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Summary It has been long believed that the viscoelasticity of polymer solution improves the displacement efficiency in polymer flood operations, but the individual effect of elasticity has not been clearly distilled for a single viscoelastic polymer. In this study, the effect of elasticity of polymer-based fluids on the microscopic sweep efficiency is investigated by injecting two polymer solutions with similar shear viscosity, but significantly different elastic characteristics. Blends of various grades of polyethylene oxide (PEO) with similar average molecular weight and different molecular weight distribution (MWD) were prepared by dissolving in deionized water. The polymer solutions exhibited identical shear viscosity, but different elasticity. A series of experiments were performed by injecting the polymer solutions through a sandpack saturated with mineral oil. The experiments were performed using a special core holder designed to simulate radial flow. Injection was done through a perforated injection line located at the centre of the cell and fluids were produced through two production lines located at the periphery. The experiments were conducted within a shear rate range of field applications. Because both polymer solutions had similar shear viscosity behaviour, but different elastic properties, it was possible to see the effect of elasticity on the sweep efficiency alone. Results of the polymer flooding experiments indicated that the sweep efficiency of a polymeric fluid could be effectively improved by adjusting the MWD of the solution at constant shear viscosity and polymer concentration. The polymer solution with higher elasticity exhibited considerably higher resistance to flow through porous media than the one with lower elasticity, resulting in higher sweep efficiency and lower residual oil saturation.

Fracture fluid flow back has been identified as one of the major challenges of hydraulic fracturing operations conducted in shale reservoirs. Factors causing the very low fracture fluid recovery need to be well understood and properly addressed, in order to get full benefits from costly hydraulic fracture jobs conducted in unconventional reservoirs. Despite the recent surge of investigations of the problem, one major question still remains: what happens to the fracture fluid that is not recovered? Does it stay in the fracture or does it go into the matrix? In case of both mechanisms are responsible for fracture fluid retainment, what fraction of fracture fluid stays in the propped fracture and what fraction is transferred from fracture to matrix. The focus of the current study is to understand if the transfer of fracture fluid from fracture to matrix through imbibition is of significant importance. We systematically measure the imbibition rate of water, brine, and oil into the actual core samples from the three shale sections of Horn River basin (i.e., Fort Simpson, Muskwa and Otter Park). We characterize the shale samples by measuring, porosity, wettability, mineral composition through XRD analysis, and interpreting the well log data. The results show that imbibition could be a viable mechanism for fluid transfer from fracture to matrix in Horn River shales. The comparative study shows the imbibition rate in the direction parallel to the bedding plane is higher than that in the direction perpendicular to the bedding. The study also suggests that the imbibition rate of the aqueous phases is significantly higher than that of the oleic phases.

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The viscoelasticity of polymers is known to contribute significantly toward improved displacement efficiency in polymer flood operations. But the contribution of elasticity of viscoelastic polymers in enhanced oil recovery (EOR) still remains largely unexplored. The majority of literature available on polymer-aided EOR, in general, talks about the role played by viscoelasticity of polymers on improved oil recovery with little or no mention of the individual contribution of the elasticity of polymers on EOR. In this work, partially hydrolyzed polyacrylamide (HPAM) solutions, having identical shear viscosity but different elasticity, were flooded to investigate the individual effect of elasticity on improved oil recovery. A transparent, sand packed visual cell, initially saturated with mineral oil, was used for flooding with four different HPAM solutions. Because these polymer solutions differed only in terms of elasticity, a comparative study of the effect of elasticity on sweep efficiency was done. Images taken at regular intervals during the course of flooding were analyzed to study the frontal displacement patterns changing with the elasticity of different HPAM solutions. The mechanism of viscous fingering in immiscible two-phase flow in porous media at different polymer elasticity values was studied. Results from flooding experiments indicate that polymer solutions with higher elasticity not only yield higher oil recovery, but also require less polymer to produce a given amount of oil. These results were further bolstered by the visual analysis. HPAM solutions with lower elasticity showed a high degree of fingering, whereas solutions with higher elasticity produced more stable displacement fronts. Improved microscopic sweep efficiency, due to the greater flow resistance offered by polymer solution with higher elasticity, was visually confirmed.