Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 2967868 2017-05-19
OPTIMIZED BITUMEN RECOVERY AND PROCESS AID DOSAGE VIA WATER
CHEMISTRY FEEDBACK CONTROL
BACKGROUND
Field of Disclosure
[0001] The disclosure relates generally to the field of oil sand
processing, and more
particularly to water-based extraction.
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
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mining may be performed to access the oil sand, which can be treated with
water, steam or
solvents to extract the heavy oil.
[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) or as a water-based oil sand extraction
process. WBE is a
commonly used process to extract bitumen from mined oil sand.
[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 WBE process, a water and oil sand slurry is separated into
three major
streams in the PSC: bitumen froth, middlings, and a PSC underflow (also
referred to as coarse
sand tailings (CST)).
[0008] 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 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
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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.
[0009] Solvent is typically recovered from the diluted product bitumen
component
before the bitumen is delivered to a refining facility for further processing.
[0010] 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
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.
[0011] From the PSC, the middlings, which may comprise bitumen and about
10-30 wt.
% solids, or about 20-25 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.
Fine tailings (FT) from the flotation cells, comprising mostly solids and
water, are sent for
further treatment or disposed in an external tailings area (ETA).
[0012] It would be desirable to have an alternative or improved method of
water-based
oil sand extraction.
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SUMMARY
[0013] It is an object of the present disclosure to provide an
alternative method of water-
based oil sand extraction.
[0014] Disclosed is a method of comprising:
a) providing an oil sand slurry stream;
b) adding a process aid to the oil sand slurry stream;
c) processing the oil sand slurry stream into bitumen froth, fine tailings
(FT), and
coarse sand tailings (CST), including using a primary separation cell (PSC);
d) measuring a water chemistry parameter of at least one of the oil sand
slurry
stream, the FT, the CST, the bitumen froth, middlings from the PSC, and a
middling
layer inside the PSC; and
e) based on the measured water chemistry parameter, adjusting at least one
of a
dosage of the process aid added to the oil sand slurry stream, process
temperature,
mixing conditions, oil sand slurry stream composition, and water addition to
the PSC.
[0015] 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
[0016] 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.
[0017] Fig. 1 is a graph of the effects of caustic on primary bitumen
recovery at varying
ore fines content.
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[0018] Fig. 2 is a graph of the effects of pH on primary bitumen recovery
at varying ore
fines content.
[0019] Fig 3 is a graph of the effects of caustic on tailings Na+
concentration at varying
ore fines content.
[0020] Fig. 4 is a graph of the relationship of Na/Nao to bitumen
recovery at varying
ore fines content, where Nao represents an initial value in process water
prior contact with the
ore.
[0021] Fig. 5 is a graph of the effects of caustic on tailings electrical
conductivity (EC)
at varying ore fines content.
[0022] Fig. 6 is a graph of the relationship of EC/ECo to bitumen
recovery at varying
ore fines content, where ECo represents an initial value in process water
prior contact with the
ore.
[0023] Fig. 7 is a graph of the effects of caustic on tailings Ca++
concentration at
varying ore fines content.
[0024] Fig. 8 is a graph of relationship of Ca/Cao to bitumen recovery at
varying ore
fines content, where Cao represents the initial value in process water prior
contact with the ore.
[0025] Fig. 9 is a graph of the effects of caustic on tailings Mg++
concentration at
varying ore fines content.
[0026] Fig. 10 is a graph of the relationship of Mg/Mgo to bitumen
recovery at varying
ore fines content, where Mgo represents the initial value in process water
prior contact with the
ore.
[0027] Fig. 11 is a graph of the effects of caustic on tailings K+
concentration at varying
ore fines content.
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[0028] Fig. 12 is a graph of the relationship of K/Ko to bitumen recovery
at varying ore
fines content, where Ko represents the initial value in process water prior
contact with the ore.
[0029] Fig. 13 is a schematic of a method including adjusting process aid
dosage based
on a measured water chemistry parameter.
[0030] Fig. 14 is a schematic of a method including adjusting ore tonnage
based on a
measured water chemistry parameter.
[0031] Fig. 15 is a schematic of a method including adjusting water
and/or water: ore
ratio based on a measured water chemistry parameter.
[0032] 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
[0033] 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.
[0034] 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,
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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.
[0035] Throughout this disclosure, where a range is used, any number
between or
inclusive of the range is implied.
