000, or below 200, or above
1000, or
between 1000 and 5000, wherein the Reynolds numbers is calculated as follows:
inertial forces of the tailings/ viscous forces of the agglomerating polymer,
where the inertial forces of the tailings = density of tailings (kg/m3) *
velocity of the
tailings (m/s) * diameter of the pipe (m),
and where the viscous forces of the agglomerating polymer = dynamic viscosity
of the
agglomerating polymer (Pa.$).
[0060] In the above equation, the following abbreviations are used: kg
(kilograms), m
(meters), s (seconds), Pa.s (Pascal-seconds), and * (multiplication).
[0061] The tailings and agglomerating polymer flowing in the pipe may
together have
a Hedstrom number greater than 10, or greater than 1000, or greater than
1,000,000. The
Hedstrom number is calculated as the ratio of the density * the square of the
pipe Inner
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Diameter * yield strength of the fluid divided by the square of the dynamic
viscosity, with
units expressed in standard units (kg, m, seconds). The Hedstrom number and
the Reynolds
Number are together used to approximate a transition between laminar and
turbulent flow for
some Non-Newtonian fluids. If the Reynolds number is above this transition
point, the flow is
considered turbulent. The relationship is typically expressed in the form of
Transition point =
A * ReB, where A and B vary based on the size of the Hedstrom number. As used
herein, if
the Hedstrom number is greater than 100,000, the transition Reynolds number is
the square
root of the Hedstrom Number. If the Hedstrom Number is less than 100,000, the
transition
Reynolds number is 80 times the Hedstrom Number taken to the 0.4 power. The
Reynolds
number may be within 5000 of the transition Reynolds number, or within an
order of
magnitude of the transition Reynolds number.
[0062] The method may be applied to Non-Newtonian fluids that flow near
or below
the transition to turbulent flow. The method may be applied to fluids with a
Reynolds number
that is less than twice the value of the transition point using the Hedstrom
number.
[0063] The method may further comprise passing the treated tailings
through a
perforated plate or flow controlling device. The plate or flow controlling
device would force a
change in flow behavior within the pipe. This change in flow behavior can be
used to
introduce more mixing, greater contact of the slurry with the agglomerating
polymer, or to
turn the material and impart shear.
[0064] The tailings may stem from water-based extraction of bitumen from
oil sand.
The tailings may comprise primary separation cell (PSC) tailings, middlings,
flotation
tailings, froth treatment tailings, TSRU tailings, fluid fine tailings (FFT),
mature fine tailings
(MFT), or a mixture thereof. MFT may be diluted with water prior to treating
the tailings
stream. This dilution may reduce the viscosity and/or solids content of the
MFT in order to
facilitate mixing of the multiple streams. The tailings stream may have a
solids content
between 10 wt. % and 65 wt. %. The tailings stream may have a ratio of sand to
fine particles
between 0.5 and 5, or between 0.01 and 10. The tailings stream may comprise
bitumen in a
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CA 02893552 2016-04-22
quantity of less than 10 wt. %. The tailings may comprise water in an amount
of greater than
20 wt. %, or greater than 50 wt. %, or greater than 80 wt. %.
[0065] The tailings may stem from solvent-based extraction of bitumen
from oil sand.
[0066] The agglomerating polymer may be any suitable polymer and may be
used to
agglomerate solids within the tailings to assist dewatering. The agglomerating
polymer may
comprise a flocculating polymer. The flocculating polymer may comprise a
polyacrylamide
(PAM). The agglomerating polymer may comprises 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.
[0067] The method may further comprise discharging the treated tailings
stream to a
dedicated disposal area (DDA). The method may further comprise collecting
water from the
DDA for recycling.
[0068] The method may further comprise conditioning or treating or both
conditioning
and treating the treated tailings with a tailings treating technology. The
tailings treating
technology may comprise thickening, centrifugation, or in-line flocculation.
The method may
further comprise following the tailings treating technology with thin or thick
lift drying.
[0069] The tailings may comprise an aluminate and a silicate added to
form
chemically-induced micro-agglomerates (CIMA). The aluminate may comprise
sodium
aluminate and the silicate may comprise colloidal silica. An example of using
CIMA in
tailings flocculation is described in Canadian Patent Application No.
2,767,510 (Lin).
[0070] The dispersing may be effected in the substantial absence of
mixing means.
Mixing means refers to mixing means such as, for instance, static and dynamic
mixers as
described above, and does not relate to mixing that will occur simply by the
polymer injection
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CA 02893552 2015-06-04
or flow in the pipe. Quantitatively, "substantial absence" may refer to where
no more than
5%, or no more than 1% of the dispersion is due to mixing means.
[0071] As illustrated in Fig. 6, a method of delivering an agglomerating
polymer to a
flowing tailings stream may comprise providing an agglomerating polymer (602);
and
pumping, using a single pump, the agglomerating polymer through a network of
tubes and
into the tailings stream at multiple injection points along a direction of
travel of the tailings
stream, to disperse the agglomerating polymer in the tailings stream (604).
The method may
further comprise monitoring delivery of the agglomerating polymer and
adjusting a flow rate
of the agglomerating polymer for achieving desired dispersion.
