Note: Descriptions are shown in the official language in which they were submitted.
CA 02568955 2006-11-24
SURFACTANT FOR BITUMEN SEPARATION
FIELD OF THE INVENTION
The present invention relates to surfactants for separating hydrocarbons from
solids. In
particular, it relates to a surfactant derived from low-rank coal and hydrogen
peroxide for
separating bitumen from sand.
. B~CSGRO~TD~OF THE~TV~NT~Ohi
It is lmown to use hot water in order to separate particulate matter such as
clay, sand or
silt from oil and tar. However, a significant amount of oil and tar remains
bound to the
particulate matter after hot water treatment. Hydrogen peroxide is a known
surfactant for
removing oil and tar from sand, silt or clay. However, it may not be
satisfactory in all cases and
is often ineffective. Therefore there is a need in the art for a surfactant
comprising hydrogen
peroxide which may be more effective.
SUIVIlVIARY OF TIBE INVENTION
The present invention is directed to a surfactant for use in separating solids
from
hydrocarbons. In one aspect, the invention comprises hydrogen peroxide which
has been
contacted with a coal. Preferably, the coal comprises low-rank coal and more
preferably
comprises lignite. Preferably, the hydrogen peroxide comprises an aqueous
solution of hydrogen
peroxide which has a concentration of about 3% to about 6% (v:v). Additional
fresh hydrogen
peroxide may be added to the resulting solution after contact with coal.
In another aspect, the invention comprises a method of forming a liquid
surfactant and the
resulting surfactant. The method may comprise the steps of mixing aqueous
hydrogen peroxide
with coal, allowing the mixture to stand and separating the liquid fraction
from the solid fraction.
The coal preferably comprises a low-rank coal. The resulting solution is then
mixed with
additional fresh hydrogen peroxide to form the surfactant. Surprisingly, the
addition of
CA 02568955 2006-11-24
additional fresh hydrogen peroxide improves the performance of the surfactant.
In another aspect, the invention comprises a method of separating hydrocarbons
from
solids comprising the step of contacting the solids/hydrocarbon with a
surfactant described herein
or produced by a method described herein. In one embodiment, the method
comprises the steps
of:
(a) mixing oilsands with fresh water to form a slurry;
(b) adding recycled process water from step (e) to the slurry;.,,
._.... . ...... -- . _. -------- 11 ......... .... ._
(c) mixing the slurry with a surfactant of claim 1 to form a mixture, with or
without
aeration;
(d) collecting bitumen from the mixture;
(e) recovering solids from the mixture, and recovering process water;
(f) recycling process water from step (e) to step (b). .
BRIEF DESCRIPTION OF THE DRAWINGS
Embodiments of the invention are described with reference to the following
drawings:
FIGURE 1: Schematic representation of the process for separation of
hydrocarbons, such as oil
sands, from solids.
FIGURE 2: Microscopic image of the decanted liquid fraction of the first
component used in the
preparation of the surfactant after mixing aqueous hydrogen peroxide with
lignite.
FIGURE 3: Microscopic image of the surfactant after addition of the second
component, the
additional hydrogen peroxide, to the first component in the preparation of the
surfactant.
FIGURE 4: Effect of chemical additives on total recovery of bitumen from Ore
2.
FIGURE 5: Effect of chemical additives on total recovery of bitumen from Ore
3.
FIGURE 6: Effect of chemical additives on total recovery of bitumen from Ore
4.
FIGURE 7: Effect of chemical additives on total recovery of bitumen from Ore
5.
FIGURE 8: Effect of chemical additives on total recovery of bitumen from Ore
6.
-2-
CA 02568955 2006-11-24
FIGURE 9: Bitumen recovery for ore 3 as a function of time using different
chemical additive
conditions.
FIGURE 10: Bitumen recovery for ore 4 as a function of time using different
chemical additive
conditions.
FIGURE 11: Effect of mixing time on bitumen extraction in the first vessel at
pilot plant scale
from oil sands described in Table 3.
FIGURE 12: Effect of mixing time on froth quality - bitumen to solids ratio,
in the first vessel at
pilot plant scale from oil sands described in Table 3.
FIGURE 13: Conductivity analysis of samples obtained from sampling points
described in Table
4.
FIGURE 14: Ion analysis of samples obtained from sampling points described in
Table 4.
