A laboratory investigation into the recovery of bitumen using hot water and naphtha was carried out in 1981 and 1982 by the Alberta Research Council under contract to Texaco Canada Resources Ltd.
An oil sand formation which was assumed to contain a highly permeable zone exposed to a hot water-naphtha injection was simulated in the Laboratory using a Hassler type cell. The cell could accommodate a core 9.2 cm in diameter and 17.8 cm long. An axial, 13 mm diameter communication path was filed with frac sand, and hot water and naphtha flowed through at a known rate.
The study presented in this paper aims to offer a simple estimation of the economics of a hot water-naphtha process. Data collected from ten runs was processed in order to calculate the most characteristic parameters for the process. A multiple linear regression technique was applied to obtain simple linear equations subsequently used for the optimization study. An analogy between rates of production obtained in the physical simulator and those obtained in the field was heuristically assumed. This assumption permits the extent ion of the study to a field process.
Diluents naphtha and other light hydrocarbons are being considered as potential additives to steam and hot water in order to enhance the in-situ recovery of bitumen from oil sand reservoirs.1–6 Insufficient information regarding the use of the naphtha as an additive in d hot water process required a dedicated laboratory study. A physical simulator was extensively used to provide information on the recovery process.
An oil sand formation, containing a highly permeable zone exposed to a hot water-naphtha injection, was simulated in the laboratory using a pressurized Hassler-type cell7 as illustrated in Figure 1. The system consisted of a reconstituted core of surface-mined Athabasca oil sand contained within a deformable lead sleeve. The diameter of the core was 9.2 cm and the length was approximately 17.8 cm. An axial communication path was constructed by drilling a 13 mm diameter hole and filling it with clean water-wet frac sand (10–20 mesh). A pressure vessel containing the oil sand sample simulated a 90 m overburden pressure through the use of nitrogen gas at 2.1 MPa. A constant injection rate of 3.0 kg/h of hot water and naphtha was used throughout the series of experiments ∗. Differential pressure across the core was continuously recorded. The produced fluids, consisting of free bitumen, a bitumen-water emulsion and naphtha, were collected and analyzed. A back pressure control valve prevented flashing of the produced fluids.
Each experiment was limited to 450 minutes. The injection temperature was maintained at a constant value; the naphtha, commingled with the water, was injected at a fixed ratio. The produced fluids were sampled at regular intervals and submitted for analyses in order to determine the oil-water composition.
Produced volatiles (mostly naphtha) were condensed and collected separately. Injecting naphtha at elevated temperatures resulted in the vaporization of some solvent. The fraction of naphtha vaporized approximated that fraction indicated by a standard distillation curve at the temperature in question.
