Effect of operating temperature on water-based oil sands processing.
Long, Jun ; Drelich, Jaroslaw ; Xu, Zhenghe 等
INTRODUCTION
Oil sands are unconsolidated sand deposits impregnated with
viscous, high molar mass petroleum, normally referred to as bitumen. The
largest oil sand deposits in the world are located in the northern areas
of Alberta, Canada, containing about 1.7 to 2.5 trillion barrels of
bitumen (Masliyah et al., 2004). With the depletion of conventional
crude oils and the continuously increasing demand on petroleum,
recovering bitumen from Alberta's oil sands becomes increasingly
important to Canada's energy supply. In recent years, the annual
bitumen production from Alberta's oil sands has been growing
steadily. In 2004, the total bitumen production was about 1.1 million
barrels per day (399 million barrels per year), representing an increase
of 14% over year 2003. In 2005, the production was close to 1.3 million
barrels per day. It is projected that the total bitumen production will
reach 1.8, 2.6 and 4 million barrels per day by 2010, 2014 and 2020,
respectively (CAPP, 2006).
To recover bitumen from the oil sands, both surface mining and in
situ technologies are currently used. For the oil sand deposits at a
depth of less than 75 m, surface mining is economically feasible.
Surface mining operation comprises of three integrated operations: an
open pit mine, an extraction plant and an upgrading complex to upgrade
the extracted bitumen to a light synthetic crude (Morgan, 2001). In the
extraction plant, water-based processes based on the pioneering Clark
Hot Water Process (Clark and Pasternack, 1932) are widely used to
extract bitumen from mined oil sand ores. Up to the early 1990s,
water-based bitumen extraction processes were typically operated at
70-80[degrees]C with caustic addition. At such high temperatures, the
bitumen extraction processes require a considerable input of thermal
energy. While operating integrated extraction and upgrading operations
with the face mine being close to the available thermal energy provided
by the upgraders, extraction operation at a relatively high temperature,
e.g. 55[degrees]C, is feasible. In this scenario, natural gas would not
be needed to heat the water that is used in the extraction process. Even
with integrated extraction and upgrading operations with the mine face
being at a long distance from the thermal energy sources, natural gas or
an alternative fuel is required to supply thermal energy to heat the
extraction water. Certainly, with non-integrated operation in the
absence of upgrading facilities, it becomes essential to operate bitumen
extraction at a temperature as low as possible without sacrificing
bitumen recovery, bitumen froth quality and operation reliability.
Tremendous efforts (Masliyah et al., 2004) have been made to lower
the processing temperature. In recent years, several industrial
extraction processes have been successfully operated at about
40-55[degrees]C. These processes are referred to as warm water
processes. In 2000, a low energy extraction (LEE) process (known as cold
water process) was designed and initially operated at a temperature of
about 25[degrees]C at the Aurora plant of Syncrude Canada Ltd. However,
the operating temperature of this LEE process was increased to
35-40[degrees]C in 2002 to ensure operation reliability and high bitumen
recovery.
With the decrease in the operating temperature, the required input
of thermal energy for bitumen extraction has been significantly reduced.
For example, for processing ~180 M tonnes of oil sands per year, the
original Clark Hot Water process operated at 80[degrees]C would require
about ~53 PJ (53 x [10.sup.15] J) thermal energy (~293 MJ per tonne of
oil sands) (Cymerman et al., 2006). If this amount of thermal energy
were to be derived from burning natural gas, it would cost $369 M/year
at $7/GJ. With the introduction of the hydrotransport technology
(Cymerman et al., 1993), the oil sand slurry temperature was reduced
from 80 to 50[degrees]C. Such a reduction in slurry temperature would
decrease the unit heat requirement to ~183 MJ/t. Using the low energy
extraction process at 34[degrees]C, the thermal energy requirement could
be further reduced to ~96 MJ/t (Cymerman et al., 2006).
In addition to the benefit in lowering thermal energy consumption,
decreasing operation temperatures also significantly reduces green house
gas emission. For example, processing oil sands at 34[degrees]C, rather
than at 50[degrees]C, would reduce green house gas emission by 47%
(Cymerman et al., 2006). Therefore, from the perspectives of both energy
conservation and environment protection, it is always desirable to
process oil sands at a lower temperature. However, investigations have
shown that processing oil sands at a lower temperature often results in
a significant decrease in bitumen recovery and operation reliability
(Hupka et al., 1983; Long et al., 2005).
To develop bitumen extraction processes that operate at lower
temperatures without sacrificing bitumen recovery and reliability, one
must have a comprehensive understanding of the role of temperature in
bitumen recovery and its effect on the physicochemical properties of oil
sand constituents. In this communication, we briefly review the current
state of knowledge about the role of operating temperature in oil sands
processing. In the next section, the effect of processing temperature on
bitumen recovery is discussed. The third section reviews the effect of
temperature on the physicochemical properties of oil sand components,
including the viscosity, density and surface tension of bitumen,
bitumen-water interfacial tension and the surface potentials of bitumen
and solids. In the fourth section, the dependence of the interactions
between various components in an oil sand slurry, including bitumen, air
bubbles and solids, on temperature is discussed. In the fifth section,
the role of chemical aids in oil sands processing is recounted.