FIGURE 15: Effect of accelerant addition - amount of peroxide/lignite solution
on pH of the oil
sand slurry of Ore 4.
FIGURE 16: Decomposition of hydrogen peroxide (H202) during the conditioning
stage.
FIGURE 17: Decomposition of hydrogen peroxide (HZOZ) during the floatation.
DETAILED DESCRIPTION OF THE INVENTION
The present invention provides for a surfactant suitable for separating
hydrocarbons from
particulate solids. In particular, the surfactant may be used to separate
heavy oil or bitumen from
sand, silt, and clay. In one embodiment, the surfactant is particularly
effective to recover
bitumen from oil sands. As used herein, the term "surfactant" shall include a
liquid which
reduces the interfacial tension between a hydrocarbon and water or a solid
material, and may also
encompass any material which facilitates or aids in the process of separating
a hydrocarbon and
water or a solid material. The liquid may be a solution or emulsion of
different substances.
Bitumen is a heavy oil found in oilsands deposits such as those found in
northeastern
Alberta, Canada. Typical oilsands contains about 10-12% bitumen, 4-6% water,
and the
remaining solid fraction comprises mineral matter such as sand and clay.
Without being
-3-
CA 02568955 2006-11-24
restricted to a theory, it is believed that water forms an intermediate layer
between oil which
clings to a sand particle. As used herein, the term "oilsands" shall include
those oil sands
conventionally mined or extracted from heavy oil deposits and.may also include
any solid
particulate matter which is contaminated or mixed.with a heavy oil or
hydrocarbon.
In one embodiment, a surfactant of the present invention is formed by mixed
two
components. The first component is the result of contacting particulate low-
rank coal, such as
lignite, with a dilute solution of hydrogen peroxide. The dilute hydrogen
peroxide may be used
in--a-concentration-of -about-3%-to-about-6%-(v: v), -although-higher-or-Iower-
concentrations- may
also be used. The coal is contacted with the hydrogen peroxide for a
sufficient time, which may
preferably be about 12 to about 24 hours. The length of contact time will
depend on the
concentration of hydrogen peroxide used and the contact temperature. The
contact temperature
may vary and it is not essential that it be controlled. For efficiency, the
use of an ambient contact
temperature is preferred. Higher concentrations and temperatures may reduce
the contact time
necessary to produce an efficacious product. For example, if the contact
temperature is raised
from 20 C to 30 C, then the contact time may be reduced from 24 hours to
about 16 hours.
Also, raising the hydrogen peroxide concentration to 6% from 3% may reduce
contact time to 12
hours from 24 hours at 20 C. Reasonable and minimal experimentation in this
regard will easily
provide one skilled in the art with effective parameters. The resulting
solution contains dissolved
solids from the coal, as well as suspended fine particles. In one embodiment,
the resulting
solution contains very little or no peroxide.
As used herein, the term "low rank coal" means coal having calorific values
less than
14,000 BTU/lb on a moist, mineral-matter-free basis; and with a fixed carbon
on a dry, mineral-
matter-free basis of less than about 69%. The total oxygen content of low rank
coals may vary in
the range of about 5.0 wt. % (dry, mineral matter free basis) for bituminous
coals to 35.0 wt. %,
or more for lignite. Higher grades of coal may be used but are not preferred.
Lignite has an
average carbon content of 30%, volatile matter 27%, and heating value of 7,000
Btu per pound.
The highest ranked coal, anthracite, has an average of 85% carbon, 5% volatile
matter, and
-4-
CA 02568955 2006-11-24
heating value of 12,750 Btu per pound. Sub-bituminous and bituminous coals are
intermediate
between these values. Without being restricted to a theory, it is believed
that some portion of the
volatile matter in the coal dissolves or is otherwise taken up in the aqueous
solution and
furthermore may be oxidized by the hydrogen peroxide solution. Therefore, it
is believed that the
higher proportion of volatile matter in the coal, the better results will be
achieved.
Preferably, the low-rank coal is fmely divided. In one embodiment, the coal is
pulverized
so that 100% of the material passes through a 30 mesh screen. However, one
skilled in the art
will recognize that finer or coarser particles may be used. If coarser
particles are used, it may be
necessary to increase the contact time with the hydrogen peroxide solution. -
After contacting the hydrogen peroxide solution with the low-rank coal, the
solid fraction
is separated from the liquid fraction by any well known technique such as
filtration or decanting.
