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Collaborating Authors
Results
Design of the Steam and Solvent Injection Strategy in Expanding-Solvent Steam-Assisted Gravity Drainage
Gates, I.D. (Alberta In Situ Centre for In Situ Energy (AICISE), Schulich School of Engineering, University of Calgary) | Chakrabarty, N. (Alberta In Situ Centre for In Situ Energy (AICISE), Schulich School of Engineering, University of Calgary)
Abstract Steam-Assisted Gravity Drainage (SAGD) is a commercial in situ recovery technology that is effective at recovering heavy oil and bitumen. However, generation of steam by combusting natural gas adversely impacts the economics of the process, especially when natural gas price is high as has been the case lately. It has been shown that solvent additives can improve oil production rates or at least maintain similar oil production rates with reduced steam injection. This is the basis of the Expanding Solvent Steam Assisted Gravity Drainage (ESSAGD) process. The key idea is that steam plus solvent is better than steam alone to mobilize heavy oil in the reservoir. This implies that ES-SAGD can potentially use less water and require smaller water handling and treatment facilities than that in SAGD. One key capability of ES-SAGD is that the recovered solvent can be recycled and re-injected into the reservoir. However, if too much solvent is injected and too little is recovered, the process can be uneconomic because the solvent is often more valuable than the produced heavy oil. In this research, the solvent injection strategy is designed for a single wellpair ES-SAGD operation by optimizing the net energy injected to oil ratio in a detailed and realistic, threedimensional, heavy oil reservoir. The process parameters for design include the operating pressure and relative amounts of steam and solvent in the injected stream. The results show that the operating pressure and injection strategy must be carefully controlled to ensure high energy efficiency and solvent recovery. Introduction At in situ native conditions, the viscosity of Athabasca bitumen is typically greater than one million centipoise, often ranging between two and six million centipoise. The key barrier to be overcome for producing bitumen from Athabasca reservoirs is to mobilize it in the reservoir, that is, lower its viscosity sufficiently so that it readily flows in the reservoir to a production wellbore. There are several means to do this: first, heat the bitumen to sufficiently high temperature, second, dissolve solvent in the bitumen and dilute it, and third, induce a compositional change of the oil that leads to a mobile oil phase, e.g. asphaltene precipitation or in situ upgrading. The effect of temperature on the viscosity of Athabasca bitumen is plotted in Figure 1 (Mehrotra and Svrcek, 1986) and is taken advantage of in the Steam-Assisted Gravity Drainage (SAGD) process (Butler, 1997). SAGD is now considered a commercial technology to produce Athabasca and Cold Lake bitumen reservoirs of Alberta (Komery et al., 1999; Butler, 1997; AED, 2004; Yee and Stroich, 2004; Scott, 2002). Typically, the original temperature of Athabasca reservoirs ranges from 7 to 11 ยฐC. The correlation displayed in Figure 1 shows that the viscosity falls by four orders of magnitude after the bitumen is heated by 100 ยฐC. Figure 1 reveals that the viscosity of Athabasca bitumen drops to less than 10 cP (could consider this as a target oil phase viscosity to enable sufficient production from SAGD) after its temperature exceeds about 196 ยฐC
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract Many field tests of the Steam-Assisted Gravity Drainage (SAGD) process have been conducted and have shown that the process is a technically effective one at extracting oil from heavy oil and bitumen reservoirs. However, it has not been firmly established whether the technology is operated at optimized conditions to yield maximum economic returns. This is especially important because typically SAGD depends on combustion of natural gas to generate steam and this is the dominant cost. This is especially important when natural gas prices are high. This research evaluates the use of a genetic algorithm optimization scheme to control a commercially available thermal reservoir simulator to optimize the steam injection strategy to reduce the cumulative oil to steam ratio (cSOR). The reservoir description is typical of that from Athabasca reservoirs. The results show that the injectionstrategy, for an individual wellpair, can be altered to reduce the cSOR up to 50% from a uniform injection pressure strategy to one after the steam injection strategy has been optimized. The optimized profile has high steam injection pressure at the beginning of the process before the steam chamber reaches the top of the reservoir. Before the chamber reaches the overburden, with high injection pressure, the saturation temperature is high and there are no thermal losses to theoverburden. After the chamber reaches the top of the formation, the injection pressure is lowered throughout the remainder of the process. This reduction of injection pressure implies that the saturation temperature falls and consequently the losses to the overburden are lowered. Thus the overall thermal efficiency of the process is enhanced. The optimized strategy is compared to processes operating at 1000 and 2000kPa constant injection pressure. Introduction Steam-Assisted Gravity Drainage (SAGD) has now been extensively tested and in commercial production in the Athabasca and Cold Lake regions of Alberta (Komery et al., 1999; Butler, 1997; AED, 2004; Yee and Stroich, 2004; Scott, 2002). The majority of existing SAGD projects are based in Alberta, Canada: more than nine are located in the Athabasca region (the McMurray formation), one in the Peace River region, (the Bluesky formation), four are in the Cold Lake region (the Clearwater formation, one other in the Grand Rapids formation), and five are in Saskatchewan (the Grand Rapids formation). The SAGD process, displayed in Figure 1, was developed by Butler (1997) while at Imperial Oil in the late 1970s. The process consists of two aligned horizontal wellbores: steam is injected into the top one whereas reservoir fluids are produced from the bottom one. The process is non-cyclic, that is, steam is continuously injected and fluids are continuously produced. Around and above the injection well, a steam chamber grows. The injected steam flows into the steam chamber and eventually comes into contact with oil sand at its edge. The steam thenreleases its latent heat to the oil sand, the oil heats up, its viscosity drops, and it flows (with water condensate) under gravity down the inclined chamber edge to the production well.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Clearwater Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Bluesky Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > McMurray Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Hangingstone Oil Sands Project (0.99)