The last ~4.5 years have been the most exciting and challenging period in my life so far. I want to use this opportunity to thank at least some of the people who have supported me in one way or another during this period. I wish to express my gratitude to my supervisor Dr. Morten G. Aarra; thank you for sharing your knowledge with me, for your personal encouragement, and for the many good discussions. My co-supervisor, Professor Arne Skauge, deserves a special thank as well; thank you for scientific advice and assistance throughout the work, for giving me the opportunity to participate as a Master and PhD student at Uni CIPR, and for offering me a permanent position thereafter. Acknowledge goes to Hege Ommedal for her support as PhD-coordinator at the department of Chemistry. I am also thankful to other past and present colleagues at Uni CIPR who have made this time

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Most studies on foam are related to homogeneous and highly permeable porous media. As the reservoir situation is rather heterogeneous with respect to permeability and layering, foam properties in layered porous media with lower permeabilities are also important to understand. This study investigates foam behavior and performance in naturally laminated sandstone cores. Laminations are common constituents in sandstone petroleum reservoirs where they usually occur as thin deformed layers in the host formation. Evidences of rock heterogeneity were confirmed by several different analyses on laminated material. From image processing of thin sections and 2D X-ray experiments, the laminas present were found to exhibit both lower porosity and permeability than the host rock, and also shown to form barriers to fluid flow. Foam experiments were performed in three low permeability sandstone cores with relative similar permeability but with a different degree of laminated stratifications parallel to flow direction. Foam was generated in all the low permeability laminated cores. However, the degree of lamina in each core influenced foam performance significantly, reflected by large variations in mobility reduction factors (MRF ∼ 20–500) and foam breakthrough times. Increased lamination resulted in weaker foams and earlier foam breakthroughs. One explanation to this could be that the low permeability laminas introduce different degrees of discontinuities and compartmentalization to foam flow. Findings in our study indicate that foam properties and performance can be strongly influenced by local heterogeneities, such as laminations naturally found in many sandstone reservoirs.

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.