Steamflooding Cold Lake Oil Reservoirs Through a Bottomwater Zone: A Scaled Physical Model Study
- T.N. Nasr (Alberta Research Council) | G.E. Pierce (Alberta Research Council)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- May 1993
- Document Type
- Journal Paper
- 94 - 100
- 1993. Society of Petroleum Engineers
- 5.4.6 Thermal Methods, 1.7.5 Well Control, 4.3.4 Scale, 6.5.5 Oil and Chemical Spills, 2.4.3 Sand/Solids Control, 5.2.1 Phase Behavior and PVT Measurements, 5.1.5 Geologic Modeling, 5.8.5 Oil Sand, Oil Shale, Bitumen
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A series of experiments was conducted in one-eighth of a five-spot-pattern, high-pressure, scaled physical model to evaluate the potential of steamflooding oil-sand reservoirs through a bottomwater zone in Cold Lake, Alta. During the experiments, steam was injected into the bottomwater zone at a constant rate until steam breakthrough occurred at the production well. The steam injection rate then was reduced to limit steam production. Results demonstrate that the process is influenced by the steam injection flow rate because of the important role played by gravity override. Increasing the steam injection rate beyond an optimum value results in decreased oil/steam ratios (OSR's) and reduced final oil recovery because steam channels to the production well. A delay in oil production was noticed in all experiments. A moving-heat-source, gravity-override, analytical model was used to investigate the mechanisms of reservoir heating in the presence of steam-gravity override. In addition, the thermal efficiency of the process, determined from the experiments and extrapolated to field conditions, was compared with predictions from Prats' thermal efficiency model. Prats' model predicted the measured thermal efficiency reasonably well at lower injection rates. As the injection rate increased, however, larger differences between Prats' model and the experiments were noticed.
In Alberta, the presence of a bottomwater zone with a high water saturation is common in Cold Lake, Peace River, Wabasca, and other oil-sand deposits. Such zones are beneficial in high-viscosity reservoirs because they provide initial injectivity of hot fluids. The efficiency of steam injection processes into reservoirs with bottomwater zones depends on the thickness ratio of the bottomwater to oil zone, oil saturations in the oil sand and bottomwater zones, permeabilities, steam injection rate, and injection strategies used. In these processes, steam, injected into a horizontal water zone, rises vertically by gravity override into the oil layer , heating the bitumen. The heated and mobilized bitumen is displaced in a countercurrent direction into the underlying water sand and then is swept toward the producing well.
To support exploitation of Peace River oil sands, Prats1 conducted a large number of experiments in a vacuum scaled model. The Peace River oil sands have a thick pay zone (27 m on average) overlying a high-permeability bottomwater zone with an average thickness of about 6.0 m; the permeability of the bottomwater zone is about six times greater than the permeability of the oil-sand zone. The bottomwater zone is partially oil-saturated (an average oil saturation of 60%). Prats found that pressure cycling was the best injection strategy. In the steamflooding process, steam channels to the production well through the high-permeability, underlying bottomwater zone, reducing the efficiency of the process. For the past 10 years, operation and production performance of the Peace River In-Situ Pilot have met original expectations.
Huygen and Lowry2 used a high-pressure scaled model to study steamflooding of the Wabasca oil sands in the presence of bottomwater zones. The Wabasca deposit contains a highly viscous oil (1.03 g/cm3 at 13°C). The oil sand is 10 m thick and overlies a 2.5-m bottomwater zone. Huygen and Lowry used a constant steam injection rate throughout the flooding process. Results indicated that oil recovery was sensitive to the steam injection rate. Higher injection rates resulted in a higher oil recovery; however, a maximum OSR was obtained at an intermediate injection rate.
Singhal3 evaluated the potential of steamflooding a heavy-oil reservoir in a scaled physical model. The study demonstrated that the hot condensate ahead of the steam zone exhibited severe fingering and channeling, which resulted in an early water breakthrough at the production well. The steamflooding process was characterized by steam-gravity override and underrunning of hot condensate. "Pressure cycling" was identified as a strategy for improving heavy-oil recovery. Singhal provided an extensive review of previous work with physical models.
The objective of the present study is to develop oil recovery processes that are as applicable to Cold Lake oil reservoirs with bottomwater zones as those used in Peace River. A high-pressure, scaled, thermal model was used to investigate the potential for steamflooding Cold Lake oil sands in the presence of a communicating bottomwater zone and to determine the effect of the steam injection flow rate on the performance of the process. A controlled steamflooding process was used in which steam was injected initially at a high flow rate until steam breakthrough occurred and then at a reduced flow rate to avoid steam production.
Pujol and Boberg's4 thermal scaling approach for high-pressure models was used in the design of this scaled model because in a steamflooding process, gravity override plays a primary role in the performance of the process, and gravity and viscous forces must be scaled adequately. This approach, however, does not scale capillary pressures and relative permeabilities adequately. Pujol and Boberg investigated the effect of inadequate scaling of capillary pressure and found that, for highly viscous (> 100 000 mPa·s) oils, accurate capillary pressure scaling is not required. For such oils, the ratio of capillary to viscous forces is so low that unsealed capillary pressures have a negligible effect on oil recovery behavior. The relative permeability is difficult to duplicate precisely in different systems. Ehrlich5 investigated the effect of different relative permeability curves for a model and a reservoir and determined that a reasonable, empirical method for comparing oil recoveries in the scaled model and the reservoir is to measure the fraction of movable oil recovered in each case.
Fig. 1 is a schematic of the experimental facility. The three main components are a steam injection system; the scaled model, cap- and base-rock assemblies, pressure vessel, overburden-pressure control, thermocouples, and instrumentation; and the production system. The experiments were performed in a thermal, high-pressure scale model representing one-eighth of a five-spot pattern to simulate a 12.8-m-thick pay zone (k=1.38 µm2, So=80%) underlaid by a 2.2-m bottomwater zone (Sw=100%). A scaling factor of (180)2 was assumed reasonable for scaling time (1 minute in the laboratory corresponds to 22.5 days in the field). For more detail on the experimental procedure see Ref. 6.
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