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Extra heavy oil and bitumen reservoirs constitute huge volumes around the world and are attracting attention as alternative energy resources while the light oil reserves diminish. Thermal recovery and steam based methods are the most widely used recovery methods applicable to these highly viscous deposits. Study of steam injection in porous media containing viscous oil requires a good understanding of the physical properties of both reservoir rock and fluid. In particular, there are some bitumen properties that are needed for simulation studies and the most reliable source for these data is laboratory tests. This paper presents experimental study of some PVT properties of Athabasca crude oil to help provide input data for further numerical studies. Viscosity of Athabasca heavy crude was measured using a rotational viscometer up to 300 °C. This viscosity data is a more reliable input for simulation purposes. Athabasca oil was characterized by gas chromatography analysis to C 39+ . No significant amount of components lighter than C 9 was observed. Whole sample molar mass was measured to 534 g/mol by cryoscopy. Density at standard conditions of 1 atm and 60 °F was measured to 1.0129 g/cm 3 by a density measuring cell. Density and molar mass of the C 39+ fraction were also determined. Density measurements were performed in the temperature range 120-195 °C as well where the density was found to vary in the range 0.95-0.90 g/cm 3 . A formula was derived based on experimental density data to predict Athabasca bitumen density in the temperature and pressure range studied. The interfacial tension between oil and steam was measured in the temperature range 120-220 °C by the pendant drop method. The interfacial tension was determined to be between 25 and 18 mN/m with a decreasing trend in the temperature range studied. The results presented here can be used as reference data for studies related to Athabasca bitumen.

A spectrometer for the detection of laser light scattered by thermally excited capillary waves at fluid interfaces is described. Its optical system makes possible precise observations at capillaly mode wave numbers high enough to avoid significant effects of instrumental resolution and permits the beam to be incident upon the fluid interface through either of the two adjacent fluid phases. Its performance was tested on the following three model systems at 20.C: the free surfaces of water and 2-butano1, representing the oscillatory and critically damped capillary wave regimes respectively, and the interface between mutually saturated phases of these two liquids, representing the non-oscillatory regime. Accessible wave numbers for which effects of instrumental resolution were insignificant ranged between approximately 1 x lo5 and 5 x lo5 m-'. Values obtained for surface and interfacial tensions and viscosity agreed well with those obtained using a high-accuracy Wilhelmy plate tensiometer and a capillary viscometer.

For efficient and safe well operations it is important to understand the behaviour of gas influx in petroleum fluids and the impact of relevant temperature and pressure changes in the well. Drilling simulators are tools for analysing gas kick detection limits, designing well control procedures, planning the chemicals and equipment needed on the rig, and generally for planning the well design. A major weakness in current models of kick detection is the lack of experimentally verified data in the HPHT region. The data from this study will be analysed and used as an input in a computational model of two phase gas-drilling fluid flow in the well, allowing better prediction of gas absorption.This study will provide experimental measurements under HPHT conditions for oil based drilling fluids (OBDFs) and base oils mixed with methane. As a part of the DrillWell centre program, SINTEF has developed an experimental setup for studying the effects of natural gas dissolved in drilling fluids under conditions relevant for HPHT drilling operations. In this setup we are able to measure density and rheological properties of drilling fluids with different degrees of methane saturation at pressures and temperatures of up to 1000 bar and 200°C.Base oils, the major constituent of OBDFs, contribute to the mud properties. Knowing the properties of the base oils at different pressure and temperature conditions enables assessment of the influence of the other components in the drilling fluid. In this paper we present measurements of a refined mineral base oil, especially designed for deepwater operations, and a linear paraffin oil. These base oils were tested for gas absorption capacity at various pressures and temperatures, and the effect of dissolved gas on the density of the base oils was measured. Experimentally determined saturation pressures show good correlation with predictions made with PVTsim for low gas-oil-ratios (GORs), however, at higher GOR-values the deviation is significant. The temperature influence on the saturation pressure is underestimated by PVTsim, demonstrating the need for more experimental data of drilling fluid behaviour at HPHT conditions. Furthermore, there was a clear difference in the maximum saturation pressure of the two base oils, which may be of high importance for the choice of drilling fluid at high reservoir pressures.In the continuation of this study we will perform measurements of methane solubility in two OBDFs composed of the two base oils studied in this work, respectively. Density and viscosity of mixtures of OBDF/CH 4 will be measured for various amounts of methane at pressures and temperatures ranging from standard ambient to HPHT. The resulting HPHT data will be highly important for improved calculation of bottom hole pressure and prediction of gas kicks.