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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.

The manipulation of a nanoconfined fluid flow is a great challenge and is critical in both fundamental research and practical applications. Compared with chemical or biochemical stimulation, the use of temperature as controllable, physical stimulation possesses huge advantages, such as low cost, easy operation, reversibility, and no contamination. We demonstrate an elegant, simple strategy by which temperature stimulation can readily manipulate the nanoconfined water flow by tuning interfacial and viscous resistances. We show that with an increase in temperature, the water fluidity is decreased in hydrophilic nanopores, whereas it is enhanced by at least four orders of magnitude in hydrophobic nanopores, especially in carbon nanotubes with a controlled size and atomically smooth walls. We attribute these opposing trends to a dramatic difference in varying surface wettability that results from a small temperature variation.

This paper presents an alternative semi-analytical model which is able to integrate PVT properties of gas with dynamic pressure domain during production process. A modified three-region radial composite model is developed to evaluate the gas condensate reservoir, taking account of different gas flow behaviors and pressure dependent properties, such as the compressibility factor. The governing equation of the pressure diffusion process is highly nonlinear due to the complex dependence of coefficients on pressure. The linearization of the non-linear partial differential equation describing the complicated gas flowing in a reservoir is handled by application of reasonable definitions of pseudo-pressure and pseudo-time for each region, which is integrated into the reservoir system through physical continuity of changing phases with PVT properties. Modified forms of total compressibility factor are proposed by valid theoretical developments. Results show that gas compositions of a gas condensate reservoir have significant effects on the fluid flow behaviors. Different proportions of C 5 , C 6 and C 7 + are simulated with constant makeup of C O 2 , N 2 and C 1 ∼ 4 , showing that small changes in composition of heavier components make distinct differences in the flow behaviors, as reflected on the liquids dropout curves. In addition, total compressibility factor varies with fluid compositions instead of remaining constant in a gas condensate reservoir. Through integrating PVT behaviors, the three-region model is able to accurately describe transient pressure behaviors of a production well in a gas condensate reservoir, which clearly characterizes three regions on the pressure derivative curves. A series of sensitivity studies are conducted to analyze the differences among the three regions.

Viscosity reduction through solvent dissolution into heavy oil is one of the most important recovery mechanisms of a vapour extraction (VAPEX) process. Existing analytical models can neither accurately describe the mass transfer between solvent vapour and heavy oil nor predict the solvent chamber evolution. Simulation models are confounded by numerical dispersion and have a difficulty in accurately characterizing fluid properties in VAPEX. This study first develops a mass transfer model to describe a dynamic heavy oil–solvent mixing process. This model is then incorporated into a VAPEX model to estimate solvent chamber development and an oil production rate. Diffusivity is determined through history matching theoretically calculated and experimentally measured cumulative oil production data. It is found that both constant and variable diffusivities can achieve excellent match in cumulative oil production data. However, their respective characterization of the fluid properties in the VAPEX transition zone is very different. This study also proposes a method to convert constant diffusivity into its equivalent variable diffusivity for VAPEX by using some regressed correlations. Moreover, the back-calculated effective diffusivity is found to be about 10–30 times of the corresponding molecular diffusivity measured in the laboratory. This article is protected by copyright. All rights reserved

Steam-assisted gravity drainage (SAGD) is one of the most popular approaches for oil sands recovery. In this study, an accurate and simple heat efficiency calculation model is presented by modeling transient heat transfer involving the flow of both hot condensate and mobile initial water in oil sands. A 2-D numerical simulation procedure is proposed to calculate temperature distribution ahead of the steam chamber edge in SAGD. A new heat efficiency model is proposed to estimate heat efficiency in SAGD by using the temperature distribution obtained from the 2-D numerical simulation. Results indicate that convection dominates the heat transfer ahead of the steam chamber edge which is induced by condensate and initial water flow in oil sands. On the basis of these studies, abundant analysis shows that the heat efficiency of SAGD can be improved by using moderate steam injection pressures for the reservoir scenarios from 1 to 10 darcy permeability.

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.

In a cyclic solvent injection (CSI) process, a vaporized solvent is cyclically injected, soaked, and released to produce heavy oil. Through this process the operating pressure is increased and decreased periodically. This causes a dynamic fluid flow across a heavy oil–solvent mixing zone, leading to a convective mass transfer in addition to molecular diffusion. This study aims at modeling the effect of convection on the heavy oil–solvent mass transfer in the transition zone of the CSI process. A convection–diffusion mathematical model is developed and semi-analytically solved. It consists of two sub-models, a pressure model and a solvent concentration model, and considers realistic viscosity and convection velocity profiles. Three practical injection and production schemes are modeled in order to provide some meaningful suggestions for the CSI field applications from the viewpoint of mass transport. Results show that convection can significantly enhance solvent dissolution during the injection period and accelerate solvent exsolution during the production period. In addition, it is also found that a smaller solvent injection rate does not make a big difference in the solvent dissolution for a long injection period. Moreover, during the production period, solvent exsolution induces a sharp pressure gradient that is believed to be a key factor for foamy-oil flow. It causes a viscosified front and solvent “inverse” diffusion that results in several rounds of foam-oil flow. Finally, a considerable amount of solvent remains dissolved in heavy oil at the end of the production period when the reservoir pressure is depleted, and is difficult to be retrieved in a short time.

Solvent-based recovery processes, such as cyclic solvent injection and its variants, have shown a great potential to enhance heavy oil recovery after cold heavy oil production with sands. In such processes, pressure is increased and reduced in a cyclic manner to induce foamy oil flow, which is a key production mechanism. Previous conclusions of foamy oil flow in primary production may have limitations for cyclic processes since the fluid properties and operating conditions are fairly different. This study first conducted an experimental study to visualize the foamy oil flow in a scaled physical model under realistic reservoir conditions. Pseudo-bubble points at different stages of the test are recorded. Then a mathematical model is developed to simulate the experimental observations. This model reasonably couples pressure diffusion and mass transfer together, and considers dynamic properties of gas, foamy oil and diluted oil. Experimental observations show that the oil zone remains relatively stable before pressure drops to a certain level. Afterwards, the oil front moves explosively inwards the solvent chamber, indicating a flow of foamy oil. Theoretical modeling results show that the pressure gradient at the oil-gas zone interface increases from zero at the beginning to a considerable value during a drawdown process. The foamy oil flows only when the pressure gradient reaches a certain level, and a larger drawdown rate tends to result in a higher pressure gradient and a higher pseudo-bubble point. In addition, at the same pressure drawdown rate, the foamy oil flow at a later stage is expected to happen more quickly than at an earlier stage.