Steam Injection Strategy and Energetics of Steam-Assisted Gravity Drainage
- Ian Donald Gates (U. of Calgary) | Joseph Kenny (ATECH Application Technology Ltd.) | Ivan Lazaro Hernandez-Hdez (ATECH Application Technology Ltd.) | Gary L. Bunio (Paramount Resources Ltd.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 2007
- Document Type
- Journal Paper
- 19 - 34
- 2007. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 4.3.4 Scale, 4.1.5 Processing Equipment, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.5 Reservoir Simulation, 5.6.4 Drillstem/Well Testing, 5.3.9 Steam Assisted Gravity Drainage, 5.4.6 Thermal Methods, 5.5.8 History Matching, 4.6 Natural Gas, 5.1.5 Geologic Modeling, 2.3.3 Flow Control Equipment, 7.2.2 Risk Management Systems, 5.2 Reservoir Fluid Dynamics, 1.7.5 Well Control, 5.4.2 Gas Injection Methods, 5.5.2 Core Analysis, 5.8.5 Oil Sand, Oil Shale, Bitumen, 2.4.3 Sand/Solids Control, 5.5.3 Scaling Methods, 5.6.1 Open hole/cased hole log analysis, 5.5.2 Construction of Static Models, 2.2.2 Perforating, 5.3.2 Multiphase Flow
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Steam-assisted gravity drainage (SAGD) is being operated by several operators in Athabasca and Cold Lake reservoirs in Central and Northern Alberta, Canada. In this process, steam, injected into a horizontal well, flows outward, then contacts and loses its latent heat to bitumen at the edge of a depletion chamber. As a consequence, the viscosity of bitumen falls, its mobility rises, and it flows under gravity toward a horizontal production well located several meters below and parallel to the injection well. Despite many pilots and commercial operations, it remains unclear how to optimally operate SAGD. This is especially the case in reservoirs with a top-gas zone in which pilot data are nearly nonexistent. In this study, a steam-chamber operating strategy is determined that leads to optimum oil recovery for a minimum cumulative steam-to-oil ratio (SOR) in a top-gas reservoir. These findings were established from extensive reservoir-simulation runs that were based on a detailed geostatistically generated static reservoir model. The strategy devised uses a high initial chamber injection rate and pressure prior to chamber contact with the top gas. Subsequent to breakthrough of the chamber into the gas-cap zone, the chamber injection rates are lowered to balance pressures with the top gas and avoid (or at least minimize) convective heat losses of steam to the top-gas zone. The results are also analyzed by examining the energetics of SAGD.
A cross-section of the SAGD process is displayed in Fig. 1. Steam is injected into the formation through a horizontal well. In Fig. 1, the wells are portrayed as points that extend into the page. Around and above the injection well, a steam-depletion chamber grows. At the edge of the chamber, heated bitumen and (steam) condensate flow under the action of gravity to a production well typically placed between 5 and 10 m below and substantially parallel to the injection well. Usually, the production well is located several meters above the base of pay. In industrial practice (Singhal et al. 1998; Komery et al. 1999), injection and production well lengths are typically between 500 and 1000 m. Because the steam chamber operates at saturation conditions, the injection pressure controls the operating temperature of SAGD.
SAGD has been piloted extensively in Athabasca and Cold Lake reservoirs in Alberta (Komery et al. 1999; Butler 1997; Kisman and Yeung 1995; Ito and Suzuki 1999; Ito et al. 2004; Edmunds and Chhina 2001; Suggett et al. 2000; Siu et al. 1991; AED 2004) and is being used as a commercial technology to recover bitumen in several Athabasca reservoirs (Yee and Stroich 2004). These pilots and commercial operations have demonstrated that SAGD is technically effective, but it has not been fully established whether its operating conditions are at optimum values. This is especially the case in reservoirs in contact with gas or water zones where the optimum operating strategy remains unclear. The variability of the cumulative injected-steam (expressed in cold water equivalents, or CWE) to produced-oil ratio (cSOR) shows that some SAGD well pairs operate fairly efficiently (with cSOR between 2 and 3), whereas others operate at much greater cSOR (up to 10 and higher) (Yee and Stroich 2004). Higher cSOR means that more steam is being used per unit volume bitumen produced. The higher the steam usage, the greater the amount of natural gas combusted, and the less economic the process.
One key control variable in SAGD is the temperature difference between the injected steam and the produced fluids. This value, known as the subcool, is typically maintained in a form of steamtrap control between 15 and 30°C (Ito and Suzuki 1999). The subcool is being used as a surrogate variable instead of the height of liquid above the production well. The liquid pool above the production well prevents flow of injected steam directly from the injection well to the production well, thus promoting injected steam to the outer regions of the depletion chamber and enabling delivery of its latent heat to the bitumen. The value of the optimum steamtrap subcool temperature difference and how the operating pressure impacts the optimum subcool value remains unclear. It also remains unclear how the subcool should be controlled in heterogeneous reservoirs that have top gas.
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