2-D Visualisation of Unstable Waterflood and Polymer Flood for Displacement of Heavy Oil

Skauge, Arne; Ormehaug, Per Arne; Gurholt, Tiril P.; Vik, Bartek; Bondino, Igor; Hamon, Gérald

doi:10.2118/154292-ms

Cited by 60 publications

(47 citation statements)

References 8 publications

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“…Water is injected from the top, in black is the injected water. From Skauge et al (2012) after applying a threshold to the image wide range of scales has been seen in these cases. Because of the moderate range of scales an estimation of a fractal dimension D F would have been difficult in the already published cases, and the authors resorted instead to the measurement of the correlation between object area A and object perimeter L in the form A ∼ L α .…”

Section: Introductionmentioning

confidence: 91%

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Simulation of Viscous Fingering in Rectangular Porous Media with Lateral Injection and Two- and Three-Phase Flows

2016

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Understanding multiphase flow in porous media is of tremendous importance for many industrial and environmental applications at various spatial and temporal scales. The present study consequently focuses on modeling multiphase flows by the Volume-of-Fluid method (sharp interface) in porous media with a simplified Darcy-scale approach and shows simulations of Saffman-Taylor fingering. The simplification of the Darcy scale approach is performed by assuming sharp interfaces between pure phases. The Volume-of-Fluid method with octree mesh refinement is used. It is implemented in the Gerris code which allows efficient parallel computations. We measure the scaling properties of the fractal viscousfingering patterns that appear in the numerical simulations. One of these properties is the fractal or Hausdorff dimension D F. The other is the variation of the area A of the viscousfingering cluster with the length L of its perimeter, which varies as a simple power law A ∼ L α. The injection of an intermediate-viscosity Newtonian fluid as a second step is also simulated. We are thus able to observe an increase of recovery of the high-viscosity fluid behind the fingering front, due to the reduction of the viscosity contrast. Some of these results are compared to waterflooding experiments of extra-heavy oils in quasi-2D square slab geometries of Bentheimer sandstone.

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Section: Introductionmentioning

confidence: 91%

“…We compare the results of simulation in the frame of this model with an actual invasion experiment by Skauge et al (2012) shown in Figure 1. This experiment has the advantage of being performed in a slab with square geometry with a moderate thickness so it matches approximately our model.…”

Section: Introductionmentioning

confidence: 99%

Simulation of Viscous Fingering in Rectangular Porous Media with Lateral Injection and Two- and Three-Phase Flows

2016

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“…It is questionable whether such approach is representative, as heavy oil and light oil have very different physical properties such as interfacial tension, moleculare size, viscosity, compressability and distribution of components. Experimental studies have shown that heavy oil in water and mixed wet system has large influx of oil droplets long after water breakthrough; see section discussing results made by Skauge 13 . This may indicate viscous coupling of oil-water moves oil along with the water.…”

Section: Experimemental Challengesmentioning

confidence: 99%

“…Arne Skauge et.al 13 : presents a water flood study where heavy oil is displaced by water in a homogenous (30 cmx30cm) core plate material. X-ray technique is used to visualize the saturation.…”

Section: Implementation Of Relative Permeability Curves Into Dynamic mentioning

confidence: 99%

Heavy Oil and Relative Permeability in Laboratory, Simulations and Production; Is There A Link?

