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Viscosity reduction through heat transport from steam to bitumen is one of the most important recovery mechanisms of a steam-assisted gravity drainage (SAGD) process. Both heat convection and conduction contribute to the heat transport. Although conduction is considered as dominant through most of a SAGD process, an understanding of heat convection, especially accurate modeling of a condensate convection velocity, is still limited in the literature. This paper develops a mathematical model for the transient heat transfer beyond a steam chamber boundary in SAGD. A convection velocity is clearly formulated, which requires the coupling of heat transport and pressure diffusion. Calculation results show that in SAGD, convection plays a minor role than conduction. In addition, the relative contribution of convection can be influenced by reservoir formation compressibility, steam chamber boundary advancing velocity, and particularly by a difference between steam injection pressure and reservoir initial pressure. Correlations are regressed to estimate the relative contribution of heat convection (ratio) in the overall heat transfer process during a stabilized production period of SAGD.

In a vapor extraction (VAPEX) process, a vaporized solvent (such as light alkanes) is injected underground to dilute and recover heavy oil. A solvent chamber forms due to the depletion of oil, and goes through three phases: rising, spreading, and falling phases during a VAPEX process. Existing analytical models of VAPEX can only roughly estimate an oil production rate but are unable to accurately describe the solvent chamber evolution. Simulation models are somewhat unreliable due to extremely small physical diffusivity and relatively large numerical dispersion. This study develops a comprehensive mathematical model for the VAPEX process to characterize a transition zone and describe the solvent chamber evolution. Major recovery mechanisms occurring in the transition zone such as dynamic mass transfer, gravity drainage, multiphase flow, and surface renewal are accounted for in the model. Modeling results show that the solvent concentration in the transition zone grows slower at the top than at the bottom while rather stable at the middle along the drainage surface. In addition, it is found that a stabilized oil production rate depends on the square root of a heavy oil–solvent effective diffusion coefficient. Moreover, this new VAPEX model can accurately describe the relationship between oil production rates and diffusion coefficients in different scales thanks to the absence of numerical dispersion.

This paper presents a new enhanced heavy oil recovery (EHOR) process, Cyclic Production with Continuous Solvent Injection (CPCSI). In this process, a vapourized solvent near its dew point is continuously injected into the reservoir to maintain reservoir pressure and also supply extra gas drive to flush the diluted oil out through an injector that is located on the top of the reservoir; while a producer, which is located at the bottom of the reservoir, is operated in a shut-in/open cyclic way. A series of experiments have been conducted to evaluate the CPCSI performance. The recovery factors (RFs) are up to 85% of original oil in place (OOIP) in 1-D tests, and the RF is improved by 11% by using the 2-D lateral CPCSI, compared with the traditional 2-D lateral VAPEX. Well configurations and the producer shut-in/open scenarios are key optimization factors that affect the CPCSI performance. Experimental results show that the foamy oil flow and solvent trap are the two major EHOR mechanisms for enhancing the oil production rate during the production period. In comparison with continuous injection process, such as vapour extraction (VAPEX), and cyclic injection process, such as cyclic solvent injection (CSI), CPCSI offers free gas driving, and the reservoir pressure is maintained during the producer opening period so that the diluted oil viscosity is kept low. This work shows that CPCSI could be an alternative optimization production scenario for applying solvent based in situ EHOR techniques for heavy oil reservoirs in Western Canada.