Athabasca

Athabasca tar sands Naturally occurring mixtures of bitumen and sand found in Northern Alberta. 

Synthetic Fuel. Solvent extraction has many appHcations in synthetic fuel technology such as the extraction of the Athabasca tar sands (qv) and Irish peat using / -pentane [109-66-0] (238) and a process for treating coal (qv) using a solvent under hydrogen (qv) (239). In the latter case, coal reacts with a minimum amount of hydrogen so that the solvent extracts valuable feedstock components before the soHd residue is burned. Solvent extraction is used in coal Hquefaction processes (240) and synthetic fuel refining (see Coal conversion processes Fuels, synthetic). 

In addition to the significant consumption of coal and lignite, petroleum, and natural gas, several countries utilize modest quantities of alternative fossil fuels. Canada obtains some of its energy from the Athabasca tar sands development (the Great Canadian Oil Sands Project). Oil shale is burned at... 

Tar sands have been reported on every continent except AustraHa and Antarctica. The best known deposits are the Athabasca of Canada, where almost 60,000 km in northeastern Alberta is underlain with an estimated 138 x 10 (870 x 10 bbl) of recoverable bitumen (157). The Alberta deposits... 

Perhaps the biggest contribution that technological advancement in petroleum production will make is bringing large volumes of unconventional petroleum resources, eg, heavy oil and tar sands, into a viable economic realm by lowering the unit cost of production. Compared to the inventory of conventional petroleum reserves and undiscovered resources, the physical inventories of such unconventional petroleum resources are extremely large for example, the Athabasca tar sands in Alberta, Canada, are estimated to contain 360 x 10 m (2250 x 10 bbl) of in-place petroleum (19). This volume is equivalent to the total inventory, ie, the combined cumulative production, reserves, and undiscovered resources, of world conventional cmde petroleum. In... 

Tar sand, also variously called oil sand (in Canada) or bituminous sand, is the term commonly used to describe a sandstone reservoir that is impregnated with a heavy, viscous black extra heavy cmde oil, referred to as bitumen (or, incorrectly, as native asphalt). Tar sand is a mixture of sand, water, and bitumen, but many of the tar sand deposits in the United States lack the water layer that is beHeved to cover the Athabasca sand in Alberta, Canada, thereby faciHtating the hot-water recovery process from the latter deposit. The heavy asphaltic organic material has a high viscosity under reservoir conditions and caimot be retrieved through a weU by conventional production techniques. 

The Athabasca deposit, along with the neighboring Wabasca, Peace River, and Cold Lake heavy oil deposits, have together been estimated to contain 1.86 X 10 m (>1.17 X 10 bbl) of bitumen. The Vene2uelan deposits may at least contain >1.60 X 10 m (1.0 X 10 bbl) bitumen (2). Deposits of tar sand, each containing >3 x 10 m (20 x 10 bbl) of bitumen, have also been located in the United States, Albania, Italy, Madagascar,... 

The Alberta (Athabasca) tar sand deposits are located in the northeast part of that Canadian province (Fig. 4). These are the only mineable tar sand deposits undergoing large-scale commercial exploitation as of this writing (ca 1997). 

The Athabasca deposits have been known since the early 1800s. The first scientific iaterest ia tar sands was taken by the Canadian government ia 1890, and ia 1897—1898, the sands were first drilled at PeHcan Rapids on the Athabasca River. Up until 1960, many small-scale commercial enterprises were attempted but not sustained. Between 1957 and 1967, three extensive pilot-plant operations were conducted ia the Athabasca region, each leading to a proposal for a commercial venture, eg, Suncor and Syncmde. 

The data available are generally for the Athabasca materials, although workers at the University of Utah (Salt Lake City) have carried out an intensive program to determine the processibiUty of Utah bitumen and considerable data have become available. Bulk properties of samples from several locations (Table 3) (9) show that there is a wide range of properties. Substantial differences exist between the tar sands in Canada and those in the United States a difference often cited is that the former is water-wet and the latter, oil-wet (10). 