EFFECT OF PROCESSING TEMPERATURE ON BITUMEN RECOVERY
Effect of Temperature on Bitumen
Liberation from Sand Grains
In a typical water-based bitumen extraction process using the
current hydrotransport technology (Masliyah et al., 2004), oil sand
lumps are mixed with water and process aids such as sodium hydroxide to
form a slurry. The prepared slurry is introduced into conditioning
hydrotransport pipelines where the oil sand lumps are sheared and lump
size is reduced. Within the hydrotransport pipelines, bitumen is
released or "liberated" from the sand grains, and the
liberated bitumen is aerated by attaching to air bubbles generated from
entrapped or introduced air. The aerated bitumen is then separated and
recovered as bitumen froth by flotation in gravity separation vessels.
Such a process includes two essential micro-subprocesses: bitumen
"liberation" and "aeration." These two
micro-subprocesses to a large extend determine bitumen recovery.
"Liberation" is the recession of bitumen from sand grain
surface with subsequent detachment. It is a prerequisite step in the
bitumen recovery process. "Aeration" is a process in which the
liberated bitumen droplets attach to air bubbles to achieve effective
flotation.
To evaluate the degree of bitumen liberation from oil sands slurry,
an on-line image analysis technique was used (Luthra, 2001; Wallwork,
2003). In this technique, a high-speed CCD camera was used to monitor
the darkness of the oil sand slurry as the bitumen was displaced from
sand grains. The dark areas were taken as a measure of bitumen still
attached to sand grains, i.e., un-liberated bitumen from sand grains.
The disappearance of dark areas was regarded as a result of bitumen
liberation from sand grains. Figure 1a shows the degree of bitumen
liberation from sand grains as a function of the slurry conditioning
time at 35 and 50[degrees]C. The results from a good processing ore of a
low fines content are compared with those from a poor processing ore of
a high fines content. Although the degree of liberations after a long
conditioning time of 60 min for both ores at the two different
temperatures is nearly identical, the rate of liberation (k) is
significantly affected by the ore type and temperature. The bitumen
liberated at a much faster rate from the good processing ore (k = 68.8
[min.sup.-1] at 50[degrees]C and k = 10.3 [min.sup.-1] at 35[degrees]C)
than from the poor processing ore (k = 12.4 [min.sup.-1] at 50[degrees]C
and k = ~0.7 [min.sup.-1] at 35[degrees]C). The bitumen liberation rate
increases with increasing temperature for both ores (Figure 1a).
To effectively liberate bitumen from sand grains, it is essential
for the bitumen to roll-up on and to release from the surface of the
sand grains (Basu et al., 1996; Drelich, 2007). Laboratory studies on
bitumen liberation were conducted for model systems of glass slides
coated with bitumen by Masliyah et al. (2004). Figures 1b shows the
results of bitumen recession from a glass slide at different
temperatures; the bitumen recession is defined here as the percentage
area of the glass slide from which the bitumen retreated. At higher
temperatures, e.g. 37[degrees]C and 44[degrees]C, the bitumen recession
was fast and somewhat independent of the temperature. However, the
recession rate became much lower at 20[degrees]C.
Basu et al. (1996) measured the contact angle of bitumen droplets
through the bitumen phase (see inset of Figure 2a) on a silica glass
surface in aqueous solutions. The effect of temperature on the dynamic
contact angle ([[theta].sub.d]) of bitumen in a solution at pH 11 is
shown in Figure 2a. The contact angle increases with time until it
reaches its "equilibrium" value ([[theta].sub.e]). The rate of
change of the dynamic contact angle of bitumen is much higher at
80[degrees]C than at 40[degrees]C indicating that the "roll-up
velocity" of bitumen on the sand grains is accelerated at a higher
temperature.
The variation of the "equilibrium" contact angle with
temperature is presented in Figure 2b. For a given pH, the equilibrium
contact angle increases only slightly with temperature. However, for a
given temperature, [[theta].sub.e] is very sensitive to changes in pH.
[FIGURE 1 OMITTED]
In summary, the results shown in both Figures 1 and 2 indicate that
a higher temperature is required to accelerate and enhance bitumen
liberation.
Effect of Processing Temperature on Overall Bitumen Recovery
The effect of temperature on bitumen recovery has been widely
investigated with various types of oil sand ores (Bichard, 1987; Dai and
Chung, 1995, 1996; Ding, 2006; Schramm et al., 2003; Stasiuk et al.,
2004). It has been found that bitumen recovery was not significantly
affected within a temperature range of 50-95[degrees]C (Bichard, 1987;
Schramm et al., 2003; Stasiuk et al., 2004). However, bitumen recovery
decreased at temperatures lower than 50[degrees]C. A sharp decrease in
bitumen recovery was observed particularly at temperatures lower than
35[degrees]C.
The pioneering early study by Bichard (1987) showed that bitumen
recovery of a poor processing ore (called "Area D, Hole 11, tar
sand" in the reference) drops significantly from about 90% at
37.8[degrees]C (100[degrees]F) to 40% at 26.7[degrees]C (80[degrees]F).
Schramm et al. (2003) observed an order of magnitude reduction in
primary bitumen recovery for an average-grade ore, from 88% at
50[degrees]C to 8% at 25[degrees]C. Ding (2006) reported bitumen
recovery of 85% to 90% at 35[degrees]C for a good processing ore even
with the addition of illite clay, calcium or magnesium ions. However,
the recovery dropped to 70% at 25[degrees]C, and to as low as 30% when
illite, calcium or magnesium ions were added together to the oil sand
slurry.