,The liquid fraction comprises the first component.
The second component is additional hydrogen peroxide, which may be an aqueous
solution of hydrogen peroxide. The first component and the second component
may be mixed to
form a surfactant, in a ratio of about 1:1 to about 1:10. In one embodiment,
the ratio of first to
second component in the surfactant is about 1:4.
The surfactant may then be diluted with water to create a surfactant solution,
which may
be less than about 2% surfactant in one embodiment.
While the first component is a known surfactant, as described in Applicant's
co-owned
U.S. Patent No. 7,090,768, we have found that it contains little or no
peroxide. It is believed that
the step of contacting the peroxide with coal causes decomposition of the
peroxide, while
solubilizing volatile components in the coal.
The addition of peroxide as a second component surprisingly improves the
performance
-5-
CA 02568955 2006-11-24
of the surfactant in the recovery of bitumen from tar sands. Peroxide is well
known for its
release of oxygen gas after decomposition in aqueous media. Without being
bound by a theory,
it is believed components of bitumen or oil sands catalyze or cause peroxide
decomposition. The
formation of oxygen bubbles in-situ may enhance bitumen-bubble attachment,
thereby assisting
in bitumen recovery.
The dissolved organic compounds are believed to lower interfacial tensions and
to
increase interfacial charge. Without being restricted to a theory, it is
possible that the organic
_. _- ----- -_ .-----...----- ----------------------~._.__..__.---__. .. ------
---------._._... _ .._...---- --.__----- -- -._ _.. .. _ _ . _..
compounds may stabilize the peroxide added as the second component.
The surfactant of the present invention may be used to clean hydrocarbon
contaminated
solids or particulate matter such as sand, silts or clay material. The
contaminated material may
be washed with the surfactant at an elevated temperature, preferably in the
range of about 40 C
to about 80 C. Agitation is not required and only slight agitation is
preferred. The simple action
of transferring the solid/surfactant slurry mixture down a washing trough may
provide sufficient
agitation. As will be apparent to one skilled in the art, higher temperatures
and longer dwell
times may improve the effectiveness of the surfactant. Higher surfactant to
solid ratios may also
be utilized for heavily contaminated materials or materials where the
hydrocarbons are tightly
bound to the solid material.
The surfactant may be used at a concentration of less than 5% by volume of the
solids/liquids slurry. In one embodirnent, concentrations of less than about
2% and even less
than 1% may be used. The inventors have found that concentrations as low as
less than 0.005%
may still be effective.
In one embodiment, the surfactant of the present invention may be used to
recover
bitumen from tar sands. In general terms, the method may comprise a bitumen
extraction process
which reuses water. A schematic representation of the process is shown in
Figure 1.
-6-
CA 02568955 2006-11-24
Generally, the first step in the extraction process is to form an oil sands
slurry by mixing
oil sands with fresh water. In one embodiment, the ratio of oil sands to water
is approximately
1:1 by weight. The slurry is then diluted with recycled process water, which
is obtained from a
later stage, as described below. In one embodiment, the recycled water ratio
to fresh water may
be about 9:1. The mixture is then added to a dilute surfactant solution, which
may be less than
about 2% surfactant, preferably with some mild agitation in an extraction
vessel. The
temperature may be between about 40 C and 80 C.
Bitumen which is released and floats to the top may then be collected from the
surface of
the agitation vessel, while solids will settle to the bottom and removed. The
liquid fraction,
which still contains suspended solids, may then be sent to a clarifying
vessel, where solid/liquid
separation may be achieved by filtration, centrifugal action or other known
methods. The liquid
portion may be used as process water and recycled to the first step in the
process, to dilute the
initial oil sands slurry. Preferably, the recycled water is heated to the
desired temperature for the
operation as it is being returned to the process.
EXAMPLES
The examples below are carried out using standard techniques, which are well
known and
routine to those skilled in the art, except where otherwise described in
detail. These examples
are intended to be illustrative, but not limiting, of the invention.
Example 1- Preparation of the Surfactant
3 volumes of 396 hydrogen peroxide was well mixed with 1 volume of lignite
particles
which were screened with a 30 mesh screen. The mixture was allowed to stand
for 24 hours at
20 C. The liquid.fraction was decanted and found to contain about 10% total
suspended solids
by weight, which may be seen in the microscopic image shown as Figure 2. The
total solids in
-7-
CA 02568955 2006-11-24
the first component was found to be about 18.3% by evaporating the first
component entirely.