Bitumen. There are wide variations both in the bitumen saturation of tar sand (0—18 wt % bitumen), even within a particular deposit, and the viscosity. Of particular note is the variation of density of Athabasca bitumen with temperature, and the maximum density difference between bitumen and water (70—80°C (160—175°F)) hence the choice of the operating temperature of the hot-water bitumen-extraction process. 

Cut point, °C Athabasca, wt % distilled NW Asphalt Ridge, wt % distiUed" P.R. Springs, wt % distilled Tar Sand Triangle, wt % distilled ... 

Recovery methods are based either on mining combined with some further processing or operation on the oil sands m situ (Fig. 6). The mining methods are appHcable to shallow deposits, characterized by an overburden ratio (ie, overburden depth-to-thickness of tar sand deposit) of ca 1.0. Because Athabasca tar sands have a maximum thickness of ca 90 m and average ca 45 m, there are indications that no more than 10% of the in-place deposit is mineable within 1990s concepts of the economics and technology of open-pit mining. 

The bitumen in the Athabasca deposit, which has a gravity on the API scale of 8°, is heavier than water and very viscous. Tar sand is a dense, soHd material, but it can be readily dug in the summer months during the winter months when the temperatures plunge to —45° C, tar sand assumes the consistency of concrete. To maintain acceptable digging rates in winter, mining must proceed faster than the rate of frost penetration if not, supplemental measures such as blasting are required. 

Recovering the bitumen is not easy, and the deposits are either strip-mined if they are near the surface, or recovered in situ if they are in deeper beds. The bitumen could be extracted by using hot water and steam and adding some alkali to disperse it. The produced bitumen is a very thick material having a density of approximately 1.05 g/cm. It is then subjected to a cracking process to produce distillate fuels and coke. The distillates are hydrotreated to saturate olefinic components. Table 1-8 is a typical analysis of Athabasca bitumen. ... 

These are found in crude petroleum including bitumen in the Athabasca tar sands of Northern Alberta. They contain a complex mixture of saturated polycyclic live- and six-membered cycloalkanes with alkane and alkanoic acid substituents. Attention has been directed to the degradation of both commercially available products, and those that are produced during bitumen extraction. Although the former were degradable (Clemente et al. 2004), the higher molecular mass components of the latter were much more recalcitrant (Scott et al. 2005). 

Scott AA, MD Mackinnon, PM Fedorak (2005) Naphthenic acids in Athabasca oil sands tailings water are less biodegradable than commercial naphthenic acids. Environ Sci Technol 39 8388-8394. 

In the laboratory of Professor R.G. Moore at the University of Calgary, kinetic data were obtained using bitumen samples of the North Bodo and Athabasca oil sands of northern Alberta. Low temperature oxidation data were taken at 50, 75, 100, 125 and 150"C whereas the high temperature thermal cracking data at 360, 397 and 420"C. 

In Figures 18.18, 18.19 and 18.20 the experimental data and the calculations based on model I are shown for the high temperature cracking at 360, 397 and 420 T of an Athabasca oil sands bitumen (Drum 20). Similar results are seen in Figures 18.21, 18.22 and 18.23 for another Athabasca oil sands bitumen (Drum 433). The estimated parameter values for model I are shown in Table 18.3 for Drums 20 and 433. 

Table 18.3 Estimated Parameter Values for Model l for High Temperature Cracking of Athabasca Oil Sands Bitumen...

Figure 18.18 Experimental and calculated concentrations of Coke (COK) "a ", Asphaltene (ASP) "o and Heavy Oil -i Light Oil (HO+LO) " at 360 °C for the high temperature cracking of Athabasca oil sands bitumen (Drum 20) using mode /.

Hanson, K. and N. Kalogerakis, "Kinetic Reaction Models for Low Temperature Oxidation and High Temperature Cracking of Athabasca and North Bodo Oil Sands Bitumen", NSERC Report, University of Calgary, AB, Canada, 1984. 

