Steam Alternating Solvent Process
- Litong Zhao (Alberta Research Council)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 2007
- Document Type
- Journal Paper
- 185 - 190
- 2007. Society of Petroleum Engineers
- 5.4.10 Microbial Methods, 5.3.9 Steam Assisted Gravity Drainage, 4.1.2 Separation and Treating, 4.3.4 Scale, 4.1.5 Processing Equipment, 5.2.1 Phase Behavior and PVT Measurements, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.5 Reservoir Simulation, 5.4.6 Thermal Methods, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4.2 Gas Injection Methods, 7.4.3 Market analysis /supply and demand forecasting/pricing
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A new heavy-oil-recovery process, the steam alternating solvent (SAS) process, is proposed and studied using numerical simulation. The process is intended to combine the advantages of the steam-assisted gravity drainage (SAGD) and vapor-extraction (vapex) processes to minimize the energy input per unit oil recovered. The SAS process involves injecting steam and solvent alternately, and the basic well configurations are the same as those in the SAGD process.
Field-scale simulations were conducted to assess the SAS process performance under typical Cold Lake, Alberta, reservoir conditions. These results suggested that the oil-production rate of an SAS process could be higher than that of a SAGD process, while the energy input was 18% less than that of a SAGD process. By varying the length of the steam- and solvent-injection periods in a cycle, a different set of steam/oil and solvent/oil ratios may be obtained because the temperature profiles and solvent-concentration distributions in the vapor chamber can be affected by the injection pattern. The process therefore can be optimized for a specific reservoir under certain economic conditions.
There are large heavy-oil and bitumen deposits in many areas of the world. The resources are especially enormous in northern Alberta, Canada. However, the high viscosity of these oils, usually more than 10 000 mPa×s, hinders the recovery of these resources. To recover such petroleum resources, two types of methods exist for the reduction of oil viscosity. The first is to increase oil temperature. This can be achieved by injecting a hot fluid, such as steam, into the formation, or by in-situ combustion through injecting oxygen-containing gases. The second method is to dilute the viscous petroleum by lower-viscosity hydrocarbon solvent. This method involves injecting a hydrocarbon solvent, such as propane or butane, or a mixture of hydrocarbons into the oil reservoir. As the solvent dissolves into viscous oil, the viscosity of the mixture becomes much lower than the original viscosity of the heavy oil. The diluted oil then can be recovered.
The combinations of the above viscosity reduction methods and the horizontal-well technology have been the focus of research for the past 20 years. Two processes, SAGD and vapex, have been developed for the recovery of heavy-oil and bitumen resources (Butler et al. 1981; Butler and Mokrys 1991; Frauenfeld and Lillico 1999). The first has been tested successfully in the field and is currently the process of choice for commercial in-situ recovery (Edmunds et al. 1994; Mukherjee et al. 1995), while the second is starting initial field testing (Butler and Yee 2000). The advantage of the SAGD process is its high recovery and high oil-production rate. However, the high production rate is associated with excessive energy consumption, CO2 generation, and expensive post-production water treatment. The vapex process has the advantage of lower energy consumption (and, therefore, less CO2 generation) and much lower water-treatment costs. The major drawback of the vapex process, however, is its expected relatively lower oil-production rate and the uncertainty on reservoir retention of solvent.
In the past several years, modifications have been proposed to improve SAGD's energy efficiency, either through injection of noncondensable gas with steam for reducing heat loss (Jiang et al. 1998) or through injection of solvents and steam together for increasing production rate (Nasr and Isaacs 2001). The combination of solvent with steam also has been studied in the steamflooding process (Farouq Ali and Abad 1976; Venturini and Mamora 2003).
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