Printer Friendly

Effect of operating temperature on water-based oil sands processing.


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 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.


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.


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 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.


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.


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.


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 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.


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.


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):


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.


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.


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.


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).


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.


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).


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.




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.


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.


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.


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.


Adamson, A. W., "Physical Chemistry of Surfaces," John Wiley & Sons, Inc., New York (1990).

Basu, S., K. Nandakumar and J. H. Masliyah, "A Study of Oil Displacement on Model Surfaces," J. Colloid Interface Sc. 182, 82-94 (1996).

Bichard, J. A., "Oil Sands Composition and Behaviour Research," AOSTRA Tech. Pub. Series #4, Alberta Oil Sands Technology and Research Authority, Edmonton, AB, Canada (1987).

Bowman, C. W., "Molecular and Interfacial Properties of Athabasca Tar Sands," in "Proc. of the 7th World Petroleum Congress," Elsevier Publishing Co., Amsterdam, The Netherlands (1967), pp. 583-604.

CAPP, "Canadian Crude Oil Production and Supply Forecast 2006-2020," PDF&dn=103586 (2006).

Chow, R. S. and K. Takamura, "Electrophoretic Mobilities of Bitumen and Conventional Crude-in-Water Emulsions Using the Laser Doppler Apparatus in the Presence of Multivalent Cations," J. Colloid Interface Sci. 125, 212-225 (1988).

Clark, K. A. and D. S. Pasternack, "Hot Water Separation of Bitumen from Alberta Bituminous Sand," Ind. Eng. Chem. 24, 1410-1416 (1932).

Cymerman, G., A. Leung, W. Maciejewski, J. Spence and B. Mcdonell, "Oil Sand Hydrotransport Tests at Syncrude Canada Ltd.," in "Proc. of the International Technical Conference on Coal Utilization and Fuel Systems," Coal and Slurry Technology Association (1993), pp. 681-690.

Cymerman, G. J., S. Ng, R. Siy and J. Spence, "Energy Conservation Measures at Syncrude Oil Sand Processing Operations," Paper 2191, CIM Mining Conference & Exhibition--Vancouver, BC, Canada (2006).

Dai, Q. and K. H. Chung, "Bitumen-Sand Interaction in Oil Sand Processing," Fuel 74, 1858-1864 (1995).

Dai, Q. and K. H. Chung, "Hot Water Extraction Process Mechanism using Model Oil Sands," Fuel 75, 220-226 (1996).

Ding, X., "Effects of Divalent Ions, Illite Clays and Temperature on Bitumen Recovery," MSc Thesis, University of Alberta, Edmonton, AB (2006).

Drelich, J., "The Role of Wetting Phenomena in the Hot Water Process for Bitumen Recovery from Tar Sand," PhD Dissertation, University of Utah, Salt Lake City, UT (1993).

Drelich, J., K. Bukka, J. D. Miller and F. V. Hanson, "Surface-Tension of Toluene-Extracted Bitumens from Utah Oil Sands as Determined by Wilhelmy Plate and Contact-Angle Techniques," Energy Fuels 8, 700-704 (1994).

Drelich, J. and J. D. Miller, "Surface and Interfacial-Tension of the Whiterocks Bitumen and Its Relationship to Bitumen Release from Tar Sands during Hot-Water Processing," Fuel 73, 1504-1510 (1994).

Drelich, J., "Wetting Phenomena in Oil Sand Systems and Their Impact on the Water-Based Bitumen Extraction Process," in "Preprints of the 136th SME Annual Meeting," February 25-28, 2007, Denver, Colorado, Society for Mining, Metallurgy and Exploration, Inc., Littleton, Colorado, Paper No. 07-002 (2007).

Dunstan, D. E., "Temperature Dependence of the Electrokinetic Properties of Two Disparate Surfaces," J. Colloid Interface Sci. 166, 472-475 (1994).

Gu, G. X., Z. H. Xu, K. Nandakumar and J. Masliyah, "Effects of Physical Environment on Induction Time of Air-Bitumen Attachment," Int. J. Mineral Process. 69, 235-250 (2003).

Helper, L. G. and R. G. Smith, "The Alberta Oil Sands: Industrial Procedures for Extraction and Some Recent Fundamental Research," AOSTRA Tech. Pub. Series #14, Alberta Oil Sands Technology and Research Authority, Edmonton, AB (1994).

Hupka, J., J. D. Miller and A. Cortez, "Importance of Bitumen Viscosity in the Hot Water Processing of Domestic Tar Sands," Mining Eng. 35, 1635-1641 (1983).

Hupka, J., A. G. Oblad and J. D. Miller, "Diluent-Assisted Hot-Water Processing of Tar Sands," AOSTRA J. Res. 3, 95-102 (1987).

Isaacs, E. E. and K. F. Smolek, "Interfacial-Tension Behavior of Athabasca Bitumen Aqueous Surfactant Systems," Can. J. Chem. Eng. 61, 233-240 (1983).

Isaacs, E. E. and D. N. Morrison, "Interfacial Films at the Athabasca Bitumen/Water Interface," AOSTRA J. Res. 2, 113-119 (1985).