[FIGURE 2 OMITTED]
To show clearly the effect of temperature on bitumen recovery, the
results reported in the literature cited above are re-plotted in Figure
3. The dash line in this figure shows a representative trend of bitumen
recovery with temperature. When the processing temperature was higher
than 50[degrees]C, the bitumen recoveries were high (>80%) and
increasing the temperature virtually had little effect on bitumen
recovery (Bichard, 1987; Schramm et al., 2003; Zhou et al., 2004).
Decreasing the temperature resulted in a sharp decrease in bitumen
recovery from over 80% at >35[degrees]C to less than 20% at
<25[degrees]C. This finding suggests that 35[degrees]C might be a
critical temperature for bitumen recovery.
Effect of Processing Temperature on Bitumen Recovery Kinetics
Among other factors, the test results of bitumen recovery from oil
sands are dependent on the size and configuration of the extraction
units and on the bitumen extraction protocols used by different
operators in different laboratories (Majid et al., 1982; Zhou et al.,
2004). The principal techniques for laboratory testing of oil sands
processability over the years include the beaker or jar tests (Bichard,
1987), the Batch Extraction Unit (BEU) (Sanford and Seyer, 1979), the
Denver flotation cells (Kasongo et al., 2000; Sury, 1990), and the unit
of a laboratory hydrotransport slurry pipeline (Wallwork et al., 2004).
These techniques will not be discussed in detail. However, it is
important to recognize that bitumen recoveries obtained by different
test techniques and protocols could vary significantly. The bitumen
recovery rate is a more convenient way to distinguish the differences in
bitumen flotation kinetics at different temperatures.
A first-order disappearance kinetic model is widely used to
evaluate the overall bitumen recovery kinetics:
[R.sub.t] = [R.sub.[varies]][1-exp(-kt)] (1)
where [R.sub.t] and [R.sub.[varies]] are the bitumen recovery at
time t and the ultimate bitumen recovery, respectively; and k is the
bitumen recovery rate constant ([min.sup.-1]).
[FIGURE 3 OMITTED]
Figure 4 shows the effect of temperature on bitumen recovery
kinetics for the two types of oil sand ores (Zhou et al., 2004). For the
good processing ore (Figure 4a), a significant enhancement of bitumen
flotation kinetics was observed when the processing temperature was
raised from 25 to 50[degrees]C. The recovery rate constant increased
from 0.15 min-1 at 25[degrees]C to 0.98 min-1 at 50[degrees]C, although
the overall bitumen recoveries are not significantly different after 15
min. A similar effect was reported for the poor processing ore (Zhou et
al., 2004); the bitumen recovery rate constant increased from 0.084
min-1 at 25[degrees]C to 0.383 min-1 at 50[degrees]C (Figure 4b). These
results indicate that bitumen recovery rates from oil sands are much
smaller at a lower temperature than at a higher temperature.
Dependence of Froth Quality on Extraction Temperature
After bitumen is recovered from oil sands, the produced bitumen
froth is a mixture of bitumen, solids and water. To obtain clean bitumen
for downstream upgrading, the solids and water present in the bitumen
froth must be removed by a series of cleaning processes. The operation
and efficiency of these cleaning processes are dependent on the quality
of the bitumen froth feed. Bitumen froth quality is normally represented
by bitumen-to-solids (B/S) and bitumen-to-water (B/W) ratios in the
bitumen froth.
[FIGURE 4 OMITTED]
Bichard (1987) and Hupka et al. (1987) conducted a number of
bitumen recovery tests using various oil sand ores at different
temperatures and demonstrated that the quality of the bitumen froth
deteriorates at a reduced temperature. Figure 5 shows some of
Bichard's results of froth quality for experiments with a poor
processing ore. There is a clear trend in the B/S ratio over the
temperature range from 10 to ~95[degrees]C, with the B/S ratio much
smaller at operation temperatures of less than 45[degrees]C than at
>55[degrees]C. A similar trend was reported for the B/W ratio (Figure
5), albeit not as evident as that of the B/S ratio.
EFFECT OF TEMPERATURE ON PHYSIOCHEMICAL PROPERTIES OF OIL SAND
COMPONENTS
As discussed in the previous section, processing temperature is
critical to bitumen liberation, bitumen recovery and bitumen froth
quality. There must be at least one key process variable that undergoes
a substantial change when the processing temperature is reduced to
explain such results as those in Figure 3. In this section, we discuss
how the temperature affects the interfacial and physiochemical
properties of oil sand components.
[FIGURE 5 OMITTED]
Bitumen Viscosity
Bitumen viscosity has been widely considered to be the main
contributor to the dramatic reduction in bitumen recovery with
decreasing temperature (Hupka et al., 1983; 1987; Schramm et al., 2003;
Stasiuk et al., 2004). Hupka et al. (1983) investigated the effect of
bitumen viscosity on bitumen recovery using a number of oil sand ores
from several U.S. and Canadian deposits. In their tests, kerosene was
used to adjust the bitumen viscosity. They found that in order to
achieve a satisfactory separation of bitumen from the oil sands, the
bitumen viscosity must be reduced below 1.5 Pa.s regardless of the oil
sands type, grade, or origin. Figure 6 shows the relation between
bitumen recovery and bitumen viscosity. The open triangles in this
figure are the test results of Hupka et al. (1983) obtained using a
number of different ores, and the short-dash line represents a general
trend of bitumen recovery as a function of bitumen viscosity. A bitumen
viscosity below 1.5 Pa.s results in bitumen recovery above 90%. In fact,
as long as the bitumen viscosity is below 3 Pa.s, bitumen recovery in
most cases is still higher than 80%. When the bitumen viscosity is
higher that 3 Pa.s, bitumen recovery sharply decreases with increasing
bitumen viscosity.
