Note: Descriptions are shown in the official language in which they were submitted.
BITUMEN EXTRACTION USING A PROCESS AID
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, 20-30 wt. %
water, and 10-
20 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
10-40
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 comprising providing an oil sand slurry
stream
stemming from an oil sand ore; processing the oil sand slurry stream into
bitumen froth,
middlings, and coarse sand tailings (CST), including using a primary
separation cell (PSC);
and adding an acidic process aid beneath a froth layer in the PSC or to the
middlings, for
reducing a pH level beneath the froth layer in the PSC or of the middlings,
for assisting
bitumen and air attachment and for reducing solids in the bitumen froth or a
froth recycle
stream.
[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 schematic of a method including adding a process aid
beneath a
froth layer in the PSC.
[0018] Fig. 2 is a schematic of a method including adding a process aid
to the
middlings.
[0019] Fig. 3 is a graph of middlings pH as a function of caustic dosage,
from
different ores.
[0020] Fig. 4 is a graph of froth quality as a function of middlings pH,
from different
ores.
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[0021] Fig. 5A is a graph of froth solids as a function of acid
injection.
[0022] Fig. 5B is a graph of bitumen recovery as a function of acid
injection.
[0023] Fig. 6A is a graph of middlings solids wt. % as a function of post-
conditioning
acid injection after insufficient bitumen liberation (inadequate caustic
addition).
[0024] Fig. 6B is a graph of approximated bitumen recovery as a function
of post-
conditioning acid injection after insufficient bitumen liberation (inadequate
caustic addition).
[0025] Fig. 7A is a graph of middlings solids wt. % as a function of post-
conditioning
acid injection after sufficient bitumen liberation (adequate caustic
addition).
[0026] Fig. 7B is a graph of middlings fines wt. % (stream basis) as a
function of post-
conditioning acid injection after sufficient bitumen liberation (adequate
caustic addition).
[0027] Fig. 7C is a graph of approximated bitumen recovery as a function
of post-
conditioning acid injection after sufficient bitumen liberation (adequate
caustic addition).
[0028] Fig. 7D is a graph of middlings SFR (sand to fines ratio) as a
function of post-
conditioning acid injection after sufficient bitumen liberation (adequate
caustic addition).
[0029] Fig. 8 is a graph of flocculent dosage requirements for middlings
samples
generated using different acidification level (post-conditioning).
[0030] Figs. 9A-9D are graphs of froth solids recovery versus primary
bitumen
recovery for different ore grades.
[0031] Figs. 10A and 10B are graphs of froth solids wt. % versus primary
bitumen
recovery for different ore grades.
[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
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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
[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, 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.
[0036] 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.
[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.
[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 (jm), as determined by laser diffraction particle size
measurement.
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[0040] "Coarse particles" are generally defined as those solids having a
size of greater
than 44 microns (Inn).
[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.
[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 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.
[0045] 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 hydrotransport line stemming from mined oil sand ore. A PSC may
comprise a
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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 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.
[0046] The main objective in the PSC is to achieve maximum separation
between
product (bitumen froth) and waste components (water and solids). Good solids
separation
from the froth and good distribution of solids in the PSC outlet streams are
advantageous for
several reasons. Solids carried over with the bitumen froth reduces froth
quality leading to
potential inefficiencies in downstream equipment (e.g. high frequency of
filters flushing or
cleaning, and limited tank capacity) or downtime issues (e.g. pipeline or
equipment erosion
issues and reduced equipment reliability).
Unpredictable middlings solids wt. % or
unexpected sand-to-fines (SFR) variations in the flotation tailings stream may
lead to
potential instabilities in the thickener and inadequate floculent
dosification. Therefore, it is
advantageous to be able to tune the PSC solids distribution to assist the
stability of
downstream operations.
[0047] One method may comprise:
a. providing an oil sand slurry stream stemming from an oil sand ore;
b. processing the oil sand slurry stream into bitumen froth, middlings, and
coarse sand tailings (CST), including using a primary separation cell
(PSC); and
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c. adding an acidic process aid beneath a froth layer in the PSC or to the
middlings, for reducing a pH level beneath the froth layer in the PSC or of
the middlings, for assisting bitumen and air attachment and for reducing
solids in the bitumen froth or a froth recycle stream.
[0048] 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 5 to 10 wt. % bitumen, 30 to 60 wt. % water,
and 40 to 60
wt. % solids. The middlings may comprise 0.5 to 3 wt. % bitumen, 60 to 85 wt.
% water, and
to 40 wt. % solids.
[0049] A sufficient amount of the acidic process aid may be added to
reduce the pH
level beneath the froth layer in the PSC or of the middlings to below 8.4. The
acidic process
aid may be added both beneath the froth layer in the PSC and to the middlings.