Jasper, J. J. and E. V. Kring, "The Isobaric Surface Tensions and Thermodynamic Properties of the Surfaces of a Series of Normal-Alkanes, C-5 to C-18, 1-Alkenes, C-6 to C-16 and of Normal-Decylcyclopentane, Normal-Decylcyclohexane and Normal-Decylbenzene," J. Phys. Chem. 59, 1019-1021 (1955).

Kasongo, T., Z. Zhou, Z. Xu and J. Masliyah, "Effect of Clays and Calcium Ions on Bitumen Extraction from Athabasca Oil Sands using Flotation," Can. J. Chem. Eng. 78, 674-681 (2000).

Li, H., J. Long, Z. Xu and J. Masliyah, "Synergetic Role of Polymer Flocculant in Low-Temperature Bitumen Extraction and Tailings Treatment," Energy Fuels 19, 936-943 (2005a).

Li, H., Z. Zhou, Z. Xu and J. Masliyah, "Role of Acidified Sodium Silicate in Low Temperature Bitumen Extraction from Poor-Processing Oil Sand Ores," Ind. Eng. Chem. Res. 44, 4753-4761 (2005b).

Liu, J., Z. Zhou, Z. Xu and J. Masliyah, "Bitumen-Clay Interactions in Aqueous Media Studied by Zeta Potential Distribution Measurement," J. Colloid Interface Sci. 252, 409-418 (2002).

Liu, J., Z. Xu and J. Masliyah, "Studies on Bitumen-Silica Interaction in Aqueous Solutions by Atomic Force Microscopy," Langmuir 19, 3911-3920 (2003).

Liu, J., Z. Xu and J. Masliyah, "Interaction between Bitumen and Fines in Oil Sands Extraction System: Implication to Bitumen Recovery," Can. J. Chem. Eng. 82, 655-666 (2004a).

Liu, J., Z. Xu and J. Masliyah, "Role of Fine Clays in Bitumen Extraction from Oil Sands," AIChE J. 50, 1917-1927 (2004b). Liu, J., Z. Xu and J. Masliyah, "Colloidal Forces between Bitumen Surfaces in Aqueous Solutions Measured with Atomic Force Microscope," Colloids Surfaces A--Physicochem. Eng. Aspects 260, 217-228 (2005a).

Liu, J., Z. Xu and J. Masliyah, "Processability of Oil Sand Ores in Alberta," Energy Fuels 19, 2056-2063 (2005b).

Long, J., Z. Xu and J. Masliyah, "On the Role of Temperature in Oil Sands Processing," Energy Fuels 19, 1440-1446 (2005).

Long, J., Z. Xu and J. Masliyah, "Adhesion of Single Polyelectrolyte Molecules on Silica, Mica and Bitumen Surfaces," Langmuir 22, 1652-1659 (2006).

Long, J., H. Li, Z. Xu and J. Masliyah, "Novel Aids for Low-Grade Oil Sand Ores Processing," Can. J. Chem. Eng. in press (2007).

Luthra, M., "A Visualization Technique for Estimating Bitumen Extraction from Oil Sands," MSc Thesis, University of Alberta, Edmonton, AB (2001).

Majid, A., A. F. Sirianni and J. A. Ripmeester, "Comparative-Study of 3 Laboratory Methods for the Extraction of Bitumen from Oil Sands," Fuel 61, 477-479 (1982).

Masliyah, J., "Electrokinetic Transport Phenomena," AOSTRA Tech. Pub. Series #12, Edmonton, AB (1994).

Masliyah, J., Z. Zhou, Z. Xu, J. Czarnecki and H. Hamza, "Understanding Water-Based Bitumen Extraction from Athabasca Oil Sands," Can. J. Chem. Eng. 82, 628-654 (2004).

Morgan, G., "An Energy Renaissance in Oil Sands Development," World Energy 4, 46-53 (2001).

Pandit, A., C. A. Miller and L. Quintero, "Interfacial-Tensions between Bitumen and Aqueous Surfactant Solutions by Maximum Bubble Pressure Technique," Colloids Surfaces A--Physicochem. Eng. Aspects 98, 35-41 (1995).

Potoczny, Z. M., E. I. Vargha-Butler, T. K. Zubovits and A. W. Neumann, "Surface Tension of Bitumen," AOSTRA J. Res. 1, 107-120 (1984).

Ramachandran, R. and P. Somasundaran, "Effect of Temperature on the Interfacial Properties of Silicates," Colloids Surfaces 21, 355-369 (1986).

Sanford, E. C. and F. A. Seyer, "Processibility of Athabasca Tar Sand Using a Batch Extraction Unit--Role of Naoh," CIM Bulletin 72, 164-169 (1979).

Schramm, L. L., R. G. Smith and J. A. Stone, "The Influence of Natural Surfactant Concentration on the Hot Water Process for Recovering Bitumen from the Athabasca Oil Sands," AOSTRA J. Res. 1, 5-13 (1984).