The bitumen viscosity threshold value of Hupka et al. is consistent
with a value of 3 Pa.s suggested by Schramm et al. (2003). Bitumen
viscosity is generally known to increase sharply with decreasing
temperature, although the value of bitumen viscosity is more or less
dependent on the origin of the bitumen and the bitumen extraction method
(Helper and Smith, 1994; Seyer and Gyte, 1989). A detailed discussion on
bitumen viscosity was given by Seyer and Gyte (1989). Helper and Smith
(1994) proposed the following equation that correlates bitumen viscosity
([[micro].sub.B]) with temperature (T) for 300 < T < 375 K,
[[micro].sub.B] = Aexp(10100/T) (2)
where T is in degrees Kelvin and [[micro].sub.B] is in mPa.s. The
constant A can vary from 1 x [10.sup.-10] to 7 x [10.sup.-10] depending
on the bitumen chemical composition. On average, it is approximately 4 x
[10.sup.-10] for the bitumens extracted from Athabasca oil sands.
[FIGURE 6 OMITTED]
Figure 7a shows a "standard" generic
viscosity-temperature relation for Athabasca bitumen over a temperature
range of 0 to 100[degrees]C (Seyer and Gyte, 1989). From this curve, one
finds that to reach the threshold bitumen viscosity of 3 Pa.s, the
temperature must be as high as about 60[degrees]C (or even about
70[degrees]C if the threshold value is set at 1.5 Pa.s). However, many
test results have indicated that a higher bitumen recovery is normally
obtainable at an extraction temperature of 50[degrees]C or higher (Zhou
et al., 2004). The mean viscosity of Athabasca bitumen at 50[degrees]C
is about 7 Pa.s. This value is higher than the threshold values of 1.5-3
Pa.s proposed for efficient processing of oil sands. Future research
should clarify whether this discrepancy can simply be explained by
different equipment and procedures used in bitumen recovery tests by
different research groups or if there are some other underlying factors.
One of the other possibilities is the uncertainty with the precision of
bitumen viscosity measurement. A small amount of solvent left in the
bitumen can have a profound effect on "bitumen" viscosity.
Bitumen viscosity influences both liberation and aeration of
bitumen. Without reducing bitumen viscosity through either a raise of
temperature or addition of a diluent, the bitumen on sand grains may
remain intact in water for a long time if viscous forces exceed the
capillary forces (Drelich, 2007). This, however, is an extreme case,
which could only result with a poor, if any, separation of bitumen from
the sand grains. More commonly observed effects relate to kinetics of:
(1) bitumen recession on the grain surface and therefore, the kinetics
of bitumen liberation; and (2) bitumen spreading over a gas bubble
surface during bitumen aeration. A recent detailed analysis of wetting
phenomena in oil sand systems (Drelich, 2007) provides more insights
into the mechanisms of bitumen film de-wetting and spreading, and the
role of bitumen viscosity in these processes.
[FIGURE 7 OMITTED]
Density of Bitumen
In a water-based bitumen extraction process, air must be introduced
into the oil sands slurry so that the bitumen can float to the top of
the slurry and be collected as a bitumen froth product. This is because
bitumen and water have nearly the same density. Figure 7b shows the
densities of water and bitumen as a function of temperature. When the
temperature is increased, the densities of both water and bitumen
slightly decrease. The density difference between bitumen and water, as
shown by the solid line at the bottom of Figure 7b, however, is very
small (often less than 10 kg/[m.sup.3]) over the whole temperature range
of 0-100[degrees]C and shows little change with temperature. Clearly,
the effect of temperature on the density difference is negligible.
Bitumen Surface Tension and Bitumen-Water Interfacial Tension
The two steps in which bitumen surface tension and/or bitumen/
water interfacial tension play a role include: (1) bitumen roll-up on
the surface of mineral (quartz) surface and its release from the mineral
matrix to the process water during oil sand slurry digestion; and (2)
bitumen spreading at the air bubble surface after bitumen droplet
collision with and attachment to the bubbles during flotation separation
(Drelich et al., 1994; Drelich and Miller, 1994). Both chemical
composition and temperature affect the surface and interfacial tension
of bitumen in water. A survey of the literature indicates that very
little attention has been paid to the study of the effect of temperature
on the surface and interfacial tension of bitumen. Isaacs and Smolek
(1983) reported the surface tension of Athabasca bitumen to be 29.6 mN/m
at 64[degrees]C and it decreased to 25 mN/m at 112[degrees]C. Potoczny
et al. (1984) measured the surface tension of several Alberta bitumen
samples from different sites using the Wilhelmy plate technique. The
surface tension of these samples varied from about 23 mN/m to 32 mN/m at
40[degrees]C, depending on the bitumen sample, the solvent type used for
bitumen extraction from oil sands, and the residual solvent content of
the bitumen.
[FIGURE 8 OMITTED]
All results reported in the literature for bitumen indicate that
the surface tension of bitumen decreases linearly with an increase in
temperature. Several examples of the effect of temperature on surface
tension of bitumen are shown in Figure 8. The results can be described
by the linear dependence using Equation (3):
[MATHEMATICAL EXPRESSION NOT REPRODUCIBLE IN ASCII] (3)
The value of [d[gamma].sub.B]/dT represents the temperature
coefficient for the surface tension. Its negative value (Table 1) is
consistent with that reported for most liquids (Adamson, 1990; Jasper
and Kring, 1955) and indicates that as the temperature increases there
is a gain in the energy of the molecules located at the surface compared
to those remaining in the bulk phase.