The acidic
process aid may also be added to a middlings withdrawal stream for reducing
solids in a froth
recycle stream. The addition of the acidic process aid in the PSC is below the
froth layer to
preserve bitumen recovery in the froth layer.
[0050] The method may further comprise providing the oil sand ore and
adding a
caustic process aid to the oil sand ore to form the oil sand slurry stream
having a pH above
8.0, or above 8.2, or above 8.4, for assisting bitumen liberation from sand
from the oil sand
ore. An additional acidic process aid may be added to the CST.
[0051] The acidic process aid may comprise HC1, SO,, NON, HF, H2SO4,
HNO3,
H3PO4, boric acid, formic acid, acetic acid, propionic acid, butyric acid,
valeric acid,
phosphonic acid, polyphosphonocarboxylic acid, Poly-Phosphino Carboxyllic
Acid,
diethylenetriamine penta methylene-phosphonic acid, diethylenetriamine
penta(methylene
phosphonic acid), an acrylic acid polymer, a maleic acid polymer, NaH2PO4,
NaHCO3, or a
combination thereof. The acidic process aid may comprise HC1. The acidic
process aid may
be introduced with dilution water, with underwash water, at an end of a
hydrotransport line
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delivering the oil sand slurry stream, at a froth recycle stream pipe leading
to the PSC, or at an
inlet of the PSC.
[0052] The method may further comprise measuring at least one property of
the oil
sand ore and, based on this measurement, adjusting a dosage of the acidic
process aid. The
method may further comprise measuring a solids content or solids content and
particle size
distribution (PSD) of the bitumen froth and, based on this measurement,
adjusting a dosage of
the acidic process aid. The method may further comprise measuring a particle
size
distribution (PSD) of fine tailings (FT) downstream of the middlings and,
based on this
measurement, adjusting a dosage of the acidic process aid. The method may
further comprise
measuring a pH level beneath a froth layer in the PSC and, based on this
measurement,
adjusting a dosage of the acidic process aid. The method may further comprise
measuring a
pH level of fine tailings (FT) downstream of the middlings and, based on this
measurement,
adjusting a dosage of the acidic process aid. The method may further comprise
measuring a
pH level of the CST and, based on this measurement, adjusting a dosage of the
acidic process
aid. The measurement may be sent to a setpoint hub, wherein the set point hub
additionally
receives a desired setpoint. The setpoint hub may compare the measurement to
the desired
setpoint, and send a signal to a controller. The controller may send a signal
to a dosage
controller which controls the dosage of the acidic process aid. The
measurement and dosage
adjustment may be effected automatically. The measurement may be effected
online, inline,
offline, or atline.
[0053] In one method, froth quality and PSC solids distribution may be
improved by
an acidification step during bitumen flotation. The acidification step may be
accomplished by
injecting a first process aid during conditioning to increase a pH to above
8.0, or above 8.2, or
above 8.4 to induce maximum bitumen liberation from the oil sand, and by
injecting a second
process aid to the PSC to acidify middlings water (i.e., reduce pH below 8.4)
to facilitate
bitumen-air attachment and to modify solids distribution. The second process
aid may be HC1
or another pH regulator. The second process aid injection may be accomplished
using
dilution water, underwash water, middlings stream, or alternative PSC
injection streams
below the froth layer. The second process aid may be injected in the middlings
withdrawal
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stream to improve secondary froth quality. The first process aid may be
controlled depending
on ore properties. The second process aid may be controlled by feedback
control from froth
solids wt%, froth solids PSD, FT solids PSD, pH measurements in the PSC
(including a water
layer immediately below an underwash injection level and/or FT and/or CST
streams). The
second process aid may also be injected directly into a CST stream.
[0054]
Fig. 1 is a schematic of a method including adding a process aid beneath a
froth layer in the PSC. An oil sand slurry stream (102) comprising mined
bituminous ore is
mixed with water in an ore preparation plant (OPP) (104). The oil sand slurry
stream (102) is
passed through hydro-transport (HT) (106) and is introduced into a primary
separation cell
(PSC) (108). The PSC produces bitumen froth (110), middlings (112), and coarse
sand
tailings (CST) (114). The middlings are introduced into flotation cells (116)
producing fine
tailings (FT) (118). A process aid (120) (e.g., caustic) is added to the oil
sand slurry stream
(102). An acidic process aid (121) may be added beneath a froth layer in the
PSC, for
reducing a pH level beneath the froth layer in the PSC, for assisting bitumen
and air
attachment (i.e. by increasing bitumen hydrophobicity) and for reducing solids
in the bitumen
froth. The pH measurements (123,125, and 140) may be taken of at least one of
the FT (118),
the CST (114), and a middling layer inside the PSC (108). For simplicity in
the Fig. 1, the
water chemistry parameter measurements at two locations, the FT (118) and the
CST (114)
are shown feeding back (122 and 124) from separate pH analyzers (123 and 125)
to a set point
hub (126). Desired set point data (128) is fed into the set point hub (126).
