An Investigation of the Steam-Assisted Gravity-Drainage Process in the Presence of a Water Leg

Abstract

Abstract Many heavy oil and oil sand reservoirs are in communication with water sand(s). Depending on the density (°API gravity) of oil, the water sand could lie above or below the oil zone. Steamflooding a heavy oil or oil sand reservoir with a contiguous water sand (water which may lie below or above the oil-bearing zone) is risky due to the possibility of short circuiting the steam chamber. The Steam Assisted Gravity Drainage (SAGD) process was first tested at the Underground Test Facility (UTF) in Fort McMurray, Alberta. The successful application of this process to Athabasca-type oil sands has extended its application to other heavy oil and oil sands reservoirs. To date, the application of this process to a variety of different reservoirs has shown mixed results due to a variety of reasons. In our opnion, the success of these projects depends on: 1) accurate reservoir description, 2) efficient utilization of heat injected into the reservoir, 3) understanding displacement mechanism, 4) understanding of geomechanics (the interaction between the fluids and the reservoir at elevated temperatures and pressure), and 5) overcoming various operational constraints. This paper looks at how the SAGD process is affected by the presence of water sand, and determines how heat is distributed in these reservoirs. Results of this numerical simulation study show a relationship between ultimate recovery, heat accumulated in the reservoir and the thickness of the water sand (bottom or top water). For the base case run, an average rate of 80 m3/d was maintained for 1400 days before it started to decline. Ultimate recovery was approximately 70% of the OOIP after 9 years of steam injection, and the cumulative OSR was 0.3 m3/m3 (CWE). The presence of a bottom water sand has a lesser impact on recovery than the case where an overlying water sand is present. As the thickness of the water sand increases, the recovery efficiency decreases. Increasing the areal coverage of the bottom water sand resulted in slightly reduced recovery as compared with the confined bottom water sand. On the other hand, increasing the areal coverage of the overlying water sand, that is 9m thick, severely reduced the recovery efficiency of the process as heat is diverted (or channeled) into the "thief" zone. The oil steam ratio (OSR) in this run was below 0.15 m3/ m3 (CWE) after 400 days of injection. When a bottom water layer is present, the BHFP (bottom hole flowing pressure) of the horizontal producer could be operated at or above the pressure of the aquifer to prevent water coning and hence only effecting the heat source slightly.