Berg

Bjørlykke

2014

Day 2 Tue, December 09, 2014

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One important challenge working in heavy oil field development is to present a set of production profiles representing low, base and high production without being overly optimistic or pessimistic. The paper give examples on how various methods of assessing the uncertainty in the relative permeability curve shapes changes the view on project uncertainty. Heavy oil laboratory relative permeability experiments face many well-known challenges. The core data is usually unconsolidated with very high permeability. This combined with high viscosity usually leads to unfavourable laboratory conditions like in example capillary end effects and viscous fingering. Typical core issues are fractures, laminations, loose sand, issues with use of multiple core plugs and very low pressure differential at initiation of the experiment. In addition there is always a discussion about reservoir wettability and core history including impact of drilling operations, drilling mud and core depressurization. The total effect is that the laboratory data is often seen as highly unreliable. The challenges are usually solved by using either light oil or by using steady state together with unsteady state experiments. Weaknesses and strength of the steady state method is addressed. Discussion of the alternative methods that is available is given with examples. Can light oil really be used instead of heavy oil given the large compositional differences? What could the impact of asphaltene content be? Examples are given of some typically laboratory effects. A brief discussion is given regarding possible reasons for differences between light and heavy oil behaviour. A benchmark of relative permeability experience from 50 heavy oil fields is presented. The benchmarking methodology is given and explained. Strength and weaknesses of the method is discussed. Actual field data is shown. Examples of relative permeability data used in simulation models are shown. Impact of grid size and properties on relative permeability is shown. Use of rock curves and alternative curve fit methods is presented with weakness and strengths.

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“…Because of the extremely high viscosity of heavy oil (100 cp~10,000 cp, or even higher), water and chemical floods in heavy oil reservoirs are inherently unstable flows even if polymer is used. Viscous finger patterns in the Darcy scale have been visualized in micromodel experiments and porous media (Tang and Kovscek 2011;Doorwar and Mohanty 2011;Skauge et al 2012). Fig.…”

Section: Introductionmentioning

confidence: 99%

Modeling and Upscaling Unstable Water and Polymer Floods: Dynamic Characterization of the Effective Finger Zone

et al. 2016

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Upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach greatly hinders the effective reservoir simulation and optimization of heavy oil recoveries using waterflood, polymer flood and other chemical floods, which are inherently unstable processes. The difficulty in upscaling unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.In a recent study based on abundant experimental data, it is found that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named viscous finger number in this paper), which is a combination of viscosity ratio, capillary number, permeability, and the cross-section area of the core. Based upon this important finding as well as the features of unstable immiscible floods, an effective-finger model is developed in this paper. A porous medium domain is dynamically identified as three effective zones, which are two-phase flow zone, oil single-phase flow zone, and bypassed oil (isolated oil island) zone, respectively. Flow functions are derived according to effective flows in these zones. This new model is capable of history-matching a set of heavy-oil waterflood corefloods under different viscosity ratios and injection rates. Model parameters obtained from the history match also have a power-law correlation with the viscous finger number.The build-up of this correlation contains reasonable physical meanings to quantitatively characterize the upscaled behavior of viscous fingering effects. Having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous finger number in reservoir simulations. The model is applied to several heavy-oil field cases with waterfloods and polymer floods with different heterogeneities. Oil recovery in water flooding of viscous oils is overpredicted by classical simulation methods which do not incorporate viscous fingering properly. Simulation results indicate that the new model reasonably differentiates the oil recoveries at different viscous finger numbers, e.g., lower injection rate leads to higher oil recovery. In contrast, classical simulations obtain close oil recoveries under different injection rates or degrees of polymer shear-thinning, which is apparently incorrect for unstable floods. Moreover, coarse-grid simulations using the new model are able to obtain consistent saturation and pressure maps with fine-grid simulations when the correlation lengths are not smaller than the coarse gridblock size. Furthermore, it is well captured by the model that the shear-shinning polymer solution can strengthen the fingering in high-permeability regions due to increased capillary number and viscosity ratio, which is not observed in waterflood. As a whole, the new model shows encour...

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2-D Visualisation of Unstable Waterflood and Polymer Flood for Displacement of Heavy Oil

Cited by 60 publications

References 8 publications

Simulation of Viscous Fingering in Rectangular Porous Media with Lateral Injection and Two- and Three-Phase Flows

Simulation of Viscous Fingering in Rectangular Porous Media with Lateral Injection and Two- and Three-Phase Flows

Heavy Oil and Relative Permeability in Laboratory, Simulations and Production; Is There A Link?

Modeling and Upscaling Unstable Water and Polymer Floods: Dynamic Characterization of the Effective Finger Zone

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