100361 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.
[0037] "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. %), 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.
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[0038] "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
combination of clay, sand, water and bitumen.
[0039] "Fine particles" or "fines" are generally defined as those solids
having a size of
less than 44 microns ( m), as determined by laser diffraction particle size
measurement.
[0040] "Coarse particles" are generally defined as those solids having a
size of greater
than 44 microns (.im).
[0041] The term "solvent" as used in the present disclosure should be
understood to
mean either a single solvent, or a combination of solvents.
[0042] 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.
[0043] 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.
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[0044] 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
be a C4 to C20
or C4 to Co 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.
[0045] Process aids (PA) are commonly used in oil sand extraction to
increase bitumen
recovery. PA addition to oil sand slurries has several effects on the slurry
water chemistry,
including changes in pH, electrical conductivity, and ions concentration.
Typically, bitumen
recovery increases with PA dosage up to an optimum level. Beyond this optimum
level, further
PA addition (over-dosage) may be detrimental to bitumen extraction. Thus,
proper PA dosage
is useful not only to reduce PA consumption and costs, but also to assist
bitumen recovery.
[0046] Caustic dosage optimization based on ore fines wt. % (solids
basis) may be
known. However, experimental work herein demonstrates that the measurement of
ore fines is
not sufficient to predict optimum PA dosage for maximum bitumen recovery. The
present
invention takes into consideration water chemistry for PA dosage control or
other process
adjustments in a water-based oil sand extraction process.
[0047] Fig. 1 is a graph of primary bitumen recovery versus caustic at
varying ore fines
contents. In Fig. 1, HF (high fines) represents greater than 18 wt.% fines, LF
(low fines)
represents less than 10 wt. % fines, and BC (base case) represents about 11-15
wt. % fines, all
on a dry bitumen basis. However, the present inventors have found that a
stronger correlation
exists for primary bitumen recovery versus pH as illustrated in Fig. 2, which
uses the same ore
labels as Fig. 1.
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[0048] Surfactant release from the bitumen (responsible for bitumen-sand
separation)
is pH dependent. A certain pH threshold is required for maximize bitumen
recovery (Fig 2b).
This threshold value (a pH of about 8.6) appears to be independent of ore
fines wt %. However,
higher fines ores may require more caustic to reach such pH level. It has been
discovered that
not only does caustic dosage and ore fine content affect tailing PH, but also
that other factors
affecting water chemistry also affect tailings pH and maximization of bitumen
recovery.
[0049] Once the ore is in contact with hot process water and PA, the
process water
experiences several changes. Figures 3-12 demonstrate changes in water
chemistry
characteristics (ions concentration and electrical conductivity) with caustic
dosage. As bitumen
recovery increases, Ca++, Mg++ and K+ ions concentration decreases, while Na+
concentration
and electrical conductivity (EC) increases. Table 1 provides the water
characteristics of the
process water prior to contact with the ore.
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[0050] Table 1.
Water chemistry analysis Units Process water chemistry
pH N/A 8.4
_
Electrical Conductivity uS/cm 562.0
HCO3- ppm, wt/vol 250.0
F- ppm, wt/vol 1.0
Cl- ppm, wt/vol 10.0
SO4-- ppm, wt/vol 74.0
Al (396.152 nm)-Rad ppm, wt/vol 0.6
Ba (455.403 nm)-Ax ppm, wt/vol 0.1
Ca (422.673 nm)-Rad ppm, wt/vol 28.0
Ca (317.933 nm)-Ax ppm, wt/vol 27.9
Fe (259.410 nm)-Ax ppm, wt/vol 0.1
K (766.491 nm)-Rad ppm, wt/vol 5.9
Mg (285.213 nm)-Rad ppm, wt/vol 11.3
Mn (257.610 nm)-Ax ppm, wt/vol ND
Mo (202.032 nm)-Ax ppm, wt/vol 0.0
Na (589.592 nm)-Rad ppm, wt/vol 89.0
Ni (216.555 nm)-Ax ppm, wt/vol ND
Si (288.158 nm)-Rad ppm, wt/vol 7.0
Sr (407.771 nm)-Ax ppm, wt/vol 0.3
Zn (213.857 nm)-Rad ppm, wt/vol ND
[0051] A method may comprise:
a) providing an oil sand slurry stream comprising bitumen, water, and solids;
b) adding a process aid to the oil sand slurry stream;
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c) processing the oil sand slurry stream into bitumen froth, fine tailings
(FT), and
coarse sand tailings (CST), including using a primary separation cell (PSC);
d) measuring a water chemistry parameter of at least one of the oil sand
slurry stream,
the FT, the CST, the bitumen froth, middlings from the PSC, and a middling
layer
inside the PSC; and
e) based on the measured water chemistry parameter, adjusting at least one of
a dosage
of the process aid added to the oil sand slurry stream, process temperature,
mixing
conditions, oil sand slurry stream composition, and water addition to the PSC.
