A number of solvent-based processes for the recovery of heavy oil have been proposed in recent years. One of the phenomena that characterizes all such processes, to varying degrees, is viscous fingering. This paper describes the results of a combined experimental/simulation study aimed at characterizing viscous fingering under conditions typical of heavy oil recovery (very high ratios of oil to solvent viscosity). The study also sheds light on other phenomena that are part of such processes. We describe a set of four experiments carried out in heavy oil saturated sand packs contained within a 30 cm x?60 cm x?1.4 cm visual cell. Three of the experiments involved injection of a miscible, liquid solvent at the bottom of the sand pack, with subsequent upward displacement of the heavy oil; the fourth involved top-down injection of a gaseous solvent. The miscible liquid displacements were dominated by a single solvent finger, which broke through quickly to a producing well at the other end of the sand pack. Observed breakthrough times were consistent with a correlation that describes reported results at lower viscosity contrast. The gaseous solvent experiment exhibited fingering but also had features of a gravity-driven VAPEX process in its later stages. Numerical simulations using a commercial reservoir simulator have been successful in reproducing key features of the experiments. Realistic fingering patterns are produced in the simulations by assuming small, random spatial variations of permeability. The correct modelling of dispersion is crucial in matching the observed phenomena. For gaseous fingering and VAPEX processes, capillary effects are significant and should be included in simulations. Introduction Solvent-based processes for the recovery of heavy oil have attracted increasing attention in recent years. Much of this attention has focused on the Vapour Extraction or "VAPEX" process(1), a solvent analogue of steam assisted gravity drainage (SAGD). However, it has been suggested that for thin reservoirs, and particularly primary-depleted reservoirs, a cyclic solvent process might be preferred. Whereas VAPEX is analogous to SAGD, a cyclic solvent process would be analogous to the cyclic steam stimulation process. A concept for a cyclic process is shown in Figure 1. In this concept, solvent would be injected for a period of time, then oil produced from the same well; and this process would be repeated. A number of questions may be asked about the basic mechanisms of a cyclic solvent process and the resulting efficiency of oil recovery. The work reported here was aimed particularly at understanding the phenomenon of viscous fingering, which characterizes any such process in which a low viscosity solvent is injected into a high viscosity oil. Viscous fingering is an instability phenomenon which occurs when one fluid is displaced by another fluid of lower viscosity. The displacing fluid is said to "finger" into the resident fluid. The two fluids may be either miscible or immiscible, and the displacement may take place in a porous medium or even a Hele- Shaw cell(2, 3).

The "VAPEX" process, a solvent analogue of Steam Assisted Gravity Drainage, has attracted considerable attention as a recovery method for heavy oil. However, to date, there are still many questions about the nature and magnitude of basic process mechanisms, and whether the process can produce economic oil rates. The experiments discussed in this paper were aimed at quantifying some of the basic mechanisms, in particular the dispersive mixing mechanism. We have performed a series of topdown solvent injection experiments under varying conditions, utilizing a CT scanner to monitor fluid movements. All of the displacements we have observed are gravity-unstable in the early stages, and characterized by viscous fingering of the solvent into the 5,500 cP oil. After solvent breakthrough, the displacements become stable, dominated by a single solvent finger which has many of the features of a VAPEX solvent chamber. The "mixing parameter" we infer for these experiments using the Butler/Mokrys analytic model is higher than that reported for Hele-Shaw VAPEX experiments. An analysis of localized fluid velocities in the experiments using numerical simulation shows that the enhanced mixing parameter can be understood as a consequence of convective dispersion in the porous medium. By adjusting the amount of physical dispersion, the simulations can match breakthrough time, post-breakthrough oil rates, and the general character of the fingering. A novel type of "quasi-pore scale" simulation grid appears to provide advantages in simulating the unstable period at the beginning of the displacements. Introduction Compared with steam-based processes such as Steam Assisted Gravity Drainage (SAGD) for recovery of heavy oil, solventbased processes offer the possibility of reduced energy consumption and greenhouse gas production. However, they are mechanistically complex, and questions remain regarding their expected performance. To date, no field data are publicly available to answer these questions. One solvent-based process that has been proposed is the Vapour Extraction (VAPEX) process(1, 2). This solvent analogue of SAGD utilizes gravity as the driving agent, and solvent dilution of the heavy oil as the mobilization mechanism. The concept of the process is illustrated in Figure 1. A practical, solvent-based recovery process will depend for its success on the interplay of a number of phenomena. Some of the most important of these are: diffusion/dispersion, viscous fingering, capillary-driven mixing (in the case of a gaseous solvent), and the effects of reservoir heterogeneity. The first three are accessible for study in the laboratory, and understanding their interplay at the laboratory scale is a first step toward predicting their effects in a field process. Numerical simulation is required both to extrapolate laboratory experience to the field scale, and to incorporate the effects of reservoir heterogeneity. The study described in this paper addresses the phenomena of diffusion/dispersion and viscous fingering based on a series of laboratory experiments, combined with numerical simulation. Our initial experiments utilized a liquid solvent; therefore capillary mixing effects were absent. Future work will extend the results to gaseous solvents.