The liquid fraction was found to contain less than 0.01% peroxide.
The liquid fraction was mixed with hydrogen peroxide in a ratio of 1:4 to
produce the
surfactant. As seen in Figure 3, very little suspended solids may be seen in
the surfactant,
indicating that the addition of hydrogen peroxide has caused the suspended
solids in the first
component to dissolve. The surfactant had a pH of 2.60, indicating that acidic
components of the
lignite had dissolved.
Example 2 - Batch Extraction using Syncrude BEU and Low Consistency
Hydrotransport
Both Syncrude Batch Unit Extraction (BEU) and Low Consistency Hydrotransport
loop
were used, with the extraction temperature controlled at 55 C. The performance
of the surfactant
was compared with conventionally used caustic process.
For these tests, six different types of oil sands samples were obtained. The
samples were
homogenized and the bitumen, solids and water content were determined. The
analyses for these
samples are shown in Table 1.
.g.
CA 02568955 2006-11-24
Table 1 Composition of Oil Sands Samples
Bitumen Solids Water
Sample ID
(wt.%) (wt.%) (wt.%)
Ore 1 14.65 84.56 0.79
Ore 2 7.99 86.18 5.75
Ore 3 12:55 ._84.89- -1-:94
Ore 4 8.87 87.65 3.43
Ore 5 15.24 83.07 1.59
Ore 6 10.23 83.99 5.45
A preliminary set of experiments were conducted using the Syncrude BEU,
conducted as
follows:
1. Remove homogenized oil sand from freezer and allow to thaw and reach room
temperature
2. Set heating bath to 55 C (or desired temperature) and circulate through BEU
heating
jacket
3. Prepare 41 mixture of 85% toluene / 15% isopropyl alcohol (IPA) (Toluene /
IPA mix)
4. Heat approximately 2000 ml Edmonton tap water to -58 C
5. Transfer 110 ml-heated water to the BEU unit
6. Weight 500 gm of oil sand to the nearest 0.1g and add to water in BEU
7. Turn motor on to 600 rpm, raising and lowering motor and impeller assembly
to break
any lumps if necessary, leaving the impellor at the set position (20mm from
the bottom of
pot)
8. Turn on air to 420 ml/min
9. Start timer for 10 minutes
10. When complete, turn off air and flood the mixture with 800 ml of heated
water
11. Mix for 10 minutes at 600rpm - no air.
12. When complete, skim off primary froth into a pre-weighed bottle using a
flat edged
spatula, cleaning the spatula and BEU surface with a pre-weighed tissue, which
is placed
in froth bottle and weighed. Submit froth sample for Dean Stark Analyses
(include tissue
-9-
CA 02568955 2006-11-24
weight to be removed from solids weight).
13. Mix the remaining material for 5 minutes at 780 rpm with air addition of
234 ml/min
14. When complete, skim off secondary froth in the same manner as the primary
froth and
submit sample. for Dean Stark analysis.
15. Place a pre-weighed 2-liter jar under BEU and turn impeller on. Take out
bottom plug of
BEU, turn impeller off and allow mixture to drain into jar (occasionally
starting and
stopping the impeller during this procedure allows the solids to mix better
and flow out).
Raise impeller and scrape as much sample as possible into the jar. Remove jar
and retain
for analyses if required.
16. Place a pre weighed 250 ml jar under the BEU.
17. Lower the impeller and slowly stir.
18._While washing with toluene/IPA mix siowly raisethe impellorto
just_below_the_top of..__ .
BEU and stop motor.
19. Raise the motor and impeller.
20. Wash pot and impeller with toluene/IPA mix, collecting residuals in jar.
Wipe with a pre
weighted tissue and place in jar. Submit toluene wash for analysis (bitumen
weight to be
combined with primary froth weight).
