In Alberta, oil sands bitumen is utilized for synthetic crude oil (SCO) production by surface mining, bitumen extraction followed by primary (coking) and secondary (catalytic hydrotreating) upgrading processes. SCO is further refined in specially designed or slightly modified conventional refineries into transportation fuels. Oil sands tailings, composed of water, sands, silt, clay and residual bitumen, is produced as a byproduct of the bitumen extraction process. The tailings have poor consolidation and water release characteristics. For twenty years, significant research has been performed to improve the consolidation and water release characteristics of the tailings. Several processes were developed for the management of oil sands tailings, resulting in different recovered water characteristics, consolidation rates and consolidated solid characteristics. These processes may affect the performance of the overall plant operations. Apex Engineering Inc. (AEI) has been developing a process for the same purpose. In this process oil sands tailings are treated with Ca(OH) 2 lime and CO 2 and thickened using a suitable thickener. The combination of chemical treatment and the use of a thickener results in the release of process water in short retention times without accumulation of any ions in the recovered water. This makes it possible to recycle the recovered water, probably after a chemical treatment, as warm as possible, which improves the thermal efficiency of the extraction process. The AEI Process can be applied in many different fashions for the management of different fractions of the tailings effluent, depending on the overall plant operating priorities.

The results of a series of triaxial compression tests on undisturbed samples of Athabasca oil sand at elevated temperatures ranging from 20 to 200 °C are summarized. The material tested had experienced gradual unloading and depressurization as a result of erosion in the Saline Creek valley near Fort McMurray. More deeply buried oil sands are known to contain much higher concentrations of dissolved hydrocarbon gases in the pore fluids. The measured shear strength of Athabasca oil sand did not change significantly as a result of the increased temperatures that were applied. The strength of Athabasca oil sand (at 20–200 °C) was found to be greater than comparable shear strengths reported for dense Ottawa sand (at 20 °C). Although heating to 200 °C had little effect on shear strength, it is recognized that pore pressure generation during undrained heating may cause substantial reduction of the available shearing resistance, particularly in gas-rich oil sands. The experimental data were used to investigate the influence of such factors as stress path dependency, microfabric disturbance, and heating to elevated temperatures on the shear strength and stress–strain behaviour of oil sand. Curve fitting of the test data suggests that the hyperbolic model is a useful empirical technique for stress—deformation analyses in oil sands. Hyperbolic stress—strain parameters derived from the experimental results for Athabasca oil sand are presented. Key words: oil sand, Athabasca oil sand, tar sand, shear strength, stress, strain, deformation, heating, high temperature, elevated temperatures, high pressure, elevated pressure, thermal properties, drained heating, undrained heating, triaxial compression testing.

The prediction of stress changes and deformations arising from ground heating requires the coupled solution of the heat transfer and consolidation equations. Heat consolidation as a class of problems is distinct from other thermally induced consolidation problems involving processes such as frost heave and thaw consolidation in that it involves heating to elevated temperatures well above normal ground temperatures. Two of the important parameters required in analyses of heat consolidation problems are thermal expansion coefficients and a coefficient of thermal pore pressure generation.Relationships describing thermal expansion behaviour and thermal pore pressure generation in oil sands are presented. Both drained and undrained thermal expansion coefficients for Athabasca oil sand were determined by means of heating experiments in the temperature range 20–300 °C. The thermal pore pressure generation coefficient was evaluated in undrained heating experiments under constant total confining stresses and under constant effective confining stresses. The equipment and experimental methods developed during this study are appropriate for determination of thermal expansion and pore pressure generation properties of oil sands and other unconsolidated geologic materials. Key words: thermal expansion, oil sand, tar sand, thermal pore pressure generation, heat consolidation, thermal consolidation, coefficient of thermal expansion, thermal stresses, ground heating, thermally enhanced oil recovery, thermoelasticity, undrained heating.

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A laboratory study was conducted to determine the recovery of high-viscosity crude oil from natural uncon-solidated sand by WATERFLOODING with a number of chem-ical solutions. Displacement tests were run using chemical solutions to displace a high-viscosity crude oil from ar-tificial packs of unconsolidated core sand. Results of the displacement tests showed that oil recovery was increased by a number of chemical solutions.Sodium hydroxide in brine at concentrations less than 0.01 per cent by weight had little effect on recovery as floods. Sodium hydroxide concentra-cent or greater increased recovery compared to brine tions of 0.1 per cent significantly. P. M. Dranchuk received his formal training in petroleum engineering at The interfacial tension between Lloydminster crude oil and various aqueous solutions was greatly reduced by the addition of a number of chemicals to the aqueous solutions. The presence of sodium chloride in the aqueous solution the amount of chemical required for the reduction of the interfacial tension between crude oil and the solution to a given level. The reduction in interfacial tension influenced the recovery of oil.The production of a very stable emulsion and evidence of reduced water mobility during displacement tests sug-gested that emulsification may have occurred within the core. The formation of an emulsion may have increased Introduction THERE ARE large known reserves of heavy oil in West-ern Canada. However, the nature of the reservoirs and oils involved are such that primary recovery is estimated at 5 to 6 per cent"', with a possibility of increasing total recovery to about 10 per cent of the oil in place by means of conventional WATERFLOODING. In order that these recoveries be increased to a more acceptable value, new secondary recovery techniques must be developed.This study represents a continuation of a series of investigations conducted at the University of Al-berta'2,:" into the effect of chemical additives on waterflood recovery from heavy oil reservoirs. It is well known that the preferential wettability of the solid surfaces in porous media influences their relative permiability, capillary pressure and water-floodability characteristics. These properties can be altered by introducing any one of a variety of liquids which alter the contact angle. However, if a surface is oil-wet, the contact angle (conventionally measured through the (denser phase) cannot be reduced below 90 degrees, so that further reductions in adhesion ten-sion and therefore energy requirements for oil dis-placement can only be realized through reductions in interfacial tension. Reductions in interfacial tension also serve to reduce capillary forces, thereby further reducing the amount of energy required for oil dis-placement. Similarly, changing a system from an oil-wet to a water-wet state improves the relative per-meability to oil and increases the efficiency of the oil displacement process.Several investigators have reported obtaining higher waterflood recoveries from preferentially water-wet sys...