Wettability Effects in Thermal Recovery Operations
- Dandina N. Rao (Louisiana State U.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- October 1999
- Document Type
- Journal Paper
- 420 - 430
- 1999. Society of Petroleum Engineers
- 4.3.4 Scale, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 1.8 Formation Damage, 5.4.6 Thermal Methods, 2.4.3 Sand/Solids Control, 5.4.1 Waterflooding, 1.6.9 Coring, Fishing, 5.8.7 Carbonate Reservoir, 5.2 Reservoir Fluid Dynamics, 5.5.2 Core Analysis, 2.7.1 Completion Fluids, 4.1.2 Separation and Treating, 4.3.3 Aspaltenes, 5.5.8 History Matching, 4.1.4 Gas Processing, 5.8.5 Oil Sand, Oil Shale, Bitumen
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Do the three-phase oil-water-rock systems remain unaltered in wettability or do they become more strongly water- or oil-wet when the reservoir temperature is increased during thermal recovery operations? The published literature provides an affirmative support to each of the three possible answers to this question. Should we let this controversy continue or is it time to put together different pieces of the puzzle to reach at least a semblance of a solution? The latter is the purpose of this paper.
This paper aims to shed more light on the controversy surrounding the effect of temperature on wettability by bringing together the various schools of thought on this subject under a simple mechanistic explanation involving an interrelationship between the spreading behavior in solid-liquid-liquid (SLL) systems and the liquid-liquid interfacial tension, and thin wetting film stability considerations. This paper extends the Zisman-type correlation between contact angles and surface tension in solid-liquid-vapor (SLV) systems to the SLL systems. The success achieved in establishing such a correlation in this study is of practical significance in that it shows a way of identifying crucial wettability changes that may occur in secondary and tertiary recovery processes through simple laboratory experiments involving interfacial tension and contact-angle measurements. This would help in recovery process selection and optimization.
The paper also describes a technique, which was discovered during the course of this experimental study, to prevent adverse wettability shifts in thermal operations. The technique involves in-situ deposition of small quantities of calcium carbonate (scale) particles near the wellbore region to maintain a strongly water-wet region of high relative permeability to crude oil. Encouraging results from an Alberta field test of this technology are also presented.
Thermal recovery operations impose a major change in the important thermodynamic variable, namely, temperature, of the reservoir rock-fluids system. Although reduction in oil viscosity may be its main purpose, the rise in temperature of the system affects almost all the variables (such as the density and viscosity of the individual phases, interfacial properties of oil-water-gas interfacial tensions and the interfacial energies involving the solid surface and its mineral transformations), that have either a direct or an indirect influence on the movement of oil-water-gas phases in the porous rock medium. In other words, the thermal energy imposed on the system introduces changes not only in fluid properties and fluid-fluid interactions, but also in rock-fluids interactions. Characterizing wettability change with temperature would be one convenient and useful way to lump all of the above-mentioned property variations into one overall effect of reaching a new thermodynamic state at an elevated temperature. However, a quick look at the literature on this subject of temperature dependence of wettability makes it obvious that the existing situation is not simple but quite complex. This complexity appears to be due not only to the three distinct schools of thought on the effect of temperature on oil-water relative permeabilities, but also due to the scatter of information across several scientific fields. It is the purpose of this paper to bring together some of this scattered information with the hope of gaining a better understanding of the probable mechanisms behind the widely differing experiences with temperature dependence of reservoir wettability.
Background on the Effect of Temperature on Wettability
Since there is no single accepted method of characterizing reservoir wettability, we need to consider several of the techniques normally used, namely, contact angle, Amott test, and USBM test as well as the qualitative technique involving the oil/water relative permeabilities from waterflooding experiments.
Corefloods and Relative Permeability Studies.
The effect of temperature on oil/water relative permeabilities is perhaps one of the most extensively studied aspects of flow through porous media for nearly four decades. Several studies1-3 have been published over the years that include summary and/or review of these works. Therefore, a detailed discussion of this subject is not attempted in this paper except to comment on some of the more recent studies.
Okoye et al.4 provide a brief review of the literature on the effect of both temperature and oil-water interfacial tension on relative permeability. They found from their coreflood experiments that oil-water relative permeability curves for high- and low-tension systems shifted to the right or higher water saturations with increasing temperature. They also concluded that for a given temperature the oil-water relative permeability ratio curves also shifted towards higher water saturations with increasing interfacial tension.
Polikar et al.3 provided summary tables of previous works on temperature effects on relative permeability for both consolidated and unconsolidated porous media. Further, they observed in their experimental study that significant temperature effects were absent in the Athabasca bitumen-water system in clean and reservoir sands because of lack of reactivity between fluid/solid combinations. Rivas,5 upon comparing the model calculations with published experimental measurements, noted that the reservoirs which are partially or totally oil-wet at low temperatures, become more water-wet as the temperature was increased and that the temperature rise did not affect the wettability of the reservoirs that were initially water-wet.
Olsen6 has presented some coreflood results depicting the effect of wettability on light-oil steam flooding. He observed sudden increases in oil production (or decrease in oil saturation) in oil-wet, intermediate-wet, and water-wet cores. In the case of the oil-wet core, this increased production was attributed to gradual shifting of wettability towards water-wet behavior and oil banking. This study also indicated that the final oil saturation (which ranged between 8 and 10%), after steam flooding, was nearly independent of initial wettability.
Bennion et al.7 measured unsteady-state relative permeability for preserved sandstone cores and found that the endpoint water relative permeability increased quite significantly at 220°C over that at lower temperatures. This led them to conclude that at elevated temperatures the system shifted to oil-wet behavior.
Bennion et al.8 measured steady-state bitumen-water relative permeabilities at 200°C in preserved cores and concluded that the rock-fluids system behaved as a water-wet system at elevated temperature. However, they did not report similar measurements at lower temperatures to enable comparison or to determine whether a wettability shift has indeed occurred or not. Their data show very low initial water saturations (3 to 7%) and modest endpoint oil relative permeabilities (from 67 to 80% of the absolute permeability) which are not quite typical of water-wet systems.
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