Waterflooding and polymer assisted waterflood in heavy oil reservoirs has currently gaining great attention. Enhanced water injection schemes represent an alternative in cases where thermal methods are either impractical or uneconomic. This study describes and analyses the oil mobilization by imaging the oil displacement at adverse mobility by injection of brine and polymer. The objectives were to improve description of viscous instabilities, mechanisms for finger growth, water channeling at adverse mobility ratio, and oil mobilization by polymers.Experiments have been made on 2D (30cmx30cm Bentheimer slabs) studying waterflooding and tertiary polymer injection in extra heavy oils (2000cp and 7000cp). The sandstone represents a relatively homogeneous and high permeability porous medium. The experiments utilize gamma and X-ray source for porosity and saturation measurements, and an X-ray imaging system to visualize displacements and thereby quantify the underlying flow mechanisms and oil recovery.At water wet condition capillary smears the front and prevents viscous fingers even at high adverse viscosity ratio. Changes in wettability (aging the rock material) dampen the capillarity and fingers then become more pronounced. High microscopic recovery to waterfloods (up to 30% after 5 PV injected) were achieved, and most importantly a rather impressive further gain in oil recovery after polymer flooding reaching final recoveries of more than 60%. The waterflood creates multiple thin sharp fractal-like fingers that propagate in the Bentheimer sandstone material. The 2D X-ray imaging describes the finger formation, growth, and also the later water channels formed. Polymer injection gives a fast increase in oil production, and analysis from the imaging proves that the oil is mainly produced through the established water channels.The 2-D experiments demonstrate the mechanisms of how heavy oil is mobilized by polymer injection. Saturation maps were accurately measured by means of X-ray scans and this enabled the visualization of flow instability, establishment of water channels and oil mobilization with high resolution.

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A reliable prediction of two-phase flow through porous media requires the development and validation of models for flow across multiple length scales. The generalized network model is a step towards efficient and accurate upscaling of flow from the pore to the core scale. This paper presents a validation of the generalized network model using micro-CT images of two-phase flow experiments on a pore-by-pore basis. Three experimental secondary imbibition datasets are studied for both sandstone and carbonate rock samples. We first present a quantification of uncertainties in the experimental measurements. Then, we show that the model can reproduce the experimental fluid occupancies and saturations with a good accuracy, which in some cases is comparable with the similarity between repeat experiments. However, high-resolution images need to be acquired to characterize the pore geometry for modelling, while the results are sensitive to the initial condition at the end of primary drainage. The results provide a methodology for improving our physical models using large experimental datasets which, at the pore scale, can be generated using micro-CT imaging of multiphase flow.

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Although thermal methods have been popular and successfully applied in heavy oil recovery, they are often found to be uneconomic or impractical. Therefore, alternative production protocols are being actively pursued and interesting options include water injection and polymer flooding. Indeed, such techniques have been successfully tested in recent laboratory investigations, where X-ray scans performed on homogeneous rock slabs during water flooding experiments have shown evidence of an interesting new phenomenon–post-breakthrough, highly dendritic water fingers have been observed to thicken and coalesce, forming braided water channels that improve sweep efficiency. However, these experimental studies involve displacement mechanisms that are still poorly understood, and so the optimization of this process for eventual field application is still somewhat problematic. Ideally, a combination of two-phase flow experiments and simulations should be put in place to help understand this process more fully. To this end, a fully dynamic network model is described and used to investigate finger thickening during water flooding of extra-heavy oils. The displacement physics has been implemented at the pore scale and this is followed by a successful benchmarking exercise of the numerical simulations against the groundbreaking micromodel experiments reported by Lenormand and co-workers in the 1980s. A range of slab-scale simulations has also been carried out and compared with the corresponding experimental observations. We show that the model is able to replicate finger architectures similar to those observed in the experiments and go on to reproduce and interpret, for the first time to our knowledge, finger thickening following water breakthrough. We note that this phenomenon has been observed here in homogeneous (i.e. un-fractured) media: the presence of fractures could be expected to exacerbate such fingering still further. Finally, we examine the impact of several system parameters, including core length, wettability and injection rate, on the extent and efficiency of the finger swelling phenomenon.