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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.

Polymer injection for viscous oil displacement has proven effective and gained interest in the recent years. The two general types of EOR polymers available for field applications, synthetic and biological, display different rheological properties during flow in porous media. In this paper, the impact of rheology on viscous oil displacement efficiency and front stability is investigated in laboratory flow experiments monitored by X-ray. Displacement experiments of crude oil (~500cP) were performed on large Bentheimer rock slab samples (30×30cm) by secondary injection of viscous solutions with different rheological properties. Specifically, stabilization of the aqueous front by Newtonian (glycerol and shear degraded HPAM) relative to shear thinning (Xanthan) and shear thickening (HPAM) fluids was investigated. An X-ray scanner monitored the displacement processes, providing 2D information about fluid saturations and distributions. The experiments followed near identical procedures and conditions in terms of rock properties, fluxes, pressure gradients, oil viscosity and wettability. Secondary mode injections of HPAM, shear-degraded HPAM, xanthan and glycerol solutions showed significant differences in displacement stability and recovery efficiency. It should be noted that concentrations of the chemicals were adjusted to yield comparable viscosity at a typical average flood velocity and shear rate. The viscoelastic HPAM injection provided the most stable and efficient displacement of the viscous crude oil. However, when the viscoelastic shear-thickening properties were reduced by pre-shearing the polymer, the displacement was more unstable and comparable to the behavior of the Newtonian glycerol solution. Contrary to the synthetic HPAM, xanthan exhibits shear thinning behavior in porous media. Displacement by xanthan solution showed pronounced viscous fingering with a correspondingly early water breakthrough. These findings show that at adverse mobility ratio, rheological properties in terms of flux dependent viscosity lead to significant differences in stabilization of displacement fronts. Different effective viscosities should arise from the flux contrasts in an unstable front. The observed favorable "viscoelastic effect", i.e. highest efficiency for the viscoelastic HPAM solution, is not linked to reduction in the local Sor. We rather propose that it stems from increased effective fluid viscosity, i.e. shear thickening, in the high flux paths. This study demonstrates that rheological properties, i.e. shear thinning, shear thickening and Newtonian behavior largely impact front stability at adverse mobility ratio in laboratory scale experiments. Shear thickening fluids were shown to stabilize fronts more effectively than the other fluids. X-ray visualization provides an understanding of oil recovery at these conditions revealing information not obtained by pressure or production data.

Biofilm accumulation in porous media can cause pore plugging and change many of the physical properties of porous media. Engineering bioplugging may have significant applications for many industrial processes, while improved knowledge on biofilm accumulation in porous media at porescale in general has broad relevance for a range of industries as well as environmental and water research. The experimental results by means of microscopic imaging over a T-shape microchannel clearly show that increase in fluid velocity could facilitate biofilm growth, but that above a velocity threshold, biofilm detachment and inhibition of biofilm formation due to high shear stress were observed. High nutrient concentration prompts the biofilm growth; however, the generated biofilm displays a weak adhesive strength. This paper provides an overview of biofilm development in a hydrodynamic environment for better prediction and modelling of bioplugging processes associated with porous systems in petroleum industry, hydrogeology and water purification.

Polymer flooding in very viscous oil has been gaining interest since its efficiency has been field proven. Multiple laboratory investigations have evidenced that the incremental oil recovered by the tertiary process increases considerably the recovery reached thanks to water flooding. However, such tertiary injection is made all the more complex that it is preceded by unstable displacement of oil by water. Therefore a better understanding of the physics is needed, in order to better predict and optimize the viscous oil reserves associated with tertiary polymer flooding. This work presents the interpretation of three similar tertiary polymer flood experiments carried out at the Centre for Integrated Petroleum Research (CIPR, Norway). Each experiment consisted in a water flood followed by a polymer flood. They involved the same Bentheimer outcrop sandstone, 2000 cP oil, 70 cP polymer solution, 2D slab geometry, but different slab lengths (2 slabs are 30cmx30cm, 1 slab is 30cmx90cm). Saturation evolution was monitored by X-ray. On the one hand, provided simple simulation assumptions, the three water floods under study could be history matched (production, pressure). Similar ratios between water and oil relative permeabilities were found, although the water flood relative permeabilities, matched with non Corey-type curves, reflected an important variability. On the other hand, the tertiary polymer floods were found challenging to match consistently. In particular, using classic history matching approaches, the history matching of the long slab experiment could not be reconciled with that of short slab experiments. Simulations were initialized with saturation maps obtained at the end of the water floods. None of the tested approaches enabled us to match consistently the short and long slab experiments together, unless a hysteresis model was implemented. Indeed, a memory effect was observed experimentally from the quantitative analysis of X-ray saturation maps and interpreted as a hysteresis phenomenon. This simple model, with two additional matching parameters, is then further validated by the comparison of 2D simulations with measured in situ saturations.