The effect of the aqueous phase pH and electrolyte concentration on
interfacial tension of bitumen-water has been frequently studied at
ambient temperature. However, the effect of temperature has not been
studied to the same extent. Isaacs and Smolek (1983) found that the
interfacial tension between Athabasca bitumen and water is about 18 mN/m
at 23[degrees]C and 15.4 mN/m at 50[degrees]C. The maximum bubble
pressure technique was used by Pandit et al. (1995) to study the effect
of temperature on the Cerro Negro bitumen-surfactant solution
interfacial tension. Interfacial tension was found to decrease from 13.9
mN/m at 25[degrees]C to 5.3 mN/m at 90[degrees]C as the nonylphenol
ethoxylate surfactant, dissolved in deionized water at 0.5 wt.%
concentration, became less hydrophilic with increasing temperature.
The studies on the effect of temperature on the bitumen/ aqueous
phase interfacial tension were also undertaken at the University of Utah in the early 1990s, for bitumens recovered from Utah oil sands. Examples
of the results are shown in Figure 9. Similar to what was observed in
the surface tension studies, there is a linear relationship between
interfacial tension and temperature at different pHs. The temperature
coefficients of interfacial tensions (d[gamma]/dT) calculated from the
slope of the curves are shown in Figure 9 for varying pH values of the
aqueous phase.
As discussed above, both surface and interfacial tensions change
only slightly when temperature is elevated. These small changes are
expected to have only minor effects, if any, on the bitumen recovery
from oil sands in a water-based extraction process. Instead, the
reduction of bitumen-water interfacial tension during the oil sand
processing is controlled through increasing the pH of the processing
water to activate more natural surfactants that are already present in
bitumen (Schramm et al., 1984). The addition of synthetic surfactants
(Pandit et al., 1995) or other surface active chemicals such as MIBC (Li
et al., 2005a, 2005b; Schramm et al., 2003), to be discussed in the
Roles of Chemical Additives section, is another option for the control
of bitumen-water interfacial tension.
Electric Surface Potentials of Oil Sand Components
In a water-based bitumen extraction process, the formed oil sand
slurry is mainly a complex mixture of water, bitumen, sand, clay
minerals and air bubbles. The colloidal state of such a system is
controlled by the interactions between the components, which are
directly related to the electric surface potentials of these components.
Extensive studies on the surface potentials of bitumen, sand (silica),
fines and various clays by zeta potential measurement have been carried
out at ambient temperature (Liu et al., 2002, 2003, 2004a, b, 2005a, b;
Masliyah, 1994; Takamura and Chow, 1983, 1985; Takamura and Isaacs,
1989; Zhao et al., 2006). However, little attention has been paid to the
effect of temperature on the zeta potentials of these oil sand
constituents.
[FIGURE 9 OMITTED]
Dai and Chung (1995) measured the zeta potentials of silica and
bitumen in 5 mM NaCl solutions at 22 and 60[degrees]C as a function of
the solution pH. Long et al. (2005) obtained the zeta potentials of
silica and bitumen as a function of temperature in an industrial process
water (47 ppm [Ca.sup.2+], 15 ppm [Mg.sup.2+] and pH of ~8.2) by fitting
the measured interaction forces between silica and bitumen using the
DLVO theory. As shown in Figure 10, the surfaces of both silica and
bitumen are negatively charged. According to the data of Dai and Chung
(Figure 10a), the bitumen surface is more negatively charged than the
silica surface at pHs greater than ~5.
The negative charge of the bitumen surface is due to dissociation of the carboxyl and sulphonate groups of the surfactants that are
naturally present in bitumen (Takamura and Chow, 1985) while the
dissociation of surface silanol groups are responsible for the negative
charge of the silica surface (Ramachandran and Somasundaran, 1986). Both
silica and bitumen become more negatively charged with increasing
temperature (Figure 10). For the silica surface, a thermodynamic analysis (Dai and Chung, 1996; Dunstan, 1994; Ramachandran and
Somasundaran, 1986) suggests that increasing temperature favours the
formation of [H.sub.3]Si[O.sup.-.sub.4] groups, thus resulting in a more
negative surface charge.
[FIGURE 10 OMITTED]
Long et al. (2005) found that the zeta potential of fines directly
taken from an oil sands tailing slurry is small (~-5-7 mV) and
doesn't change much in the process water over a temperature range
of 20-40[degrees]C.
As both silica and bitumen become more negatively charged at an
elevated temperature, the repulsion between them increases. Quantitative
results of the interaction forces between bitumen and silica/fines are
discussed in detail in the next section.
EFFECT OF TEMPERATURE ON INTERACTIONS BETWEEN BITUMEN AND
SOLIDS/BUBBLES
Interaction Forces between Bitumen and Solids
The separation of bitumen from oil sands is controlled by the
interactions between the bitumen and solids. Long et al. (2005) directly
measured the interaction forces between bitumen and solids as a function
of temperature using an atomic force microscope (AFM). To better
represent the interactions between bitumen and solids in oil sand
processing, fine particles directly chosen from an oil sand tailings slurry and model silica spheres to represent sand grains in the oil
sands were used in the force measurements. In these measurements,
process recycled water obtained from a commercial operation site (Aurora
plant of Syncrude Canada Ltd.) was used as the aqueous medium.