[0052] The oil sand slurry stream may be any suitable oil sand slurry
stream and may
stem from mined oil sand. The oil sand slurry stream may be a feed stream to a
PSC. The oil
sand slurry stream may comprise 7 to 16 wt. % bitumen, 1 to 7 wt. % water, and
77 to 92 wt.
% solids. The oil sand slurry stream may comprise 10 to 12.5 wt. % bitumen,
2.5 to 6 wt. %
water, and 81.5 to 87.5 wt. % solids.
[0053] The process aid may be any suitable process aid and may be
caustic. The process
aid may be suitable to increase the pH of the slurry water.
[0054] In a PSC, bitumen froth is separated from the majority of water
and solids. A
feed to the PSC comprises bitumen, solids, and water, which may be an aerated
oil sand slurry
from a hydrotranspoil line stemming from mined oil sand ore. A PSC may
comprise a
cylindrical section at the top where aerated bitumen froth with some solids
and water rises
upwards and flows to the next process equipment for cleanup in froth
treatment, and a conical
section below, which creates a densification zone (comprising the majority of
solids and water)
establishing a vertical density gradient in the PSC, which enables separation
of bitumen froth.
The cylindrical section may comprise a froth layer, an underwash layer into
which an
underwash is added, and a middlings layer. The "middling layer" inside the PSC
means the
phase in the PSC beneath the bitumen froth and above the CST. Three streams
typically leave
the PSC, namely, a bitumen froth comprising the majority of the bitumen from
the oil sand
which is withdrawn near the top of the PSC, middlings comprising some bitumen
which is
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withdrawn near the bottom of the cylindrical section of the PSC and which are
sent to flotation
cells for secondary recovery of bitumen, and a coarse sands tailings (CST)
which are withdrawn
at the bottom of the PSC. The CST may comprise water and the majority of
solids from the oil
sand slurry.
[0055] The phrase "processing the oil sand slurry stream into bitumen
froth, fine tailings
(FT), and coarse sand tailings (CST), including using a primary separation
cell (PSC)" is used
herein. The term "including" in this phrase implies that while FT may be not
produced directly
by the PSC, its production includes processing by the PSC. FT may be produced
by processing
a middlings stream in flotation cells to produce FT.
[0056] The water chemistry parameter may be any suitable water chemistry
parameter
and may comprise at least one of pH, electrical conductivity, content of at
least one metal,
content of at least one cation, content of at least one anion, and ionic
strength. The water
chemistry parameter may comprise content of at least one of calcium,
magnesium, sodium,
potassium, bicarbonate, and sulfate. The water chemistry parameter may
comprise pH. The
water chemistry parameter may comprise electrical conductivity. The water
chemistry
parameter may comprise at least one of Na+, K+, Ca++, Mg++ cation content. The
water
chemistry parameter may comprise Ca++ or Mg++ cation content.
[0057] Adjusting process temperature may comprise adjusting the
temperature in the
PSC or in the ore preparation plant upstream of the PSC.
[0058] Adjusting the oil sand slurry stream composition may comprise
adjusting an
amount (i.e., rate) of ore and/or fines introduced to the system, and/or the
water:ore ratio in the
oil sand slurry stream.
[0059] Adjusting water addition to the PSC may comprise adjusting the
amount of
water added to the PSC either via the oil sand slurry stream and/or as
dilution water added to
the PSC.
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[0060] Step e) may particularly comprise adjusting the dosage of the
process aid added
to the oil sand slurry stream. Step e) may further comprise adjusting at least
one of the process
temperature, the mixing conditions, the oil sand slurry stream composition,
and the water
addition to the PSC.