Schramm, L. L., E. N. Stasiuk, H. Yarranton, B. B. Maini and B. Shelfantook, "Temperature Effects from the Conditioning and Flotation of Bitumen from Oil Sands in Terms of Oil Recovery and Physical Properties," J. Can. Petroleum Technol. 42, 55-61 (2003).

Seyer, F. A. and G. W. Gyte, "Viscosity," AOSTRA Tech. Handbook Oil Sands, Bitumen Heavy Oils--AOSTRA Tech. Pub. Series #6, L. G. Helper and C. Hsi, Eds., Alberta Oil Sands Technology and Research Authority, Edmonton, AB (1989), Chapter 4.

Stasiuk, E. N., L. L. Schramm, H. Yarranton and B. Shelfantook, "Shear and Interfacial Phenomena Involved in Reducing Process Temperature for the Recovery of Bitumen from Athabasca Oil Sand," in "Abstracts of Papers of the American Chemical Society," (2004), pp. U839-U839.

Sury, K. N., "Low Temperature Bitumen Recovery Process," U.S. Patent 4 946 597 (1990).

Takamura, K. and R. S. Chow, "A Mechanism for Initiation of Bitumen Displacement from Oil Sands Electric Properties of The Bitumen/Water Interface Part II. Application of the Ionizable Surface-Group Model," Can. J. Petroleum Technol. 22, 22-30 (1983).

Takamura, K. and R. S. Chow, "The Electric Properties of the Bitumen/Water Interface Part II. Application of the Ionizable Surface-Group Model," Colloids Surfaces 15, 35-48 (1985).

Takamura, K. and E. E. Isaacs, "Interfacial Properties," AOSTRA Tech. Handbook Oil Sands, Bitumen Heavy Oils--AOSTRA Tech. Pub. Series #6, L. G. Helper and C. Hsi, Eds., Alberta Oil Sands Technology and Research Authority, Edmonton, AB (1989), Chapter 4.

Varghabutler, E. I., T. K. Zubovits, C. J. Budziak, A. W. Neumann and Z. M. Potoczny, "Surface-Tension of Bitumen from Contact-Angle Measurements on Films of Bitumen," Energy Fuels 2, 653-656 (1988).

Wallwork, V., "An Investigation of Oil Sand Processibility," MSc Thesis, University of Alberta, Edmonton, AB (2003).

Wallwork, V., Z. H. Xu and J. Masliyah, "Processibility of Athabasca Oil Sand Using a Laboratory Hydrotransport Extraction System (LHES)," Can. J. Chem. Eng. 82, 687-695 (2004).

Yang, C., T. Dabros, D. Q. Li, J. Czarnecki and J. H. Masliyah, "Measurement of the Zeta Potential of Gas Bubbles in Aqueous Solutions By Microelectrophoresis Method," J. Colloid Interface Sci. 243, 128-135 (2001).

Zhao, H. Y., J. Long, J. H. Masliyah and Z. H. Xu, "Effect of Divalent Cations and Surfactants on Silica-Bitumen Interactions," Ind. Eng. Chem. Res. 45, 7482-7490 (2006).

Zhou, Z., T. Kasongo, Z. Xu and J. Masliyah, "Assessment of Bitumen Recovery from the Athabasca Oil Sands using a Laboratory Denver Flotation Cell," Can. J. Chem. Eng. 82, 696-703 (2004).

Jun Long, (1) * Jaroslaw Drelich, (2) Zhenghe Xu (1) and Jacob H. Masliyah (1)

(1.) Department of Chemical and Materials Engineering, University of Alberta Edmonton, AB, Canada T6G 2G6

(2.) Department of Materials Science and Engineering, Michigan Technological University, Houghton, MI, U.S.A. 49931

* Author to whom correspondence may be addressed. E-mail address:
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

Peace River (Canada) -0.063 [+ or -] 0.010 (40[degrees]C to

Pelican Lake (Canada) -0.063 [+ or -] 0.012 (40[degrees]C to

Fort McMurry (Canada) -0.063 [+ or -] 0.010 (40[degrees]C to

Whiterocks North-West -0.077 [+ or -] 0.002 (40[degrees]C to

West-Central -0.082 [+ or -] 0.001 (40[degrees]C to

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)


Table 2. Effect of chemical aids on bitumen recovery

Chemicals Bitumen recovery Type of oil sands

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)
COPYRIGHT 2007 Chemical Institute of Canada
No portion of this article can be reproduced without the express written permission from the copyright holder.
Copyright 2007 Gale, Cengage Learning. All rights reserved.

Article Details
Printer friendly Cite/link Email Feedback
Author:Long, Jun; Drelich, Jaroslaw; Xu, Zhenghe; Masliyah, Jacob H.
Publication:Canadian Journal of Chemical Engineering
Date:Oct 1, 2007
Previous Article:Hydrodynamic cell model: general formulation and comparative analysis of different approaches.
Next Article:The limits of fine and coarse particle flotation.

Terms of use | Privacy policy | Copyright © 2020 Farlex, Inc. | Feedback | For webmasters