Wettability in complex porous materials, the mixed-wet state, and its relationship to surface roughness (original) (raw)
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Linking continuum-scale state of wetting to pore-scale contact angles in porous media
Journal of Colloid and Interface Science, 2020
Wetting phenomena play a key role in flows through porous media. Relative permeability and capillary pressure-saturation functions show a high sensitivity to wettability, which has different definitions at the continuum-and pore-scale. At the continuum-scale, the state of wetting is defined as Amott-Harvey or USBM (United States Bureau of Mines) indices by capillary pressure drainage and imbibition cycles. At the pore-scale, the concept of contact angle is used, which until recently was not experimentally possible to determine within an opaque porous medium. Recent progress on measurements of pore-scale contact angles by X-ray computed micro-tomography has therefore attracted significant attention in various research communities. In this work, the Gauss-Bonnet theorem is applied to provide a direct link between capillary pressure saturation (P c (S w)) data and measured distributions of pore-scale contact angles. We propose that the wetting state of a porous medium can be described in terms of geometrical arguments that constrain the morphological state of immiscible fluids. The constraint describes the range of possible contact angles and interfacial curvatures that can exist for a given system. We present measurements in a tested sandstone for which the USBM index, P c (S w), and pore-scale contact angles are measured. Additional studies are also performed using two-phase Lattice Boltzmann simulations to test a wider range of wetting conditions. We show that mean pore-scale contact angle measurements can be predicted from petrophysical data within a few differences. This provides a general framework on how continuum-scale data can be used to describe the geometrical state of fluids within porous media.
Journal of Visualized Experiments
In situ wettability measurements in hydrocarbon reservoir rocks have only been possible recently. The purpose of this work is to present a protocol to characterize the complex wetting conditions of hydrocarbon reservoir rock using pore-scale three-dimensional X-ray imaging at subsurface conditions. In this work, heterogeneous carbonate reservoir rocks, extracted from a very large producing oil field, have been used to demonstrate the protocol. The rocks are saturated with brine and oil and aged over three weeks at subsurface conditions to replicate the wettability conditions that typically exist in hydrocarbon reservoirs (known as mixed-wettability). After the brine injection, high-resolution threedimensional images (2 µm/voxel) are acquired and then processed and segmented. To calculate the distribution of the contact angle, which defines the wettability, the following steps are performed. First, fluid-fluid and fluid-rock surfaces are meshed. The surfaces are smoothed to remove voxel artefacts, and in situ contact angles are measured at the three-phase contact line throughout the whole image. The main advantage of this method is its ability to characterize in situ wettability accounting for pore-scale rock properties, such as rock surface roughness, rock chemical composition, and pore size. The in situ wettability is determined rapidly at hundreds of thousands of points. The method is limited by the segmentation accuracy and X-ray image resolution. This protocol could be used to characterize the wettability of other complex rocks saturated with different fluids and at different conditions for a variety of applications. For example, it could help in determining the optimal wettability that could yield an extra oil recovery (i.e., designing brine salinity accordingly to obtain higher oil recovery) and to find the most efficient wetting conditions to trap more CO 2 in subsurface formations.
Fluid surface coverage showing the controls of rock mineralogy on the wetting state
The wetting state is an important control on flow in subsurface multi fluid phase systems, e.g., carbon storage and oil production. Advances in X-ray imaging allow us to characterise the wetting state using imagery of fluid arrangement within the pores of rocks. We derived a model from equilibrium thermodynamics relating fluid coverage of rock surfaces to wettability and fluid saturation. The model reproduces the behaviour measured in a water-wet, nearly all-quartz, Bentheimer sandstone imaged during steady-state imbibition. A shift in fluid surface coverage is observed when the rock is altered to a new wetting state with crude oil. In two multi-mineralogical (Berea) samples, one water-wet and the other altered with crude oil, the analysis of fluid surface coverage after imbibition revealed mineral specific wetting preferences only in the altered system. Clays and calcite preferentially alter to an oil wet state, leading to mixed wettability in the rock.
Impact of surface roughness on wettability of oil-brine-calcite system at sub-pore scale
Journal of Molecular Liquids, 2019
Wettability alternation appears to be an important physicochemical process in carbonate reservoirs during low salinity water flooding. Contact angle measurement is widely used as a simple and direct method to demonstrate wettability alteration by low salinity water. The effect of various parameters, e.g., brine salinity, oil composition, and rock mineralogy on contact angle have been well documented. However, uncertainty over effect of rock surface roughness on contact angle of oil-brine-calcite is a major impediment to upscaling laboratory results and predicting wettability at field scale, knowing oil-brine-rock interaction is governed by electrostatic forces. We thus measured contact angle of oil on calcite substrates with different surface roughness (17 nm, 366 nm, and 943 nm), in high and low salinity brines. Moreover, we compared our experimental results with contact angles predicted by Wenzel's equation. Contact angle results show that in high salinity brine, contact angles decreased from 170°to 134°(36°decrease) with increasing surface roughness from 17 to 943 nm, suggesting a less hydrophobic system. Similar correlation between contact angles and surface roughness was observed in low salinity brine. Nevertheless, contact angles only slightly decreased from 117°to 101°(16°decrease) in low salinity brine, suggesting the effect of surface roughness on contact angle is more subtle in low salinity condition. We also found that for oil-brine-calcite system, the correlation between contact angle and surface roughness contradicts the trend predicted by Wenzel's equation. This is largely because the surface forces that govern oil-brine-calcite interactions are not captured by Wenzel's equation. Therefore, we hypothesize that at pore-scale level, wettability alteration by low salinity brine will likely be more subtle than that shown by contact angles when performed on smooth substrates (at sub-pore scale). To predict contact angle at pore-scale, surface roughness and surface forces governing oilbrine-calcite interactions need to be considered. The findings of this research will provide further insight into water-assisted EOR in carbonate reservoirs.