[0072] As illustrated in Fig. 7, a method of retrofitting a pipe for
carrying a tailings
stream with an agglomerating polymer injection system may comprise forming
holes in the
pipe at multiple points along a length of the pipe (702); and attaching the
agglomerating
polymer injection system to the pipe to fluidly connect a source of
agglomerating polymer to
the pipe through the holes using a network of flexible tubing (704).
[0073] Table 1 is an illustration of calculations of a flowing primary
line containing a
non-Newtonian fluid which may be challenging to model. The material is to be
thoroughly
mixed with a viscous chemical flocculent. A traditional approach to this
problem is to
increase the flowrate to ensure the primary line is in the turbulent regime.
However, because
the material is non-Newtonian, it is non-trivial to calculate the precise
transition point to
turbulence. In Table 1, the calculations are based on introducing the viscous
fluid in either
three spigot ports at a single junction around the circumference of the pipe
(i.e. radially) or in
50 spigot ports along the length of the pipe. In one calculation, the material
in Case #1 is
turbulent in flow regime, but this turbulence may be insufficient to mix in
the viscous
polymer, as demonstrated by the second calculation of flow regime in Case #2.
In Case #1, a
traditional definition of the Reynolds number was employed, that is, the ratio
of viscous
forces to inertial forces for the carrier primary fluid was used, which
constitutes the great
majority of the flowing medium. In Case #2, the calculation was made
differently, that is, the
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CA 02893552 2015-06-04
ratio of the inertial forces of the carrier stream to the viscous forces of
the smaller, viscous
stream, was used. This is because the smaller stream must be torn apart by the
energy in the
carrier fluid and mixed into the larger stream. The fluid providing the energy
to perform this
action is the primary carrier fluid, while the viscosity of the smaller stream
resists the action
of mixing into the primary stream. Thus, a conventional calculation might
suggest that the
flow is turbulent and should mix as such, while the action at the interface of
the fluids is more
laminar in nature. The laminar flow regime requires diffusion as a major
vector for mixing to
occur, and the limitation on diffusion is described by the penetration of the
materials into one
another. Table 1 shows that three spigots arranged radially would result in a
"ribbon" of
viscous material flowing in the pipe after the injector with a radius of 1.4
cm. Such a thick
material will be very challenging to mix by diffusion alone. The use of 50
spigots along the
length of the pipe has the impact of reducing the effective radius of this
"ribbon" of the
resisting fluid to 3.5 mm, a much more manageable diffusion mixing challenge
in a flowing
stream.
[0074] Table 1.
Stream Parameter Parameter Units Case # 1 Case #1 Case
# 2 Case # 2
D diameter inches 12 12
12 12
Q flow rate/hr m3/hr 1200 1200
1200 1200
Q flow rate m3/s 0.3333 0.3333 ,
0.3333 0.3333
Dh diameter m 0.3048 0.3048 0.3048
0.3048
dynamic
Primary
Line viscosity or
consistency mu Pa-s 0.13 0.0487 0.13
0.0487
kinetic
viscosity mu/rho m2/s 9.3592E-05 3.5061E-05
9.3592E-05 , 3.5061E-05
A area m2 0.07297 0.07297 0.07297
0.07297
rho density kg!m3 1389 1389 1389
1389
v velocity m/s 4.5683 4.5683 4.5683
4.5683
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CA 02893552 2015-06-04
,
Stream Parameter Parameter Units Case # 1 Case
# 1 Case # 2 Case # 2
tau yield stress _ Pa 39 56
39 56
Re Q Dh/vA 14878 39714 14878
39714
i
density x yield x
diameter2
He consistency 2 297790 3046929 297790
3046929
Transition
Reynolds 13643 43639 13643
43639
Flow
Regime Turbulent Laminar Turbulent
Laminar
Safety
Factor 994 -9% 994
-994
dynamic
viscosity or
consistency mu Pa-s 1.16 1.16 1.16
1.16
Viscous
Material kinetic
of fluid viscosity mu/rho n12/s 0.00116 0.00116
0.00116 0.00116
flocculent
ribbon rho density kg/m3 1000 1000 1000
1000
tau yield stress Pa 27 27 27
27
Cross
section
radius (if 1
spigot) m 0.04912 0.04912
0.04912 0.04912
Cross
section
radius each m 0.01418 0.01418
0.003474 0.003474
Cross
Section
_ area m2 0.001895 0.001895
0.001895 0.001895
Number of
Spigots 3 3 50
50
Polymer
_ flowrate m3/hr 32 32 32
32
Full Polymer
Stream flowrate m3/s
0.008889 0.008889 0.008889 0.008889
Total
Flowrate
after floc m3/s 0.3422 0.3422 0.3422
0.3422
Total
Velocity in
line after
floc m/s 4.6902 4.6902 4.6902
4.6902
Total
Velocity
after floc 4.6902 4.6902 4.6902
4.6902
_ Re (ReDr) 1711.8 1711.8 1711.8
1711.8
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.
CA 02893552 2016-01-14
Stream Parameter Parameter Units Case # 1 Case #
1 Case # 2 Case # 2
Flow
Regime Laminar Laminar Laminar Laminar
100751 The scope of the claims should not be limited by particular
embodiments set
forth herein, but should be construed in a manner consistent with the
specification as a whole.
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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