[0061] The water chemistry parameter may be measured with an online water
chemistry
analyzer. The water chemistry analyzer may send a signal to a setpoint hub,
wherein the set
point hub additionally receives a desired setpoint. The setpoint hub may
compare the signal
from the water chemistry analyzer to the desired setpoint, and send a signal
to a feedback
controller. The feedback controller may send a signal to a controller which
controls the
adjusting the dosage of the process aid added to the oil sand slurry stream,
and/or the oil sand
slurry stream composition. The oil sand slurry stream composition may be
adjusted, wherein
the adjusting of the oil sand slurry stream composition comprises adjusting at
least one of a rate
of ore introduced to the system, a rate of fines introduced to the system, and
a water:ore ratio
in the oil sand slurry stream.
[0062] The method may further comprise obtaining an indication of fines
content in the
oil sand slurry stream and further adjusting at least one of the dosage of the
process aid added
to the oil sand slurry stream, the process temperature, the mixing conditions,
the oil sand slurry
stream composition, and the water addition to the PSC, based at least in part,
on the fines
content. The water chemistry parameter may be measured with an online water
chemistry
analyzer. The water chemistry analyzer may send a signal to a setpoint hub,
wherein the set
point hub additionally receives a desired setpoint. The setpoint hub may
compare the signal
from the water chemistry analyzer to the desired setpoint, and send a signal
to a feedback
controller. The feedback controller may send a signal to a controller which
controls the
adjusting the dosage of the process aid added to the oil sand slurry stream,
and/or the oil sand
slurry stream composition. The oil sand slurry stream composition may be
adjusted, wherein
the adjusting of the oil sand slurry stream composition comprises adjusting at
least one of a rate
of ore introduced to the system, a rate of fines introduced to the system, and
a water:ore ratio
in the oil sand slurry stream. The indication of fines in the oil sand slurry
stream may comprise
measuring a natural radiation parameter of the oil sand slurry stream. The
natural gamma
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radiation detection may comprise measuring gamma radiation emitted during
decay of
potassium-40 (K40), uranium-238, or thorium 232.
[0063] Steps a) to d) may be effected continuously. Step e) may be
effected
automatically. Step c) may be effected online, inline, offline, or atline.
[0064] Figs. 13-15 are schematics of methods including adjusting process
aid dosage,
ore tonnage, and water and/or water:ore ratio, respectively, based on a
measured water
chemistry parameter.
[0065] Fig. 13 is a schematic of a method including adjusting process aid
dosage based
on a measured water chemistry parameter. An oil sand slurry stream (1302)
comprising mined
bituminous ore is mixed with water in an ore preparation plant (OPP) (1304).
The oil sand
slurry stream (1302) is passed through hydro-transport (HT) (1306) and is
introduced into a
primary separation cell (PSC) (1310). The PSC produces bitumen froth (1312),
middlings
(1314), and coarse sand tailings (CST) (1316). The middlings are introduced
into flotation cells
(1318) producing fine tailings (FT) (1320). A process aid (1322) (e.g.,
caustic) is added to the
oil sand slurry stream (1302). The stars in Fig. 13 illustrate a water
chemistry parameter
measurement taken of at least one of the oil sand slurry stream (1302), the FT
(1320), the CST
(1316), and a middling layer inside the PSC (1324). For simplicity in the
Figure, the water
chemistry parameter measurements at two locations, the FT (1320) and the CST
(1316) are
shown feeding back (1325 and 1326) from water chemistry analyzer (A) to a set
point hub
(1328). Desired set point data (1330) is fed into the set point hub (1328).
Based on the water
chemistry parameter measurement(s) (1325 and 1326) and the desired set point
data (1330), a
set point offset signal (1332) may be fed to a feedback controller (1334). A
control signal
(1336) may be sent from the feedback controller (1334) to a controller (1338).
Fig. 13 includes
a feed-forward component starting with a fines content measurement from a
fines analyzer (FA)
(1340) of the oil sand slurry stream (1302) which may be optionally included
in the process
configuration. This measurement (1340) is passed to a feedforward controller
(1342) and on to
the controller (C) (1338). The controller (1338) may send a signal to a
process aid dosage
controller (1344) for dosing process aid (1322) addition. It should be noted
that while, for
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CA 2967868 2017-05-19
simplicity, the description Figure 13 (and similarly for Figures 14 and 15)
only illustrate the
feedback signal from water chemistry analyzers (A) located on process lines
1320 and 1316 of
the water-based oil extraction process, that similarly, the water chemistry
analyzers (A) shown
on line 1302, as well as located at the middling layer inside the PSC (1324),
can be utilized in
a similar manner. Additionally, the water chemistry analyzers (A) as shown in
Figures 13-15
can be used either individually or in any combination.
