Pore-Scale Evaluation of Polymers Displacing Viscous Oil – Computational Fluid Dynamics Simulation of Micromodel Experiments

Clemens, Torsten; Tsikouris, Kostas; Buchgraber, Markus; Castanier, L.M.; Kovscek, Anthony R.

doi:10.2118/154169-ms

Cited by 3 publications

(2 citation statements)

References 61 publications

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“…In response to this need, we have now demonstrated that the polymer concentration C p has a significant influence on the dynamics and patterns of interface displacement and phase distribution (even when the flowrate is kept constant) due to the effects of C p on the effective viscosity of the polymer solution. In contrast to previous studies [2,20,[24][25][26][27][28], the dependency of M and S ro on Ca could be analyzed. Using a series of microfluidic experiments, we showed the capability of C p to alter the value and range of Ca and M, which, in turn, determine the stability of the invasion front as well as the mobilization and fragmentation of the resulting ganglia.…”

Section: Ganglia Size Distribution and Analysismentioning

confidence: 99%

“…Other authors [28] carried out computational fluid dynamics simulations using a digitalised pore network to investigate the non-Newtonian fluid displacement at the microscale and compared their results with the flooding experiments [20]. In previous work [2], a micromodel study was performed to investigate the effects of rheological properties of several complex fluids used in EOR on oil recovery.…”

Section: Introductionmentioning

confidence: 99%

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Effects of shear-thinning fluids on residual oil formation in microfluidic pore networks

Castro

Oostrom

Shokri

2016

Journal of Colloid and Interface Science

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Two-phase immiscible displacement in porous media is controlled by capillary and viscous forces when gravitational effects are negligible. The relative importance of these forces is quantified through the dimensionless capillary number Ca and the viscosity ratio M between fluid phases. When the displacing fluid is Newtonian, the effects of Ca and M on the displacement patterns can be evaluated independently. However, when the injecting fluids exhibit shear-thinning viscosity behaviour the values of M and Ca are interdependent. Under these conditions, the effects on phase entrapment and the general displacement dynamics cannot be dissociated. In the particular case of shear-thinning aqueous polymer solutions, the degree of interdependence between M and Ca is determined by the polymer concentration. In this work, two-phase immiscible displacement experiments were performed in micromodels, using shear-thinning aqueous polymer solutions as displacing fluids, to investigate the effect of polymer concentration on the relationship between Ca and M, the recovery efficiency, and the size distribution of the trapped non-wetting fluid. Our results show that the differences in terms of magnitude and distribution of the trapped phase are related to the polymer concentration which influences the values of Ca and M.

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Section: Ganglia Size Distribution and Analysismentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Effects of shear-thinning fluids on residual oil formation in microfluidic pore networks

Castro

Oostrom

Shokri

2016

Journal of Colloid and Interface Science

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Shear Rate Determination from Pore-Scale Flow Fields

Berg

Wunnik

2017

Transp Porous Med

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Aqueous solutions with polymer additives often used to improve the macroscopic sweep efficiency in oil recovery typically exhibit non-Newtonian rheology. In order to predict the Darcy-scale effective viscosity μ eff required for practical applications often, semiempirical correlations such as the Cannella or Blake-Kozeny correlation are employed. These correlations employ an empirical constant ("C-factor") that varies over three orders of magnitude with explicit dependency on porosity, permeability, fluid rheology and other parameters. The exact reasons for this dependency are not very well understood. The semi-empirical correlations are derived under the assumption that the porous media can be approximated by a capillary bundle for which exact analytical solutions exist. The effective viscosity μ eff (v Darcy ) as a function of flow velocity is then approximated by a cross-sectional average of the local flow field resulting in a linear relationship between shear rate γ and flow velocity. Only with such a linear relationship, the effective viscosity can be expressed as a function of an average flow rate instead of an average shear rate. The local flow field, however, does in general not exhibit such a linear relationship. Particularly for capillary tubes, the velocity is maximum at the center, while the shear rate is maximum at the tube wall indicating that shear rate and flow velocity are rather anti-correlated. The local flow field for a sphere pack is somewhat more compatible with a linear relationship. However, as hydrodynamic flow simulations (using Newtonian fluids for simplicity) performed directly on pore-scale resolved digital images suggest, flow fields for sandstone rock fall between the two limiting cases of capillary tubes and sphere packs and do in general not exhibit a linear relationship between shear rate and flow velocity. This indicates that some of the shortcomings of the semi-empirical correlations originate from the approximation of the shear rate by a linear relationship with the flow velocity which is not very well compatible with flow fields from direct hydrodynamic calculations. The study also indicates that flow fields in 3D rock are not very well represented by capillary tubes.

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Polymer Flooding of a Heavy Oil Reservoir with an Active Aquifer

Delshad

Lotfollahi

et al. 2014

SPE Improved Oil Recovery Symposium

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In recent years, polymer flooding of heavy oil has been extensively studied in laboratories and successfully applied in several fields. This paper reports the laboratory corefloods, development of mechanistic models, and simulation studies of polymer flooding in a heavy oil reservoir with active aquifer influxes. Bentley Field, operated by Xcite Energy Resources, is located on the UK Continental Shelf. Flow tests confirmed the existence of a large, active bottom aquifer which may cause polymer loss and decrease the economic attractiveness of polymer flooding. To analyze the impact of the aquifer on oil recovery efficiency, a reservoir simulation model was set up. Several development scenarios have been simulated for the optimization of development strategy. Conventional thinking, based on previously accepted EOR screening criteria, would be that the oil viscosity (approximately 1500 cp) exceeds the economic and technical limit of oil viscosity for polymer flooding. However, this paper demonstrates that the limit for effective polymer flooding can be extended to considerably higher viscosity oils. To validate the applicability of polymer flooding, two laboratory experiments were conducted with two different high permeability sandpacks. Due to the unconsolidated nature of the Bentley formation no cores were available. Waterflooding was stopped when water cut reached 90% and up to that point, less than 25% of oil in place had been recovered. However, the remaining oil saturations after both tertiary polymer corefloods achieved around a 5% level. We investigated the recovery mechanisms and developed a mechanistic model to match the laboratory observations. Simulation results show that for this heavy oil field with an active aquifer, polymer flooding economics can be improved by optimizing well locations, number of horizontal wells, polymer injection time, etc. In history matching coreflood experiments, two oil saturation reduction mechanisms were considered: (1) viscous polymer solution reduces viscous fingering and channeling effects especially in the heavy oil displacement process and also reduces remaining oil saturation after waterflooding; (2) remaining oil can be mobilized by viscoelastic properties of synthetic polymer solutions. Both mechanisms were considered in the simulation study where a favorable match of oil recovery and pressure drop was obtained. In this paper, polymer flooding is shown as a viable technology in a heavy oil reservoir, despite the highly unfavorable mobility ratio and strong aquifer influxes. Considering the diminishing conventional oil reserves, polymer flooding provides a non-thermal approach for producing heavy oil reserves that may be particularly attractive in an offshore environment, compared to thermal techniques.

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Pore-Scale Evaluation of Polymers Displacing Viscous Oil – Computational Fluid Dynamics Simulation of Micromodel Experiments

Cited by 3 publications

References 61 publications

Effects of shear-thinning fluids on residual oil formation in microfluidic pore networks

Effects of shear-thinning fluids on residual oil formation in microfluidic pore networks

Shear Rate Determination from Pore-Scale Flow Fields

Polymer Flooding of a Heavy Oil Reservoir with an Active Aquifer

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