Figure 11 shows the effect of temperature on the long-range
interaction forces between bitumen and silica. Over the temperature
range, from the ambient temperature up to about 40[degrees]C, the
measured long-range interactions at a separation distance of less than
15 nm are monotonically repulsive. The repulsive forces decrease with
decreasing temperature, although they are still present at room
temperature (~21[degrees]C).
[FIGURE 11 OMITTED]
The inset of Figure 11 shows the adhesion forces (contact forces)
between bitumen and silica. Only at temperatures lower than about
32[degrees]C were adhesion forces detected, and the adhesion forces
increased with decreasing temperature.
Prior to the direct measurement of interaction forces, an early
study by Dai and Chung (1995) used a silica pick-up test to study
bitumen-sand interactions. The bitumen-coated Teflon plate was submerged
in a test solution containing a silica sand bed, and an
electromechanical device was used to drive the bitumen-coated plate
downward to pick up sand grains. As shown in Figure 12, the bitumen
surface coverage decreased with increasing solution pH. This is because
both bitumen and silica surfaces become more negatively charged and the
repulsion between them became stronger with increasing pH. At the same
solution pH, the surface coverage decreases with increasing temperature.
Particularly, when the solution pH is higher than 8, the surface
coverage at 60[degrees]C is zero, indicating that no silica sand grains
were picked up. This further suggests that at 60[degrees]C the
bitumen-sand long-range repulsion is strong and the bitumen-sand
adhesion is zero. However, at 22[degrees]C, there were still some sand
grains attached to the bitumen surface at a solution pH of 8 or even 10,
implying the presence of a certain strength of adhesion between bitumen
and sand. These findings are consistent with the results of direct force
measurement shown in Figure 11.
Figure 13 shows the measured long-range interactions and
short-range adhesion forces between a clay particle and a bitumen
surface in the process water as a function of temperature (Long et al.,
2005). The long-range interaction forces changed progressively from
attractive at room temperature to repulsive at about 40[degrees]C. Also,
strong adhesion forces decreased from about 1.5 mN/m at 21[degrees]C to
zero at temperatures higher than 33-35[degrees]C.
For a dynamic colloidal system such as the oil sand slurry in a
bitumen extraction system, both the long-range forces and adhesion
forces have to be considered. The adhesion force determines fine
solids' attachment to bitumen, while the long-range forces are the
key for dispersion or coagulation of solids and bitumen. A repulsive
long-range colloidal force and a zero adhesion force between bitumen and
sand grains promote easy bitumen liberation. As shown in Figure 11, the
long-range interaction force between bitumen and silica sands is always
repulsive, and the repulsive force becomes stronger with increasing
temperature. At temperatures higher than 32[degrees]C, there is no
adhesion between bitumen and silica sands (inset of Figure 11). These
results suggest that good bitumen liberation from sand grains can be
achieved at a temperature of 32[degrees]C or higher.
[FIGURE 12 OMITTED]
For the bitumen aeration process, the presence of slime coating on
the bitumen and air bubble surfaces not only reduces the bitumen
flotation rate and recovery by setting up a steric barrier retarding
bitumen drops to contact air bubbles, but also deteriorates the froth
quality by carrying fine solids to the bitumen froth product (Liu et
al., 2004b). Figure 13 shows that at temperatures lower than
32[degrees]C, an attractive long-range interaction force and an adhesion
force exist between bitumen and clay particles in recycled Aurora
process water. Such forces could induce a strong hetero-coagulation
between bitumen and fines, possibly resulting in slime coating of the
bitumen surface, preventing an intimate contact of air bubbles with the
bitumen. Therefore, the aeration efficiency and subsequent bitumen
recovery can deteriorate. In contrast, at temperatures higher than
32[degrees]C, the long-range interaction force becomes repulsive
(circles in Figure 13), and the adhesion force is extremely weak (inset
of Figure 13). Thus, the fine particles cannot strongly attach to the
bitumen surface and can be removed by the hydrodynamic forces during the
bitumen extraction process.
Air-Bitumen Attachment as a Function of Temperature
After bitumen is liberated from the sand grains, the liberated
bitumen droplets must attach to air bubbles to achieve effective
flotation. This is attributed to the well-know fact that bitumen has
almost the same density as water over the temperature range used in
bitumen extraction (Figure 7b). Since bitumen and air are both apolar phases, their attachment in a polar medium such as water is
thermodynamically favourable. However, both bitumen and air bubbles are
negatively charged in an aqueous media under natural conditions (Chow
and Takamura, 1988; Masliyah, 1994; Takamura and Chow, 1985; Yang et
al., 2001). These charges are responsible for the repulsive energetic
barrier between surfaces, and they slow down the attachment of bitumen
droplets to air bubbles.
The dynamics of the bitumen-bubble attachment process has been
studied by measuring the induction time; i.e., the time needed for an
air bubble to attach to the bitumen surface when they are in contact.
For example, Gu et al. (2003) found that the induction time for air
bubbles at the bitumen surface decreased with increasing temperature in
both deionized water and an industrial process water (Figure 14).
[FIGURE 13 OMITTED]
Another way to investigate bitumen-bubble attachment is to measure
the sliding time of a gas bubble along an inclined bitumen surface
before it attaches to the bitumen surface. Three examples of results for
oxygen bubbles on a bitumen surface are given in Figure 15 (Masliyah et
al., 2004). At a water temperature of 30[degrees]C, the oxygen bubble
did not always attach and stick to the coated bitumen surface within the
time frame of the test. However, bitumen-bubble attachment always
occurred at a temperature of 40 or 50[degrees]C, in spite of the
increased surface potential of bitumen at higher temperatures (discussed
in Electric Surface Potentials of Oil Sand Components). The time for an
attachment to occur was much shorter at 50[degrees]C than at
40[degrees]C.