Isaacs and Smolek [211 observed that low tensions obtained for an Athabasca bitumen/brine-suIfonate surfactant system were likely associated with the formation of a surfactant-rich film lying between the oil and water, which can be hindered by an increase in temperature. Babu et al. [221 obtained little effect of temperature on interfacial tensions however, values of about 0.02 mN/m were obtained for a light crude (39°API), and were about an order of magnitude lower than those observed for a heavy crude (14°API) with the same aqueous surfactant formulations. For pure hydrocarbon phases and ambient conditions, it is well established that the interfacial tension behavior is dependent on the oleic phase [15.231 In general, interfacial tension values of crude oiI-containing systems are considerably higher than the equivalent values observed with pure hydrocarbons. 

Materials. Samples of dewatered crude oils were obtained from the Athabasca oil sands of the McMurray formation by extraction using the commercial hot water process (Suncor Inc.) the Bl uesky-Bu11 head formation at Peace River, Alberta by solvent extraction of produced fluids the Clearwater formation at Cold Lake, Alberta by solvent extraction of core material and the Karamay formation in Xing-Jiang, China. A summary of the physical and chemical properties of the crude oils, including chemical composition, and density-temperature and viscosity-temperature relationships, is given in Table I. 

This type of difficulty associated with measurements using chemical ly iI I-defined substrates was also observed during sessile drop measurements carried out on Athabasca bitumen in D20 T311. Values in the range of 15-20 mN/m were obtained for measurements with several drops of bitumen, while interfacial tensions for other pure aqueous and oleic systems were accurate to 0.5 mN/m. 

Effect of NaCI Concentration. The presence of surfactant in brine can have a dramatic effect on crude oil-aqueous surfactant tensions even at elevated temperatures r5,211. Figure 5 shows that the effect of sodium chloride concentration on Athabasca bitumen-D20 interfacial tensions measured at constant surfactant... 

Effect of Temperature. In the absence of surfactant, interfacial tensions of the Athabasca 1 211. Karamay 1 51, and other heavy oils 1 321 show little or no dependence on temperature. For surfactant-containing systems, Figure 6 shows an example of the effect of temperature (50-200°C) on interfacial tensions for the Athabasca, Clearwater and Peace River bitumens in Sun Tech IV solutions containing 0 and 10 g/L NaCI. The interfacial tension behavior for the three bitumens was very similar. At a given temperature, the presence of brine caused a reduction in interfacial tension by one to two orders of magnitude. The tensions were seen to increase substantially with temperature. For the case of no added NaCI, the values approached those observed T211 in the absence of surfactant. 

Figure 5 Effect of NaCI concentration on the Athabasca bitumen/DJ) interfacial tension for Enordet C18 18, Sun Tech IV and TRS 10-80. Closed triangle represents the data measured for Enordet C16 18 at concentrations up to 160 g/L NaCI.

Table III Interfacial tension data for the Athabasca bitumen/D20 and Enordet C1618 (2 g/L) system as a function of NaCI concentration and temperature...

Figure 6 Interfacial tensions for Athabasca, Cold Lake and Peace River bitumen/DJ) systems as a function of temperature and NaCI (0 and 10 g/L) concentration.

Figure 7 Variation of interfacial tension between Athabasca bitumen and D20 containing Sun Tech IV (2 g/L) as a function of pH and temperature at constant ionic strength of 10 M. The dashed line represents data from reference T211 at 50 C in the absence of added surfactant or brine.

In the presence of Sun Tech IV surfactant, the interfacial tension of an Athabasca/brine system showed little or no dependence on pH. However, at a given pH, tension values increased with temperature (50-150°C). 

Bowman, C. W. Molecular and Interfacial Properties of Athabasca Tar Sands, Proceedings of the Seventh World Petroleum Congress", Elsevier Publishing Company New York, 1967, 3, p 583. 

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