Phase Behaviour and Physical Property Measurements for VAPEX Solvents: Part I. Propane and Athabasca Bitumen
- A. Badamchi-Zadeh (University of Calgary) | H.W. Yarranton (University of Calgary) | W.Y. Svrcek (University of Calgary) | B.B. Maini (University of Calgary)
- Document ID
- Petroleum Society of Canada
- Journal of Canadian Petroleum Technology
- Publication Date
- January 2009
- Document Type
- Journal Paper
- 54 - 61
- 2009. Petroleum Society of Canada (now Society of Petroleum Engineers)
- 6.4.6 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 6.2.1 Phase Behavior and PVT Measurements
- vapor extraction, solvents, propane
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The saturation pressure and solubility of propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for temperatures from 10 to 50 °C. Equilibration proved challenging for this fluid mixture and required some experimental modifications that are discussed. Only liquid and liquid-vapour phase regions were observed at propane contents below 20 wt%. A second liquid phase appeared to have formed at higher propane contents. The saturation pressures, where only a single dense phase formed, ranged from 600 to 1,600 kPa and these were fitted with a modification to Raoult's law. Viscosities less than 210 mPa.s were obtained at a propane content of 15.6 wt%. All of the viscosity data of the liquid phase were predicted from the propane and bitumen viscosities using the Lobe mixing rule.
The worldwide original oil-in-place (OOIP) of heavy oil and bitumen is estimated to be approximately 6 trillion barrels. A major part of these resources are in Canada ( ~36%) and Venezuela ( ~27%)(1). In Canada, steam-based methods are often employed to improve heavy oil recovery. However, the industry is starting to seek alternatives to these methods because they are energy intensive and are drawing heavily on the available water supply. Solvent-based recovery methods are a potential alternative capable of providing high recovery factors without substantial water requirements(2, 3). One option is the vapour extraction method (VAPEX), which is a solvent-based analogue of the Steam-Assisted Gravity Drainage (SAGD) process(4-7).
VAPEX is implemented with a pair of horizontal wells: a production well at the bottom of the reservoir and a solvent injection well located directly above the production well(5), as shown in Figure 1. The vapourized solvent is injected through the injection well and a chamber of solvent vapour forms around the well. At the walls of the chamber, the solvent diffuses into a surface layer of the heavy oil and dramatically reduces its viscosity. The diluted oil layer is then mobile enough to drain down, under the influence of gravity, into the production well.
VAPEX performance depends on the viscosity and density of the liquid phase that forms at the edge of the solvent chamber. In order to design and optimize VAPEX and other solvent-based processes, it is critical to be able to determine the diffusivity of the solvent in the heavy oil, identify the phases that form in the solvent and heavy oil mixtures at various temperatures and pressures, and determine the density and viscosity of the liquid phase. Other solvent-based processes (steam and solvent injection for heavy oil recovery and solvent extraction of oil sands) require similar data.
Most research on VAPEX has focused on physical model experiments with light alkane solvents; particularly mixtures of methane and propane(3). However, mixtures of carbon dioxide and propane may be a more viable option. Currently, carbon dioxide is expensive, but costs are expected to decrease if environmental incentives to sequester carbon dioxide are introduced. Carbon dioxide may also be a better VAPEX solvent than methane because it is more soluble in heavy oil and reduces the viscosity more(8).
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