High-Temperature Relative Permeabilities for Athabasca Oil Sands
- M. Polikar (BP Resources Canada Ltd.) | S.M. Farouq Ali (U. of Alberta) | V.R. Puttagunta (Lakehead U.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- February 1990
- Document Type
- Journal Paper
- 25 - 32
- 1990. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 5.2 Reservoir Fluid Dynamics, 5.2.1 Phase Behavior and PVT Measurements, 5.4.6 Thermal Methods, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.6.2 Core Analysis, 5.5 Reservoir Simulation, 4.2.3 Materials and Corrosion, 2.4.3 Sand/Solids Control, 5.1.1 Exploration, Development, Structural Geology, 5.3.4 Reduction of Residual Oil Saturation, 5.3.2 Multiphase Flow, 1.2.3 Rock properties, 5.4.1 Waterflooding, 5.5.2 Core Analysis, 4.3.4 Scale, 4.1.2 Separation and Treating, 5.5.8 History Matching, 5.3.1 Flow in Porous Media
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An experimental study of Athabasca bitumen/water relative permeabilities revealed little or no temperature effect on the relative permeabilities to water and bitumen over a range of 100 to 250C [212 to 482 F]. Comparable results were obtained with both steady- and unsteady-state relative permeability measuring techniques. It was determined that the oil-phase relative permeability curve was convex. Measured curves were also compared with those obtained by history matching.
Relative permeability is one of the most important input variables for numerical reservoir simulation models. Knowledge of relative permeability curves and residual fluid saturations is needed to determines the oil production rate and ultimate recovery, respectively. Relative permeability generally has been represented as a function of saturation. Experimental measurement techniques developed in the 1950's and early 1960's for light-oil reservoirs include the steady-state technique and the unsteady-state, or dynamic, method. The latter has received more attention because of its faster turn-around time. Neither method seems superior, however, because of limitations inherent in each. Because of the experimental difficulties encountered in determining relative permeabilities, a suitable laboratory procedure that eliminates inlet and outlet end effects and resulting saturation gradients must be used. The experimental conditions usually are idealized and simplified by the use of small core plugs or reconstituted sand cores and refined oils rather than native reservoir materials. The objective of this study was to measure experimentally the relative permeability to water and bitumen in unconsolidated sand cores. The difficulties of this task were compounded by the system's high temperatures and pressures and the bitumen's high viscosity. No published experimental data on residual fluid saturations, relative permeability curves, and the effect of temperature on these parameters exist for the Athabasca oil-sand system. The temperature and pressure conditions encountered in the recovery of oil-sand bitumens (1.02 to 0.97 g/cm3 [8 to 14API]) from deeply buried formations were reproduced in this study. Because of conflicting results in the literature regarding the effect of temperature on relative permeability, a simple system focusing on the fundamental properties that might cause temperature effects was used. The selected system consisted of unconsolidated silica sand, deionized water, and solvent-extracted Athabasca bitumen. Measurements were performed in the 100 to 250C [212 to 482F] temperature range. These idealized conditions minimized clay migration and high-temperature corrosion. The use of crude oil more closely represented the field conditions. In this way, experimental difficulties were alleviated and the interpretation of relative permeability determination was eased.
Temperature effects on relative permeability have received considerable attention since the mid-1950's. Contradictory results were obtained because of the different systems used. Tables 1 and 2 summarize the observations reported in the literature for unconsolidated and consolidated porous media, respectively. Nakornthap and Evans presented the most frequently observed effects with increasing temperature: an increase in irreducible water and a decrease in residual oil, which shifts the saturation range to higher water saturations, and a considerable increase in relative permeability to oil and a decrease in relative permeability to water. Two recent studies at Stanford, performed in clean unconsolidated sand cores with white mineral oils, showed that residual saturations and relative permeability relationships were virtually unaffected by temperature. The authors concluded that previously reported results for unconsolidated sands may have been affected by viscous instabilities, capillary end effects, and/or difficulties in maintaining material balances, but noted that there was no way to evaluate such problems in others' works. They did not prove that temperature effects were nonexistent for real reservoir rocks and fluids, but only implied that such effects were probably unrelated fundamental flow properties. A detailed review of available relative permeability relationships for the oil-sand and heavy-oil deposits of Alberta indicated that a variety of curves existed and that no direct comparison could be undertaken between experimentally (laboratory) and numerically (history-match) determined curves. An examination of the heavy-oil/water relative permeability data led to the following observations regarding endpoints. 1. The typical range encountered for irreducible water saturation is between 10 and 40%. Laboratory-measured irreducible water saturations in unconsolidated sandpacks can be lower, but can approach 40% as temperature increases. 2. Residual oil saturations (ROS's) have been reported to be as high as 50% of the pore space. This high saturation is a result of fingering, which occurs when water displaces a viscous oil. With increasing temperature and a subsequent decrease in oil-to-water viscosity ratio, ROS's have been found to decrease to as low as 10%. 3. Endpoint relative permeabilities, based on the absolute permeability of the porous medium, are generally greater than 0.6 for oil at irreducible water saturation and less than 0.3 for water at ROS. The ratio of oil-to-water endpoint relative permeabilities was generally found to be larger than about 2.5, which agrees with the values reported by Craig for water-wet systems. It is with noting that the endpoint water relative permeability was higher for imbibition than for drainage in most cases.
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