In Situ Upgrading of Heavy Oil in a Solvent-Based Heavy Oil Recovery Process

Abstract

Abstract In this paper, a series of laboratory experiments are conducted under reservoir conditions to quantify the in situ upgrading of heavy oil due to the solvent dissolution and asphaltene precipitation by using a pure solvent (propane) and a solvent mixture (70 mol% methane + 25 mol% propane + 3.5 mol% n-butane + 1.5 mol% iso-butane). It is found that after a solvent is placed in contact with heavy oil at a relatively high pressure for a sufficiently long time, the heavy oil-solvent system at equilibrium state can be roughly divided into three different layers. The top layer is a solvent-enriched oil phase, the middle layer comprises heavy oil with the dissolved solvent and the bottom layer mainly consists of heavy components. The solvent-saturated heavy oils in these three layers have rather different physicochemical properties, such as the solvent concentration, carbon number distribution and viscosity. The top layer has the highest concentrations of solvent and light components and the lowest viscosity of heavy oil even after its dissolved solvent is flashed off. The heavy oil in the middle layer has similar carbon number distribution to the original heavy oil. The bottom layer has the lowest solvent concentration and the highest concentration of heavy components. The heavy oil in the bottom layer, after its dissolved solvent is flashed off, has much higher viscosity than the original heavy oil. These experimental results indicate that in a solvent-based heavy oil recovery process, the solvent-saturated heavy oil in the top and middle layers can be recovered because of its lower viscosity, whereas the heavy oil in the bottom layer may be left behind in the heavy oil reservoir because of its higher viscosity. In this way, the produced heavy oil is in situ upgraded during the solvent-based heavy oil recovery process. Introduction Western Canada has tremendous heavy oil and bitumen deposits(1). Approximatelzy 70 to 80% of the original-oil-in-place (OOIP) remains unrecovered at the economic limit after cold production(2). Heavy oil contains a large portion of heavy components, which are the major reason for its high viscosity (>100 mPa •s) and low API gravity (< 20 °API)(3). Heavy oils and bitumen are highly viscous so that they cannot be recovered by using some conventional recovery techniques for medium and/or light oils. In practice, thermal methods are often used because they can dramatically reduce heavy oil viscosity. However, the majority of Canadian heavy oil reservoirs cannot be exploited effectively and economically by using thermal methods alone due to thin pay zones and/or bottomwater aquifers. Also, low thermal conductivity, high water saturation and large heat losses to the overburden and underburden formations are among the major technical problems associated with the thermal methods(4). In the past, a number of experimental and numerical studies have been conducted to explore the potential of non-thermal recovery methods for heavy oil reservoirs. Solvent-based processes, such as vapour extraction (VAPEX)(5–8), are among the most promising heavy oil recovery techniques. In the VAPEX process, for example, gaseous light hydrocarbon solvents(9) or their mixtures together with non-condensable gases(10) are used to extract heavy oils and bitumen from the reservoir formations.