Spatial Correlation of Contact Angle and Curvature in Pore-Space Images
Water Resources Research
We study the in situ distributions of contact angle and oil/brine interface curvature measured within millimeter-sized rock samples from a producing hydrocarbon carbonate reservoir imaged after waterflooding using X-ray microtomography. We analyze their spatial correlation combining automated methods for measuring contact angles and interfacial curvature (AlRatrout et al., 2017,
Determination of the spatial distribution of wetting in the pore networks of rocks
2021
The macroscopic movement of subsurface fluids involved in CO2 storage, groundwater, and petroleum engineering applications is controlled by interfacial forces in the pores of rocks, micrometre to millimetre in length scale. Recent advances in physics based models of these systems has arisen from approaches simulating flow through a digital representation of the complex pore structure. However, further progress is limited by a lack of approaches to characterising the spatial distribution of the wetting state within the pore structure. In this work, we show how observations of the fluid coverage of mineral surfaces within the pores of rocks can be used as the basis for a quantitative 3D characterisation of heterogeneous wetting states throughout rock pore structures. We demonstrate the approach with water-oil fluid pairs on rocks with distinct lithologies (sandstone and carbonate) and wetting states (hydrophilic, intermediate wetting, or heterogeneously wetting). The resulting 3D maps...
A pore-level scenario for the development of mixed wettability in oil reservoirs
AIChE Journal, 1993
Understanding the role of thin films in porous media is vital to elucidate wettability at the pore level. The type and thickness of films coating pore walls determine reservoir wettability and whether or not reservoir rock can be altered from its initial state of wettability. Pore shape, especial& pore wall curvature, is important in determining wetting-film thicknesses. Yet, pore shape and physics of thin wetting films are generally neglected in flow models in porous rocks. Thin-film forces incorporated into a collection of star-shaped capillary tubes model describe the geological development of mixed wettability in reservoir rock. Here, mixed wettability refers to continuous and distinct oil and water-wetting surfaces coexisting in the porous medium. This model emphasizes the remarkable role of thin films.
Added insight from image-based wettability characterization
E3S Web of Conferences
Microtomographic rock and fluid imaging under in-situ conditions is applied for reservoir wettability characterization. The investigation entails careful sample preparation and cleaning of mini-plugs, operation with reservoir fluids, wettability restoration, centrifuge wettability testing cycles, repeated sample scanning and image analysis, parametrization of wettability and digital rocks simulation for input into reservoir modeling. The results are compared to conventional Amott testing performed in core laboratories. Determination of saturations from image analysis, instead of centrifuge production, allows the use of stock tank crude, rather than exchanged mineral oil. Doping of the synthetic formation water (here with 1 M sodium iodide) was applied for enhancement of the X-ray contrast. The digital imaging workflow offers insight on the liquid distributions from the plug scale down to the pore-scale, linked to applied pressure gradients and resulting pore fluid occupancies in the...
Nanoscale imaging of pore-scale fluid-fluid-solid contacts in sandstone
Geophysical Research Letters, 2015
Direct observations of oil-water-rock contacts are key for improving our understanding of multiphase flow phenomena in mixed-wet reservoir rocks. In this study we imaged pore-scale fluid-fluid-solid contacts in sandstone with nanometer resolution using cryogenic broad ion-beam polishing in combination with scanning electron microscopy and phase identification by energy-dispersive X-ray analysis. We observed, as expected, the nonwetting oil phase separated from quartz surfaces by a thin brine film, but also direct contacts between oil and rock at asperities and clay aggregates, which act as pinning points and cause discontinuous motion of the oil-water-solid contact line. For the rare classical configuration of a three-phase contact the microscopic contact angle has been determined by serial sectioning. Our results call for improvements in models of multiphase pore-scale flow in digital rocks.
Wettability Analysis Using Micro-CT, Fesem and Qemscan, and Its Applications to Digital Rock Physics
2015
This study presents an integrated methodology for determining the pore-scale distribution of wettability of rock samples to guide pore network modeling. Wettability was characterized by spatial registration of rock images from X-ray micro-computed tomography (MCT), Field Emission Scanning Electron Microscopy (FESEM), and Quantitative Evaluation of Minerals by SEM (QEMSCAN). The approach was applied to miniplugs of an outcrop and a reservoir sandstone, which were drained and aged in oil and underwent spontaneous and forced imbibition of brine. Tomogram acquisition after each preparation step showed that, from similarly low initial water saturation, oil recovery by spontaneous imbibition was high in the outcrop and virtually zero in the reservoir sample, while the additional recovery by forced imbibition was the opposite. These results and the pore-scale distributions of remaining oil suggest different wettabilities for each sample though their petrophysical properties (porosity and permeability) are similar. The cleaned miniplugs were then subjected to FESEM mapping of raw cut faces to visualize local wettability alteration, and to QEMSCAN of polished faces to relate this to surface mineralogy. The established wettability information was then used to assign plausible wettability parameters to pores and throats of topologically equivalent networks. The simulated oil/water displacement results for the reservoir sandstone showed good agreement with available SCAL data.