Based on the pH
measurement(s) (122 and 124) and the desired set point data (126), a set point
offset signal
(130) may be fed to a feedback controller (132). A control signal (134) may be
sent from the
feedback controller (132) to a controller (136). The controller (136) may send
a signal to an
acidic process aid dosage controller (138) for dosing acidic process aid (121)
addition. It
should be noted that while, for simplicity, the description of Fig. 1 only
illustrates the
feedback signal from the pH analyzers (123 and 125) located on the FT (118)
and CST (114)
of the water-based oil extraction process, similarly, a pH analyzer (140)
shown in the PSC
(108) may be utilized in a similar manner. Additionally, the pH analyzers may
be used either
individually or in any combination.
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[0055]
Fig. 2 is a schematic of a method including adding a process aid to the
middlings. An oil sand slurry stream (202) comprising mined bituminous ore is
mixed with
water in an ore preparation plant (OPP) (204). The oil sand slurry stream
(202) is passed
through hydro-transport (HT) (206) and is introduced into a primary separation
cell (PSC)
(208). The PSC produces bitumen froth (210), middlings (212), and coarse sand
tailings
(CST) (214). The middlings are introduced into flotation cells (216) producing
fine tailings
(FT) (218) and a froth recycle stream (217). A process aid (220) (e.g.,
caustic) is added to the
oil sand slurry stream (202). An acidic process aid (221) may be added to the
middlings
(212), for reducing a pH level of the middlings (212), for assisting bitumen
and air attachment
and for reducing solids in the froth recycle stream (217). The froth recycle
stream (217) may
be recycled back to the inlet of the PSC (208) (not shown). Fig. 2 illustrates
a pH analyzer
(215) located on the FT stream (218). The pH measurement (222) is shown
feeding back
from the pH analyzer (215) to a set point hub (226). Desired set point data
(228) is fed into
the set point hub (226). Based on the pH measurement (222) and the desired set
point data
(228), a set point offset signal (230) may be fed to a controller (236). The
controller (236)
may send a signal to an acidic process aid dosage controller (238) for dosing
acidic process
aid (221) addition.
[0056]
Fig. 3 is a graph of lab generated middlings pH as a function of caustic
dosage,
from different ores. The different ores are HF (high fines ore with more than
20 wt. % fines);
BC (base case with about 11-18 wt. % fines); and LF (low fines ore with less
than 11 wt. %
fines). This demonstrates that middlings pH is significantly affected by
caustic dosage.
[0057]
Fig. 4 is a graph of lab generated froth quality (as indicated by bitumen to
solids ratio (B/S)) as a function of middlings pH, from different ores. The
different ores are
HF (high fines ore with more than 20 wt. % fines); BC (base case with about 11-
18 wt. %
fines); and LF (low fines ore with less than 11 wt. % fines).
This demonstrates that high
middlings pH leads to poor froth quality. Low froth quality (i.e.
bitumen/solids ratio of less
than 4) is more commonly observed with low fines ore (i.e. less 11 wt. %
fines) or caustic
over-dosage (Region II, pH above 8.6).
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[0058] Fig. 5A is a graph of froth solids as a function of acid
injection. Fig. 5B is a
graph of bitumen recovery as a function of acid injection. In respect of Fig.
5A and 5B,
caustic was added in a conditioning step in the lab scale experiments. Acid
injection in the
PSC inlet stream could counterbalance negative effects of high middlings pH.
Acid injection
post-conditioning reduces froth solids (Fig 5A) without significant effects on
bitumen
recovery (Fig 5B). The benefits of froth solids reduction are more pronounced
in low fines
ores.
[0059] Acid addition in the middlings withdrawal stream can potentially
improve
secondary froth quality (froth from flotation circuit). If secondary froth
quality is high
enough, it could be mixed with the primary froth product, instead of being
recycled back to
the PSC inlet. In this particular scenario, the amount of froth recycle could
be replaced by
hydrotransport slurry, increasing PSC throughput.
[0060] Acid injection may facilitate preferential removal of coarse
particles (above 44
pm). Coarse particles are expected to be more detrimental for erosion issues
in the froth
pipelines.
[0061] Low pH in the PSC is typically banned given that it is expected to
increase
middlings viscosity and thus reduce bitumen recovery. Lab scale testing
confirmed two
different scenarios, A and B:
[0062] A - Acid injection (post-conditioning) after insufficient bitumen
liberation
[0063] Experiments conducted with low/inadequate caustic addition during
conditioning, followed by systematic acid addition during a flotation step
(via dilution water).