[FIGURE 14 OMITTED]
[FIGURE 15 OMITTED]
ROLE OF CHEMICAL ADDITIVES
The early hot water bitumen extraction process generally required
the use of caustic to adjust the oil sand slurry pH and to promote the
generation or release of surfactants (Sanford and Seyer, 1979). To
extract bitumen from oil sands at a lower temperature, various process
aids other than (or in combination with) caustic have been used to
improve bitumen recovery (Bichard, 1987; Li et al., 2005a, b; Schramm et
al., 2003; Stasiuk et al., 2004). Examples of such aids are kerosene,
MIBC, sodium silicate and partially hydrolyzed polyacrylamide (HPAM).
Table 2 presents some results of bitumen recovery, showing the effect of
chemical aids. In this section, we briefly discuss the role of these
chemicals in bitumen extraction.
The mechanisms of improving bitumen recovery by the use of
chemicals are different. Basically, they can be divided into two major
categories: (1) bitumen dilution for lowering its viscosity using
organic solvents; and (2) controlling the colloidal state by adjusting
the interactions and adhesion between bitumen and solids using a
dispersant or a polymer flocculant. Essentially, chemical aids are
needed to alleviate the negative impact from increases in bitumen
viscosity and bitumen-mineral adhesion when processing oil sands at a
lower temperature.
Kerosene (as well as several other solvents) was used to dilute
viscous bitumen and to reduce its viscosity. As discussed earlier,
acceptable recoveries of bitumen from oil sands, >80-90%, were
recorded if the viscosity of the diluted bitumen was reduced to less
than ~3 Pa.s before oil sand digestion and flotation (Hupka et al.,
1983, 1987; Schramm et al., 2003; Stasiuk et al., 2004).
Acidified sodium silicate is a dispersant and was used as an aid to
process an oil sand ore with a high fines content by Li et al. (2005b).
The bitumen recovery was increased from 65% for the case of no process
aid addition to 97% for the case with 3660 ppm (oil sand basis) of
sodium silicate addition. Li et al. (2005b) claimed the superiority of
sodium silicate as a process aid over caustic because: (1) it
precipitates calcium and magnesium ions from the process water,
minimizing the synergistic effect of divalent cations in inducing a clay
coating on the bitumen surface and clay gelation; (2) it disperses clay
fines in the pulp; and (3) it maintains an adequate pulp slurry pH for
efficient bitumen-air bubble attachment.
[FIGURE 16 OMITTED]
The addition of MIBC together with caustic and kerosene
significantly improved bitumen recovery from 79% to 98% (Table 2). Since
MIBC addition did not change the viscosity of bitumen, to find out its
role in bitumen extraction, Long et al. (2005) measured the interaction
and adhesion forces between bitumen and solids (silica and fines) in
aqueous solutions in the presence of MIBC. Figure 16 shows the measured
long-range interaction forces and the adhesion forces (inset) between
bitumen and fine particles at room temperature. Without MIBC addition or
with MIBC addition at a low concentration, the presence of attractive
long-range interaction force and adhesion force between bitumen and
fines indicates possible heterocoagulation between bitumen and fines,
leading to slime coating and thus poor bitumen-air attachment and low
bitumen recovery. At desired MIBC additions, the long-range interactions
change progressively from attractive to repulsive, and the adhesion
force decreases substantially and eventually disappears. As a result,
little slime coating occurs, thereby achieving a higher bitumen
recovery. At a very high concentration of 5000 ppm, an adhesion force
was measured again, leading to a deteriorated bitumen recovery. This
result is consistent with the bitumen recovery results of Schramm et al.
(2003) as they found that overdose of MIBC resulted in decreased bitumen
recovery.
In a recent study, Li et al. (2005a) attempted to use HPAM as a
process aid to process a high fines content ore. They found that the
addition of HPAM in the bitumen extraction step not only improved
bitumen recovery but also enhanced the settling of fine solids in the
tailings stream. However, it led to a deterioration of the bitumen froth
quality. To understand the role of this polymer in both bitumen
extraction and tailings settling, Long et al. (2006) employed the
technique of single molecule force spectroscopy to measure the adhesion
forces of single HPAM molecules on the surfaces of various oil sand
components, such as bitumen, sand and clay, using an atomic force
microscope (AFM). The measured adhesion forces together with the zeta
potential values of these surfaces indicated that the polymer would
preferentially adsorb onto a clay surface than onto a bitumen surface.
When the polymer was used as a process aid in the extraction process,
the polymer-induced formation of large flocs of fine particles reduced
the number of individual fine particles in the oil sands slurry. As a
result, the chance for slime coating to occur was reduced. This would
benefit attachment of air bubbles to bitumen droplets and thus improve
the flotation efficiency and consequently bitumen recovery. The
formation of large floccules also increased the settling rate of fine
solids in the tailings. It is the selective adsorption of HPAM that
benefited both bitumen recovery and tailings settling when the polymer
was added directly to the bitumen extraction process at an appropriate
dosage. Because the large floccules produced were normally loose and
irregular in shape, they could be brought up to the bitumen froth by
aerated bitumen droplets and air bubbles during the flotation process,
thereby leading to a poor froth quality.