[0066]
Fig. 14 is a schematic of a method including adjusting ore tonnage based on a
measured water chemistry parameter. An oil sand slurry stream (1402)
comprising mined
bituminous ore is mixed with water in an ore preparation plant (OPP) (1404).
The oil sand
slurry stream (1402) is passed through hydro-transport (HT) (1406) and is
introduced into a
primary separation cell (PSC) (1410). The PSC produces bitumen froth (1412),
middlings
(1414), and coarse sand tailings (CST) (1416). The middlings are introduced
into flotation cells
(1418) producing fine tailings (FT) (1420). The stars in Fig. 14 illustrate a
water chemistry
parameter measurement taken of at least one of the oil sand slurry stream
(1402), the FT (1420),
the CST (1416), and a middling layer inside the PSC (1424). The water
chemistry parameter
measurement may also be taken from the bitumen froth or from the middling from
the PSC. For
simplicity in the Figure, the water chemistry parameter measurements at two
locations, the FT
(1420) and the CST (1416) are shown feeding back (1425 and 1426) from a water
chemistry
analyzer (A) to a set point hub (1428). Desired set point data (1430) is fed
into the set point
hub (1428). Based on the water chemistry parameter measurement(s) (1425 and
1426) and the
desired set point data (1430), a set point offset signal (1432) may be fed to
a feedback controller
(1434). A control signal (1436) may be sent from the feedback controller
(1434) to a controller
(C) (1438). Fig. 14 includes a feedforward component starting with a fines
content
measurement from a fines analyzer (FA) (1440) of the oil sand slurry stream
(1402) which may
be optionally included in the process configuration. This measurement (1440)
is passed to a
feedforward controller (1442) and on to the controller (1438). The controller
(1438) may send
a signal to a feed rate/composition controller (1446) for controlling the oil
sand slurry stream
(1402) rate and/or composition of the oil sand slurry stream (or its
individual components, such
as controlling the overall rate of ore to the system) into the ore preparation
plant OPP (1404).
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CA 2967868 2017-05-19
[0067] Fig. 15 is a schematic of a method including adjusting water
and/or water:ore
ratio based on a measured water chemistry parameter. An oil sand slurry stream
(1502)
comprising mined bituminous ore is mixed with water in an ore preparation
plant (OPP) (1504).
The oil sand slurry stream (1502) is passed through hydro-transport (HT)
(1506) and is
introduced into a primary separation cell (PSC) (1510). The PSC produces
bitumen froth
(1512), middlings (1514), and coarse sand tailings (CST) (1516). The middlings
are introduced
into flotation cells (1518) producing fine tailings (FT) (1520). A process aid
(1522) (e.g
caustic) is added to the oil sand slurry stream (1502). The stars in Fig. 15
illustrate a water
chemistry parameter measurement taken of at least one of the oil sand slurry
stream (1502), the
FT (1520), the CST (1516), and a middling layer inside the PSC (1524). The
water chemistry
parameter measurement may also be taken from the bitumen froth or from the
middling from
the PSC. For simplicity in the Figure, the water chemistry parameter
measurements at two
locations, the FT (1520) and the CST (1516) are shown feeding back (1525 and
1526) from a
water chemistry analyzer (A) to a set point hub (1528). Desired set point data
(1530) is fed into
the set point hub (1528). Based on the water chemistry parameter
measurement(s) (1525 and
1526) and the desired set point data (1530), a set point offset signal (1532)
may be fed to a
feedback controller (1534). A control signal (1536) may be sent from the
feedback controller
(1534) to a controller (C) (1538). Fig. 15 includes a feedforward component
starting with a
fines content measurement from a fines analyzer (FA) (1540) of the oil sand
slurry stream
(1502) which may be optionally included in the process configuration. This
measurement
(1540) is passed to a feedforward controller (1542) and on to the controller
(1538). The
controller (1538) may send a signal to a water/ore dosage controller (1546)
for dosing water
addition or for controlling a water:ore ratio.
[0068] 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.
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