Experimental results for bitumen recovery from oil sands by continuous and cyclic injection of several steam-flue gas combinations are presented in this paper. Steam, steam-CO2, steam-N2 and steam-CO2-N2 mixtures were injected (3.55 MPa and 100% steam quality into an oil sand test bed which contained a high permeability communications path between injection and production wells. The concentrations of flue gas (N2 + CO2) and carbon dioxide in steam were designed to simulate those which would be produced from a "down-hole " steam generator which uses either air or oxygen. The test results show that the addition of flue gas to steam substantially improves both rate and ultimate recovery of bitumen as compared to that obtained by steam-alone. The steam-CO2 mixture was superior to either steam-N2 or the steam-flue gas combinations. Introduction Oil sand is a complex mixture which contains mineral matter (primarily quartz and feldspar), organic materials (bitumen), gases and water with bitumen and water saturations up to 15% and 2% by weight, respectively. The oil sand has a permeability of about 3.0 µm2 and a porosity of about 32%. The viscosity of bitumen varies considerably and in some cases reaches values about 1000.0 Pa.s at reservoir conditions (15 °C). The technology of exploiting the oil sand deposits by surface mining has been proven in the last few years. However, the available oil sand resource which is surface-mineable accounts for only about 10% of the total available deposit, with the remaining 90% uneconomically mineable due to excessive overburden depth. For the deeper portions of the oil sand deposits, the technology of in-situ extraction has received considerable interest during recent years. In general, in-situ methods involve some means of reducing the viscosity of and then displacing bitumen to a production well. Injection of a hot fluid into the oil sands (most commonly steam) is normally used. Addition of solvents, gases or solvent-gas combinations may also be used in conjunction with steam. Two methods of steam injection have been employed: single well steam stimulation and steam drive. In this paper, the primary focus will be on the steam drive process. At reservoir conditions, most commonly, the first step in a steam drive process is establishment of communication between injection and production wells. Thereafter, the recovery process comprises of channeling of the steam, heating of the adjacent oil layer(s) by conduction and displacement of the heated oil by an entrainment process(1) in which healed oil is displaced toward the producing well by flowing steam and condensed water. Interaction between fluids flowing in the communication path and the surrounding formation is a very important part of the recovery process. There appears to be a dynamic balance between the rate of heat transfer from the steam zone to the adjacent oil layers and the flow displacement processes in the interface region between the steam zone and the oil zone. This balance can result in the occurrence of an optimum injection rate.

A solvent-assisted gravity drainage process (Vapex) for recovery of heavy oil or bitumen offers high recoveries and promising rates of oil production. In order to predict process performance, data on solvent-oil solubility and on the viscosity of solvent-oil mixtures must be obtained. The solubility of selected gasses in Lloydminster Aberfeldy oil and in a Cold Lake oil was measured. The gasses used were: CH4, C2H6, C3H8 and CO2. Measurements were done at reservoir temperature.The data were regressed using the Peng-Robinson equation of state, which was used to generate k-values expressing the solubility of the gas-oil systems. Regressing the Peng-Robinson equation to the measured data generated interaction coefficients for the systems measured. These coefficients were used with the equation to generate k-value or solubility tables at other conditions. Measured viscosity data were used to confirm the usefulness of the Puttagunta viscosity correlation for propane-based heavy oil systems. The work confirmed the formation of two liquid phases in the oil-propane system at high solvent loading. The measurements also confirmed the large viscosity reductions available (100:1–200:1) by saturating oil with light hydrocarbons. A viscosity increase in one oil-propane system was observed at high solvent loading, suggesting possible asphaltene precipitation and/or deposition on the walls of the capillary viscometer tube. These observations confirmed the need to study phase behaviour and asphaltene deposition in the oils at high solvent loading, as well as obtaining solubility and viscosity measurements. The data have been used to perform numerical simulations of Vapex and other solvent-based processes, and to perform predictions of field process performance. Introduction Thermal recovery processes have been used successfully on many Alberta bitumen and heavy oil reservoirs. Some reservoirs, however, are not suited to thermal processes. This may be due to depth, unfavorable mineralogy, bottom water, thin pay sections, or a combination of these factors. For these reservoirs, a non-thermal process may be more suitable.The most likely candidate is a Vapex-type process, where oil is contacted by solvent vapour. The vapour dissolves in the oil, and diluted oil drains to a production well. The application of this technology to heavy oil recovery requires confident prediction of the process performance for a field-scale operation. This in turn requires knowledge of the mechanisms active in the process, and of the magnitude of each of these mechanisms. Mechanisms identified to date include solubilization of the solvent in oil, mass transfer from vapour to liquid phases by diffusion, mixing of diluted and undiluted oil by diffusion and dispersion, reduction of the oil viscosity by solvent dilution, and upgrading of the oil by asphaltene precipitation and deposition. This work measured solubility and viscosity of several oil-solvent systems.

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