Theoretical and experimental evidence of different wettability classes

Skauge, Arne; Spildo, Kristine; Høiland, Linda Kåda; Vik, Bartek

doi:10.1016/j.petrol.2006.11.003

Cited by 51 publications

(53 citation statements)

References 12 publications

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“…1). The existence of these three different classes of intermediate wettability was later verified both theoretically and experimentally (Skauge et al 2006).…”

Section: Introductionmentioning

confidence: 80%

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Fluid flow properties for different classes of intermediate wettability as studied by network modelling

Høiland¹,

Spildo²,

Skauge³

2007

Transp Porous Med

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Most clastic reservoirs display an intermediate type of wettability. Intermediate wettability covers several local wetting configurations like fractional wet and mixed-wet where the oil-wet sites could either be in the large or smaller pores. Clastic reservoirs show a large variation in fluid flow properties. A classical invasion-percolation network simulator is used to investigate properties of different intermediate wet situations. Variation in wetting properties like contact angles, process dependent contact angles, contact angle distribution, and fraction of oil wet sites are investigated. The fluid flow properties analysed in particular are residual oil saturation and normalized endpoint relative permeability. Results from network modelling have been compared to reservoir core analysis data. The network models applied are at the capillary limit, while the core flood results are clearly viscous influenced. Even though network modelling does not cover all the physics involved in fluid displacement processes, results show that data from simulations are sufficient to present trends in fluid flow properties which are comparable to experimental data.

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“…1). The existence of these three different classes of intermediate wettability was later verified both theoretically and experimentally (Skauge et al 2006).…”

Section: Introductionmentioning

confidence: 80%

“…Contact angles are chosen for both the water-and oil-wet pores. The physical evolution of the three wetting states is described theoretically by Skauge et al (2006). Pores with star shaped cross sections will have a higher disjoining pressure in the small pores than in the larger pores.…”

Section: Wettability Alterationmentioning

confidence: 99%

Fluid flow properties for different classes of intermediate wettability as studied by network modelling

Høiland¹,

Spildo²,

Skauge³

2007

Transp Porous Med

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“…In mixed-wet large sandstones, only the large pores are oil-wet, and in mixed-wet small, the small pores are also oil-wet. The pores in our chalk samples are Ϸ100 times smaller than sandstone (24), but their randomly distributed, variable size hydrophobic and hydrophilic patches put them decidedly into the fractionally wet class. For macroscopic determination by imbibition, the sample would appear water-wet, which is consistent with macroscopic data from our own samples and those of others (25); water imbibes easily into freshly fractured chalk surfaces.…”

Section: Afm Force Mappingmentioning

confidence: 93%

“…Salathiel (6) originally proposed that mixed-wettability means a continuous pathway of oil-wet surfaces interconnected through pores. Skague et al (24) categorized wettability for sandstones into three subclasses defined by size and location of the oil-wet patches relative to the size of the pores and the channels between them. A ''fractionally wet'' sample was defined to have variable size water-and oil-wet domains.…”

Section: Afm Force Mappingmentioning

confidence: 99%

Probing the intrinsically oil-wet surfaces of pores in North Sea chalk at subpore resolution

Hassenkam

Skovbjerg

Stipp

2009

Proc. Natl. Acad. Sci. U.S.A.

134

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Pore surface properties control oil recovery. This is especially true for chalk reservoirs, where pores are particularly small. Wettability, the tendency for a surface to cover itself with fluid, is traditionally defined by the angle a droplet makes with a surface, but this macroscopic definition is meaningless when the particles are smaller than even the smallest droplet. Understanding surface wetting, at the pore scale, will provide clues for more effective oil recovery. We used a special mode of atomic force microscopy and a hydrophobic tip to collect matrices of 10,000 force curves over 5-؋ 5-m 2 areas on internal pore surfaces and constructed maps of topography, adhesion, and elasticity. We investigated chalk samples from a water-bearing formation in the Danish North Sea oil fields that had never seen oil. Wettability and elasticity were inhomogeneous over scales of 10s of nanometers, smaller than individual chalk particles. Some areas were soft and hydrophobic, whereas others showed no correlation between hardness and adhesion. We conclude that the macroscopic parameter, ''wetting,'' averages the nanoscopic behavior along fluid pathways, and ''mixed-wet'' samples have patches with vastly different properties. Development of reservoir hydrophobicity has been attributed to infiltrating oil, but these new results prove that wettability and elasticity are inherent properties of chalk. Their variability, even on single particles, must result from material originally present during sedimentation or material sorbed from the pore fluid some time later.AFM ͉ force maps ͉ wettability ͉ oil recovery ͉ adhesion

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“…(1) Uncertainty in the experimental input properties to the model: pore space images and spatial wettability distribution [5,9] (2) Uncertainty due to model simplifications, incorporated physics, and numerics [10] (3) Uncertainty due to sampling and scale difference between the model, typically a few mm 3 , and the experiment, which may be performed on a rock volume of several cm 3 [11] * t.bultreys@imperial.ac.uk…”

Section: Introductionmentioning

confidence: 99%

Validation of model predictions of pore-scale fluid distributions during two-phase flow

et al. 2018

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Pore-scale two-phase flow modeling is an important technology to study a rock's relative permeability behavior. To investigate if these models are predictive, the calculated pore-scale fluid distributions which determine the relative permeability need to be validated. In this work, we introduce a methodology to quantitatively compare models to experimental fluid distributions in flow experiments visualized with microcomputed tomography. First, we analyzed five repeated drainage-imbibition experiments on a single sample. In these experiments, the exact fluid distributions were not fully repeatable on a pore-by-pore basis, while the global properties of the fluid distribution were. Then two fractional flow experiments were used to validate a quasistatic pore network model. The model correctly predicted the fluid present in more than 75% of pores and throats in drainage and imbibition. To quantify what this means for the relevant global properties of the fluid distribution, we compare the main flow paths and the connectivity across the different pore sizes in the modeled and experimental fluid distributions. These essential topology characteristics matched well for drainage simulations, but not for imbibition. This suggests that the pore-filling rules in the network model we used need to be improved to make reliable predictions of imbibition. The presented analysis illustrates the potential of our methodology to systematically and robustly test two-phase flow models to aid in model development and calibration.

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Theoretical and experimental evidence of different wettability classes

Cited by 51 publications

References 12 publications

Fluid flow properties for different classes of intermediate wettability as studied by network modelling

Fluid flow properties for different classes of intermediate wettability as studied by network modelling

Probing the intrinsically oil-wet surfaces of pores in North Sea chalk at subpore resolution

Validation of model predictions of pore-scale fluid distributions during two-phase flow

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