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The economic life of a typical heavy oil reservoir under primary or secondary recovery schemes can be short lived or near their limit, with recovery factors in the range of 5-15%. Waterflooding alone has been successfully practiced in the Lloydminster area of the Western Canada for decades. Heavy oils located in thick reservoirs have benefited from the application of thermal, gravity drainage processes; however, thin, unconsolidated heavy oil reservoirs are unsuitable due to lack of drainage height. These reservoirs may benefit from immiscible CO 2 or CO 2 -WAG processes.This paper examines the effect of oil viscosity, permeability and injection rate on the performance of heavy oil waterflooding, immiscible CO 2 flooding and immiscible CO 2 water-alternating-gas (WAG) processes. A series of 11 sand packfloods were conducted using 440 and 1,500 mPa·s heavy oils and sand packs with absolute permeabilities of 12 and 40 µm 2 . Water injection volumes for the waterfloods were 1.5 pore volumes (PVs) at rates of 0.112, 1.124, and 5.62 cc/min. For the CO 2 flooding process, 4.5 PVs of gas were injected at a rate of 1 cc/min. For the WAG process, the water:CO 2 slug ratios were varied from 1:1, 1:2 and 2:1. A 99.9% purity CO 2 gas stream was used for all gas floods. All experiments were performed at a controlled temperature of 25°C and 345 kPa.Among the 11 sand packfloods conducted, the waterfloods consistently yielded the highest recovery factor for both heavy oils and sand packs, with 48-52% OOIP recovered and most of this recovery occurring during 0.112 cc/min. During CO 2 flooding of the 440 mPa·s oil, 48.5% OOIP was produced from the 40 µm 2 sand pack. From the same fluid-sand system, a 1:1 slug ratio, CO 2 -WAG process produced 42% OOIP. For the 1,500 mPa·s heavy oil, 1:2 and 2:1 slug ratios of CO 2 -WAG both produced ~25% OOIP from the 40 μm 2 sand pack and a 1:1 slug ratio produced 35% OOIP from the 12 μm 2 sand pack. All WAG injection schemes were compared on a 2.5 PV injected basis. These results suggest that the role of displaced fluid viscosity plays the most prominent role in the recovery of heavy oil.

Water/oil relative permeability data plays an important role in characterizing the simultaneous two-phase flow of fluids in porous media and predicting the performance of water flooding as a means of an immiscible displacement processes in oil reservoirs. Review of literatures indicated extensive experimental studies on two-phase water/oil relative permeability for light oil systems, however, such studies on the effect of various crude oil characteristics and operational factors on water/oil relative permeability in heavy oil systems are limited. In addition, previously developed correlations, such as Corey's equations, are not satisfactory when applied to heavy oil systems. The Objectives of this study were: I) to investigate the effect of temperature, viscosity, flow rate, and pressure on water/oil relative permeability, experimentally and II) to develop a set of new correlations for calculating water/oil relative permeability in which the effects of pressure, viscosity (temperature), and flow rate were incorporated. The experimental results showed that both water and oil relative permeability values are significantly temperature dependent and they increase when temperature increases. The results revealed that relative permeability to oil and water increase with decrease in oil viscosity. Increase in injection flow rate resulted in higher oil relative permeability and lower water relative permeability. The tests results also indicated that relative permeability to oil in water-heavy oil system is almost independent of operating pressure. The experimental data obtained in this study was used to develop new water/oil relative permeability correlations. The comparative evaluation of the new correlations with those developed by Corey showed significant improvement in prediction of water/heavy oil relative permeability. Statistical analysis of the results showed that the new correlations facilitate reliable calculation of water/oil relative permeability values by decreasing the Root Mean Square magnitude from 0.167 and 0.178 to 0.004 and 0.061 for water and oil relative permeability, respectively. In addition, the accuracy of newly developed correlations was tested against three sets of heavy oil experimental data obtained by other researchers. Results of this comparison also showed that water/oil relative permeability predicted by new correlations are in better agreement with experimental data compare to those predicted by Corey's model. Introduction Relative permeability is a crucial empirical parameter in describing the flow of multiple immiscible fluids within a porous medium (Amyx et al. 1960; Frick 1962; Heaviside et al. 1983; Honarpour et al. 1986; Al-Fattah 2003). It is defined as the ratio of the effective permeability of a fluid at a given saturation to the absolute permeability of the rock. Relative permeability data is essential for almost all fluid flow calculations in reservoirs and is utilized extensively in many areas of petroleum engineering such as: determining the residual fluid saturations, calculating the fractional flow and frontal advance, making engineering estimates of productivity, injectivity and ultimate recovery. The data is more particularly used for matching, predicting and optimizing oil and gas reservoir performances through numerical simulations. Relative permeability values are generally obtained from laboratory experiments on reservoir core samples using one of the measurement methods: steady state, unsteady state, or centrifuge techniques. The relative permeability data may also be determined from field data using the production history of a reservoir and its fluid properties. However, this approach is not often practical because it requires the complete production history data and provides average values which are influenced by pressure and saturation gradients, differences in the depletion stage and saturation variations in reservoirs.