Interest in the vapor-extraction (Vapex) process for heavy-oil and bitumen recovery has grown considerably as a viable and environmentally friendly alternative to the currently used thermal methods. The potential for the success of the Vapex process is even more attractive in some scenarios that preclude the thermal methods. The presence of an overlying gas cap and/or bottomwater aquifer, thin pay zones, low thermal conductivity, high watersaturation, and unacceptable heat losses to overburden and under burden formations are some of the limitations with the thermal techniques, which potentially can be overcome by Vapex implementation. However, predicted low production rates by previous researchers for field application of the Vapex technique remain a serious barrier to commercial applications of the process. The scaleup methods that have been used by previous workers for translating the laboratory results to field predictions were based primarily on the reservoir transmissibility. An analytical model developed by Butler and Mokrys showed that the oil rate should be proportional to the square root of reservoir transmissibility. The effect of convective dispersion between solvent and virgin heavy oil in porous media was ignored in developing this model.
The main objective of this work is to develop an improved scaleup method for the Vapex process using physical-model experiments carried out in models of different sizes. In this paper, we report the results of a new series of experiments that extend the previously reported results of Karmaker and Maini to a significantly wider range of model heights. These new experiments used a new design of slice-type physical models that places the sandpack in the annulus formed by two cylindrical pipes. Combining the new results with the previous data of Karmaker and Maini, we show that the transmissibility-based scaling-up method seriously under predicts the results at larger scales. This observation suggests that much higher rates can be expected in the field implementation of the Vapex process.
A new correlation also has been proposed for scaling up the experimental data to the real field cases. It indicates the height dependency of the convective-dispersion contribution, which can be the dominant mass-transfer mechanism for the process, to be a higher order than previously postulated. Experimental results from this work show that the stabilized rate is a function of drainage height to the power of 1.1 to 1.3, instead of the square-root functionality of the Butler and Mokrys model.
Cost-effective heavy-oil- and bitumen-recovery methods are still challenging issues that have not been fully resolved. The huge volume of almost immobile hydrocarbon resources in the world, especially located in Canada, Venezuela, and the United States (approximately six times the total conventional oil reserves), offers unlimited challenges and opportunities to researchers. The high viscosity and low mobility of these oils cause the primary recovery to be very low. The adverse mobility-ratio problem also limits the application of waterflooding to these reservoirs. The overall recovery that can be achieved before the enhanced-oil-recovery (EOR) methods usually does not exceed 6 to 8%of the original oil in place.
The well-known observation of a dramatic decrease in the viscosity of heavy oil with temperature increase makes the thermal-recovery methods, such as steamflooding, cyclic steam stimulation (CSS), in-situ combustion, and (more recently) the steam-assisted gravity drainage (SAGD) process the obvious choices. However, thermal methods are not universally applicable to highly viscous heavy-oil reservoirs. The low recovery factors associated with CSS(inefficient steamflood in highly viscous oils and a relatively high mobility requirement), in addition to the process-control difficulties for the in-situ combustion technique, are some of the obstacles that leave the SAGD process as the only thermal option for heavy-oil and bitumen recovery in many reservoirs. In the SAGD process, two horizontal wells located in the same vertical plane are used to inject the steam from the upper well and produce heated oil from the lower well.
The Vapex process, which was initially proposed by Butler and Mokrys, is a solvent-based analog of the SAGD process, which can be considered when the SAGD is likely to be problematic. In thin reservoirs, the amount of heat loss to the surrounding formations makes the SAGD uneconomic. Also, in low-permeability carbonate reservoirs in which the heat capacity per volume of oil is high, the steam/oil ratio is not economically attractive. The presence of the bottom aquifer and/or a thin gas cap can be counted as an advantage for the Vapex process, whereas they are troublesome for SAGD. In terms of energy consideration, it has been reported that Vapex needs only a fraction of the energy used for SAGD. Also, Vapex has smaller upfront capital requirements compared to SAGD, in which 30% of the capital investment goes towards team-generation equipment.