21. Put bottom plug back in place
22. Turn off air and heating bath.
Results were calculated as follows:
Primary Recovery %: ((Wt. of bitumen in primary froth + Wt. of bitumen in
toluene wash) /
(Wt. of oil sand used * % bitumen in oil sand * 0.01)) * 100
Secondary Recovery %: ((Wt. of bitumen in secondary froth * 100) / Wt. of oil
sand used * %
Bitumen in oil sand * 0.01)) * 100
Total Bitumen Recovery %: Primary Recovery + Secondary Recovery
Scavenging Efficiency: ((Secondary Recovery * 100) /(100 - Primary Recovery)
Primary Froth Quality: % Bitumen in Primary Froth
Secondary Froth Quality: % Bitumen in Secondary Froth
Total Froth Quality: (Wt. of bitumen in Primary Froth + Wt. of bitumen in
Secondary Froth) *
100 / (Wt. of Primary Froth + Wt. of Secondary Froth)
Froth Quality can also be calculated for % Solids and % Water
CA 02568955 2006-11-24
The oil sand extraction test loop is used to extract bitumen froth from oil
sand to
determine extractability based on ore quality and variable test conditions. A
simulation of a
slurry transport loop was conducted as follows:
a) 'Iurn on heating bath (1/0 button) and set to run temperature
b) Start heating -6 liters of process water on a hot plate to run temperature
c) Fill system with heated process water
d) Turn on pump
e) With separation vessel base baffle open, note time, and slowly add weighed
oil sand to
system
.10- .f).---S-tartair-addition-(if required)~
g) Skim froth from top of separation tank into preweighed jars at set times
until completion of
run
h) Stop air addition
The water used in these experiments was Edmonton tap water. Extractions were
conducted in water, with increasing concentrations of the surfactant(expressed
as wt. % in water)
or caustic, which was added until a pH at the flood stage reached a value of
8.5. The surfactant
had the first and second components combined in a 4:1 ratio. The results of
these experiments are
listed in Figures 4 to 8.
Changes to primary and total recovery are often used to evaluate the effect of
chemical
addition on bitumen extraction. For Ore 2 (Figure 4), a 90% primary recovery
was obtained in
the absence of chemical aids, suggesting that the ore can be easily processed.
Adding chemicals
did not show any benefit to improve the recovery. For the ore samples of Ore 5
and 6 (Figures 7
and 8), both primary and total recoveries approached 100%, no matter whether
the chemical aids
were added or not. The results suggest that for these three types of ores,
addition of any process
aid would have little benefit.
The use of the surfactant improved bitumen recovery for Ore 3 and 4 (Figures 5
and 6).
For Ore 3, the primary bitumen recovery increased from 58%, without chemical
aids, to 92%
with the addition of 1.0% surfactant. In this case, the performance was even
better than adding
caustic (85% recovery). For Ore 4, the primary bitumen recovery increased from
46%, without
surfactant, to 67% with the addition of 1.0% surfactant. For this specific
ore, adding caustic did
-11-
CA 02568955 2006-11-24
not boost the primary recovery, but increased the total bitumen recovery to
about 85% by
increasing the secondary recovery. The low bitumen recovery for these two ores
without
chemical aids was related to their ore characteristics, which was described as
having 'high fines
and mud content'. The results suggested that for all these ore samples tested,
Ores 3 and 4 would
be difficult to process and would require the use of a process aid.
To aid in further quantification of the effect of the surfactant, Ores 3 and 4
were tested in
the lab extraction loop system.
The advantage of using this laboratory apparatus is the kinetic information
that is
obtained on the recovery of the bitumen. The extraction loop has an additional
advantage of
simulating the oil sands slurry conditioning in hydrotransport pipelines.
To evaluate and predict the effect of chemical additives on bitumen extraction
performance, a first order kinetic model shown below was used to fit the
experimental data:
R=Rõ*(1-e ")
where R and Rõ are bitumen flotation recovery at time t and time infinity ( Rõ
<_ 100%)
and k is a flotation rate constant (min'). The larger the rate constant k, the
faster the bitumen
flotation, and the higher achievable bitumen recovery at a given flotation
time. Flotation rate
constant is a valuable parameter for the process diagnosis, development and
scale-up. For
example, if the bitumen extraction process is targeted and designed at 90%
recovery, and the
bitumen flotation rate constant for a given ore with chemical additives is
known, then the
required retention time of the ores in the process, and the size of the
separation tank can be
determined logically. Such exercise could contribute to enormous savings in
reducing the
operating and capital costs.