To improve the bitumen froth quality, Long et al. (2007) used a
hybrid Al(OH)3-polyacrylamide (Al-PAM) in combination with HPAM. The use
of the dual polymers at a low dosage was found to be able to achieve a
holistic improvement in bitumen recovery, froth quality and tailings
settling.
SUMMARY
In this communication, we provide an overview of the state of the
knowledge on the role of operating temperature in oil sands processing.
The relation between temperature and bitumen recovery, the effect of
temperature on the physiochemical properties of oil sand components, and
the role of chemical additives in oil sand processing are discussed. How
operating temperature affects the interactions between bitumen and
solids and between bitumen and gas bubbles is also discussed. From all
the information gathered, we conclude:
1. Temperature affects nearly all properties of oil sands among
which bitumen viscosity and bitumen-solids adhesion pose a prominent
impact on bitumen recovery. There seems to exist a critical operational
temperature of 35[degrees]C below which bitumen recovery severely
deteriorates.
2. The use of selected chemical additives can reduce bitumen
viscosity and/or the adhesion between bitumen and solids and thus
provide a possible mean to process oil sands at lower temperatures while
maintaining higher bitumen recoveries.
3. Most existing studies on the physiochemical properties of oil
sand constituents were carried out at ambient temperature.
More in-depth investigations on the effect of temperature on these
properties are needed in order to fully understand the role of
temperature in water-based oil sand processing.
ACKNOWLEDGEMENT
The financial support for this work from the NSERC Industrial
Research Chair in Oil Sands Engineering (held by JHM) is gratefully
acknowledged.
Manuscript received February 27, 2007; revised manuscript received
May 25, 2007; accepted for publication May 25, 2007.
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(1.) Department of Chemical and Materials Engineering, University
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Table 1. Surface tension for selected bitumens (Drelich, 1993; Drelich
et al., 1994; Drelich and Miller, 1994)
Bitumen Surface Tension [mN/m]
Athabasca (Canada) -31 (40[degrees]C)
29.6 (64[degrees]C)
Peace River (Canada) 26.5 [+ or -] 2.7 (40[degrees]C)
27.5 [+ or -] 2.7 (23[degrees]C)
Pelican Lake (Canada) 28.0 [+ or -] 2.6 (40[degrees]C)
29.1 [+ or -] 2.7 (23[degrees]C)
Fort McMurry (Canada) 27.5 [+ or -] 2.9 (40[degrees]C)
26.4 [+ or -] 1.3 (23[degrees]C)
Whiterocks North-West 22.1 (40[degrees]C
23.5 (21[degrees]C)
West-Central 22.6 (40[degrees]C
24.1 (21[degrees]C)
Bitumen Temperature Coefficient [mN/(m.deg)]
Athabasca (Canada) -0.19(40[degrees]C to 95[degrees]C)
-0.095 [+ or -] 0.004 (64[degrees]C to
112[degrees]C)
Peace River (Canada) -0.063 [+ or -] 0.010 (40[degrees]C to
90[degrees]C)
Pelican Lake (Canada) -0.063 [+ or -] 0.012 (40[degrees]C to
90[degrees]C)
Fort McMurry (Canada) -0.063 [+ or -] 0.010 (40[degrees]C to
90[degrees]C)
Whiterocks North-West -0.077 [+ or -] 0.002 (40[degrees]C to
77[degrees]C)
West-Central -0.082 [+ or -] 0.001 (40[degrees]C to
78[degrees]C)
Bitumen References
Athabasca (Canada) (Bowman, 1967)
(Isaacs and Smolek, 1983)
Peace River (Canada) (Potoczny et al., 1984;
Varghabutler et al., 1988)
Pelican Lake (Canada)
Fort McMurry (Canada)
Whiterocks North-West (Drelich and Miller, 1994)
West-Central
Table 2. Effect of chemical aids on bitumen recovery
Chemicals Bitumen recovery Type of oil sands
ore
NaOH (0.06% addition, 8% Average grade
oil sand basis)
NaOH (0.06%) + 79%
Kerosene (20,000 ppm)
NaOH (0.06%) + Kerosene 98%
(20,000 ppm) + MIBC (1000 ppm)
No chemical 65% Poor-processing
acidified sodium silicate 97%
(3660 ppm)
No chemical 50% Poor-processing
HPAM (20 ppm) 74%
HPAM (15 ppm)+ 86%
AI-PAM (5 ppm)
Chemicals Extraction method and temperature
NaOH (0.06% addition, batch extraction at 25[degrees]C
oil sand basis)
NaOH (0.06%) +
Kerosene (20,000 ppm)
NaOH (0.06%) + Kerosene
(20,000 ppm) + MIBC (1000 ppm)
No chemical laboratory hydrotransport
extraction system at 35[degrees]C
acidified sodium silicate
(3660 ppm)
No chemical laboratory hydrotransport
extraction system at 35[degrees]C
HPAM (20 ppm)
HPAM (15 ppm)+
AI-PAM (5 ppm)
Chemicals Reference
NaOH (0.06% addition, (Schramm et al., 2003)
oil sand basis)
NaOH (0.06%) +
Kerosene (20,000 ppm)
NaOH (0.06%) + Kerosene
(20,000 ppm) + MIBC (1000 ppm)
No chemical (Li et al., 2005b)
acidified sodium silicate
(3660 ppm)
No chemical (Long et al., 2007)
HPAM (20 ppm)
HPAM (15 ppm)+
Al-PAM (5 ppm)