Fig. 6A is a graph of middlings solids wt. % as a function of post-
conditioning acid injection
after insufficient bitumen liberation (inadequate caustic addition). Fig. 6B
is a graph of
approximated bitumen recovery as a function of post-conditioning acid
injection after
insufficient bitumen liberation (inadequate caustic addition). In respect of
Figs. 6A and 6B,
caustic was added during a conditioning step, and an acid was added during a
flotation step in
these lab scale experiments. In these cases (Figs. 6A and 6B), middlings
characteristics
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(solids wt. % and SFR) remained similar. However, bitumen recovery was
significantly
reduced as acid volume injected increased. This scenario is not recommended.
[0064] B- Acid injection (post-conditioning) after sufficient bitumen
liberation
[0065] Experiments conducted with high enough caustic addition (to
maximize
bitumen liberation) during conditioning, followed by systematic acid addition
during a
flotation step (via dilution water). Fig. 7A is a graph of middlings solids
wt. % as a function
of post-conditioning acid injection after sufficient bitumen liberation
(adequate caustic
addition). Fig. 7B is a graph of middlings fines wt. % (stream basis) as a
function of post-
conditioning acid injection after sufficient bitumen liberation (adequate
caustic addition). Fig.
7C is a graph of approximated bitumen recovery as a function of post-
conditioning acid
injection after sufficient bitumen liberation (adequate caustic addition).
Fig. 7D is a graph of
middlings SFR (sand to fines ratio) as a function of post-conditioning acid
injection after
sufficient bitumen liberation (adequate caustic addition). In respect of Figs.
7A-7D, caustic
was added during a conditioning step, and an acid was added during a flotation
step in these
lab scale experiments. In these cases (Figs. 7A-D), pH adjustment of middlings
allowed
tuning of middlings sand-to-fines ratio (SFR) by controlling solids
distribution. Middlings
characteristics were tuned without detrimental effects on recovery (Figs. 7A-
D).
[0066] A lab experiment was conducted comparing middlings conditioning
using
caustic and flotation without using an acid addition versus middlings
conditioning using
caustic using an acid addition. After seven days, qualitative observations of
the middlings
samples suggested a relative improvement of middlings behavior due to
relatively faster
solids settling. The characteristics of the middlings sample without acid
addition were: 1)
high turbidity of the carried fluid in the middlings samples, indicating a
high amount of
suspended solids; and 2) an unclear interface between the coarse solids and
the carried fluid.
The characteristics of the middlings sample with acid addition were: carried
fluid in middlings
samples looks more translucent, indicating a lower amount of suspended solids;
and 2) a clear
interface distinction between the settled coarse solids and the carried fluid.
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[0067] Fig. 8 is a graph of flocculent dosage requirements for middlings
samples
generated using different acidification level (post-conditioning). The
conditioning used 150
ppm of NaOH (middlings samples generated from lab batch extraction tests) with
acid
addition post-conditioning (HC1: 0.1M).
[0068] Caustic addition during oil sand conditioning may be at a dosage
high enough
to maximize bitumen liberation (e.g. pH 8.0 - 8.4). Acid injection (e.g. HC1)
in the PSC inlet
(or the middlings withdrawal stream) may be at a dosage high enough to
increase bitumen
hydrophobicity which facilitates bitumen-air attachment and enhances water and
solids
rejection from the froth phase without affecting bitumen recovery. The acidic
process aid
may be added in a dosage of 5 and 100 ppmw.
[0069] Figs. 9A-9D are graphs of froth solids recovery versus primary
bitumen
recovery for different ore types (Lab batch extraction tests results). Bitumen
recovery is
defined as grams of bitumen in the froth divided by grams of bitumen in ore.
Solids recovery
is defined as grams of solids in the froth divided by grams of solids in ore.
Fig. 9A- High
fines ore, Fig. 9B - Medium fines ore, Fig. 9C - Low fines and high grade ore,
Fig. 9D -
Summary plot for different ore types. Bitumen recovery increases as caustic
dosage increases.
However, there is a threshold beyond which further increase in caustic dosage
results in
minimal increase in bitumen recovery while it does substantially increase
froth solids
recovery. Adding the acidic process aid in the PSC/flotation stage (after
recovery has been
maximized) reduces froth solids recovery.
[0070] Figs. 10A and 10B. are graphs illustrating the relationship
between froth solids
wt% versus primary bitumen recovery for different ore types (based on lab
batch extraction
tests results). Bitumen recovery typically increases with caustic addition.
Depending on ore
type and process water characteristics, process aid (i.e., caustic) can be as
low as 0 ppm. For
example high grade ore in operations using recycled water. In general, low
fines/high grade
ores are more prone to have high bitumen recoveries as well as high froth
solids. Adding the
acidic process aid in the PSC/flotation stage (after recovery has been
maximized) effectively
reduces froth solids wt% (as shown in Fig 10B).
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[0071]
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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