-12-
CA 02568955 2006-11-24
Figures 9 and 10 show the bitumen recovery, for ores 3 and 4, respectively, as
a function
of time for different chemical additive conditions. For ore 4, the use of the
surfactant resulted in
an increase in overall recovery from a value of 50% with water or caustic to
70%. For both ores,
however, a significant increase in bitumen recovery rate with time was
observed with the
addition of 0.5% surfactant compared to either water or caustic. While
virtually no changes in
bitumen flotation rate constant were observed when adding caustic, the
flotation rate constant
almost tripled with the addition of 0.5% surfactant, as compared with the case
without chemical
addition.
The good fit of the experimental results with the model prediction suggested
that the
increased bitumen flotation kinetics due to the surfactant could be either due
to the enhanced
bitumen-bubble attachment or the increased total amount of bubbles in the
system. The loop tests
demonstrated again that addition of the surfactant was beneficial for
recovering bitumen from
poor processing ores, and the added chemicals performed better than caustic in
increasing
bitumen recovery.
Example 3- Pilot Plant
. In a pilot plant having a flowsheet schematically represented in Figure 1,
extraction
followed three steps: oil sand was slurried at a 1:1 ratio in two sequential
vessels, followed by a
separation vessel, and a water recovery loop. The first runs were conducted to
commission the
introduction of oil sand into this system, and to determine the optimum mixing
time for the slurry
preparation. Water used in these runs was Medicine Hat city water. The
characteristics of the oil
sand used are listed in Table 3.
Table 3: Oil sand used in Commissioning Pilot Runs
% Bitumen 8.1
% Water 24.4
% Solids 68.2
-13-
CA 02568955 2006-11-24
Figure 11 shows the effect of mixing time in the first vessels on bitumen
extraction. As
can be seen, consistently higher bitumen recoveries were obtained with the
addition of the TRL
process aid, confirming lab test results. It can also be noted that with the
addition of process aid,
bitumen recovery did not change with mixing time, but an increase in bitumen
recovery was
observed with increasing mixing time in the absence of process aid. In
subsequent experiments,
a 15 minute mixing time was adopted.
Another significant finding is that the bitumen froth quality (determined as
the
bitumen/solids-ratio) was-much-higher-in-the-piloting-tests--than-those-from
lab-tests.-In-the-case
of lab tests, all the tests (both BEU and loop tests) showed that bitumen to
solids ratio in the froth
was less than 2. However, for the piloting tests as shown in Figure 12,
bitumen to solids ratio in
the froth was much greater than 4. In the case of no process aid addition, the
ratio was even
greater than 9 to 11. It should be noted here that for commercial operation
the bitumen to solids
ratio in the froth is around 4-6. Since most solids that report to the froth
are carried over by the
water film with rising air bubbles, or by attachment to the bubbles, the low
solids in the froth
could be attributed to a low amount of entrained air (no air added) used in
the piloting tests. This
observation is in agreement with the first findings of Dr. Karl Clark (founder
of the hot water
extraction process) that aeration should be controlled in the narrow ranges to
have a good froth
quality. In addition, the strong mechanical agitation and hydrodynamic
conditions used in lab
tests could also contribute to more solids carried over to the froth.
Example 4- Water Analysis
As part of the evaluation of the water recycle system, water samples were
taken and analysed for
changes in suspended solids, pH and several ions. These results are also
described below. In the
runs that were conducted in this phase of piloting, very few changes in water
quality were
observed. It was suspected that the very large water to oil sand ratio in the
extraction/water
clarification system (approximately 50:1) was responsible.
-14-
CA 02568955 2006-11-24
Seven different samples were taken around the process. The sampling protocol
is listed in Table
4. The location of where the specified sample was taken is illustrated in
Figure 1.
Table 4: Sampling points and sampling time for analysis of water re-cycled in
the bitumen
separation process.
Sample Number Process Temnerature
CC)
Oil Oil Clarified
Time Sands Sands Tailings Middlings Bitumen Sand Extraction Clarifier
Water- - -- - -
(min) Ore Slurry (TLl) (MD1) (BITl) (SDlj Vessel Vessel
(OS1) (SLl (CLWI)
0 0 0 0 0 52 54
1 1 1 1 51 54
13 1
2 2 2 2 51 53
23 2
3 3 3 3 50 54
40 4 4 4 4 51 53
50 5 5 5 0 52 54
5
The bitumen recovery for this process was determined by doing a material
balance around the
Extraction Vessel. The data in this example was for Run No. 10:
1) Known feed rate of oil sand to the vessel (181.44 kg/br).
2) Known composition of oil sand (8.34% bitumen, 85.05% solids, 6.60% water).
10 3) Known fresh water addition to oil sand feed (218 kg/hr).
4) Known composition of bitumen product stream from the Extraction Vessel
(32.97%
bitumen, 16.23% solids).
5) Known composition of tailings stream from the Extraction Vessel (0.10%
bitumen,
6.71% solids).
15 6) Assume no accumulation of bitumen, water, or solids in Extraction
Vessel.
-15-
CA 02568955 2006-11-24
The following unknowns are identified as:
Xb = bitumen in the bitumen product stream (kg/hr)
Xs = solids in the bitumen product stream (kg/hr)
Xw = water in the bitumen product stream (kg/hr)
Yb = bitumen in the tailings stream (kg/hr)
Ys = solids in the tailings stream (kg/hr)
Yw = water in the tailings stream (kg/hr)
The following equations are the material balance:
X b Y b . _ = . . _ 1513 kg/hr_ B i t u m e n I n _ = B i t u m e n Out._ ..
.._
Xs + Ys =154.31 kg/hr Solids In = Solids Out
Xb / (Xb + Xs + Xw) = 32.97% Bitumen Content of Bitumen Product
Xs / (Xb + Xs + Xw) = 16.23% Solids Content of Bitumen Product
Yb / (Yb + Ys + Yw) = 0.10% Bitumen Content of Tailings Stream
Ys / (Yb +Ys +Yw) = 6.71% Solids Content of Tailings Stream
The solution of the six unknowns and six equations gives:
Xb = 12.93 kg/hr
Xs = 6.36 kg/hr
Xw =19.91 kg/hr
Yb = 2.20 kg/hr
Ys =147.95 kg/hr
Yw = 2054.73 kg/hr
Bitumen recovery = 12.93 / 15.13 = 85.4%
During the commission runs, sample of the recycle water were taken and
subjected to
arialysis in order to evaluate the change in water quality with time. Figures
13 and 14 shows the
conductivity (a measure of the soluble ion content) and the ion analysed for
water recovered from
the 'middlings' sample. The ion analysis is presented as the concentration in
the sample,
normalized by the concentration in original water (see Table 5 for original
water analysis). For
the most part, there was very little change in the quality of the water.
Although the sodium
content did increase by a factor of 8, the absolute concentration (16 ppm) was
relatively small.
-16-
CA 02568955 2006-11-24
Table 5: Ion Anal,ysis of Medicine Hat City Water
Calcium , 40.2 Chloride 9.86
Magnesium 14.5 Sulfate 60.9
Sodium 1.8 Alkalinity 124.1
Potassium 1.8 Bicarbonate 148.2
pH 7.23
Example 5- Decomposition Egperiments
The effect of peroxide addition on the changes in oil sands slurry properties
was
examined.
Figure 15 shows the changes of slurry pH with the amount of peroxide/lignite
solution
addition. In this test, 200 gm of ore (sample Ore 4) was mixed with 383 ml of
water at 55 C. The
amount of peroxide/lignite solution added was based on the water content. As
can be seen, the
slurry pH decreased with increasing peroxide/lignite solution addition. A
possible consequence
of the reduced slurry pH in terms of oil sands processability is that the fine
solids could have a
higher probability to coagulate with bitumen, thereby contributing to
increased solids content in
the bitumen froth.
The decomposition of hydrogen peroxide in the presence of oil sand slurry was
also
evaluated. The test conditions were set to simulate conditioning (1:1 oil
sand:water and flotation
(1:2 oil sand:water). Samples were removed from the slurry and the hydrogen
peroxide
concentration determined by Raman spectroscopy. The results in Figures 16 and
17 show that
more than 90% peroxide was decomposed within 10 min at the conditioning stage.
The
decomposed hydrogen peroxide could be converted to the generation of oxygen
gas, forming
oxygen bubbles in the oil sands slurry. Without being restricted to a theory,
it is believed that this
contributes to the enhanced bitumen recovery by adding the two-part surfactant
of the present
invention.
-17-
CA 02568955 2006-11-24
It can also be noted that the peroxide decomposition was faster during the
conditioning
stage than in the flotation stage. One of the possible reasons could be due to
much higher solids
to water ratio during conditioning stage, thereby contributing to a stronger
catalytic effect of
solids on the peroxide decomposition.
-18-
