Spatial Correlation of Contact Angle and Curvature in Pore-Space Images (original) (raw)
Related papers
Multiphase flow in porous media is strongly influenced by the wettability of the system, which affects the arrangement of the interfaces of different phases residing in the pores. We present a method for estimating the effective contact angle, which quantifies the wettability and controls the local capillary pressure within the complex pore space of natural rock samples, based on the physical constraint of constant curvature of the interface between two fluids. This algorithm is able to extract a large number of measurements from a single rock core, resulting in a characteristic distribution of effective in situ contact angle for the system, that is modelled as a truncated Gaussian probability density distribution. The method is first validated on synthetic images, where the exact angle is known analytically; then the results obtained from measurements within the pore space of rock samples imaged at a resolution of a few microns are compared to direct manual assessment. Finally the method is applied to X-ray micro computed tomog-raphy (micro-CT) scans of two Ketton cores after waterflooding, that display water-wet and mixed-wet behaviour. The resulting distribution of in situ contact angles is characterized in terms of a mixture of truncated Gaussian densities. Crown
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.
Journal of Petroleum Exploration and Production Technology, 2020
Estimating the contact angle in very complex rock pores presents some challenges to accurately identify the fluid–rock contact surface. This work presents a methodology to estimate the contact angle formed by the brine–rock and the brine–oil interfaces on processing high-resolution images provided by micro-CT scan. We focus the discussion on the limitations of the most popular computational techniques used to determine the contact angle and discuss how to select a practical way to evaluate it. The method consists of four steps: (1) processing the images to determine each fluid present in the image, (2) selection of the pixels that will be part of the contact interface of fluids and the contact point, (3) fitting polynomial equations for each interface and selection of the equation that gives the lowest error, (4) estimation of the contact angle based on the more appropriate polynomial equation. The contact angle is calculated based on the slope of the interfaces’ tangents at the con...
Automated extraction of in situ contact angles from micro-computed tomography images of porous media
Computers & Geosciences
This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
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.
Petroleum Science and Technology, 2019
Wettability contact angle characterization will be investigated by 2D technologies and a deterministic model is developed. Deterministic approach is a robust technique using 2D image capturing and image analyses that are applied on a Kuwaiti silty sandstone reservoir to accurately quantify wetting contact angle trends in the rock sample. And, then, generate all possible pore contact angles. In this study, heavy oil recovery prediction model is also developed by constructing mathematical model based on statistical grouping and averaging for all measured pore-walls available and quantifying wetting contact angle follows morphological approach that has greater confidence.
2019
Models of fluid flow are used to improve the efficiency of oil and gas extraction and to estimate the storage and leakage of carbon dioxide in geologic reservoirs. Therefore, a quantitative understanding of key parameters of rock−fluid interactions, such as contact angles, wetting, and the rate of spontaneous imbibition, is necessary if these models are to predict reservoir behavior accurately. In this study, aqueous fluid imbibition rates were measured in fractures in samples of the Eagle Ford Shale using neutron imaging. Several liquids, including pure water and aqueous solutions containing sodium bicarbonate and sodium chloride, were used to determine the impact of solution chemistry on uptake rates. Uptake rate analysis provided dynamic contact angles for the Eagle Ford Shale that ranged from 51 to 90°using the Schwiebert−Leong equation, suggesting moderately hydrophilic mineralogy. When corrected for hydrostatic pressure, the average contact angle was calculated as 76 ± 7°, with higher values at the fracture inlet. Differences in imbibition arising from differing fracture widths, physical liquid properties, and wetting front height were investigated. For example, bicarbonate-contacted samples had average contact angles that varied between 62 ± 10°and ∼84 ± 6°as the fluid rose in the column, likely reflecting a convergence−divergence structure within the fracture. Secondary imbibitions into the same samples showed a much more rapid uptake for water and sodium chloride solutions that suggested alteration of the clay in contact with the solution producing a waterwet environment. The same effect was not observed for sodium bicarbonate, which suggested that the bicarbonate ion prevented shale hydration. This study demonstrates how the imbibition rate measured by neutron imaging can be used to determine contact angles for solutions in contact with shale or other materials and that wetting properties can vary on a relatively fine scale during imbibition, requiring detailed descriptions of wetting for accurate reservoir modeling.
Energy & Fuels, 2019
Low salinity water flooding appears to be a promising means to improve oil recovery in carbonate reservoirs due to a wettability alteration process. Contact angle measurement is a direct approach to reveal the wettability alteration in oil-brine-carbonate system. However, questions have been raised about using contact angle measurement to justify the wettability alteration. This is because contact angle may be significantly affected by surface roughness variation in the presence of low salinity water due to calcite dissolution during the contact angle measurement. To clarify the cause and effect of wettability alteration during low salinity water flooding, we measured contact angle on two calcite substrates with similar surface roughness
Wettability plays a crucial role on the performance of enhancing oil recovery techniques because of its effect on fluid saturations and flow behavior in porous medium. This study is directed toward determining contact angles (i.e., wettability) in systems with carbon dioxide, brine, and an oil-saturated rock system. Two situations are considered: Rock system I is partially water-wet, whereas rock system II is effectively oil-wet. Contact angles have been determined experimentally as a function of brine salinity and pressure using the pendant-drop shape analysis. The experiments were carried out at a constant temperature of 318 K and pressures varying between 0.1 up to 16.0 MPa in a pendant-drop cell. For rock system I, the partially water-wet substrate, brine, and CO 2 system, the dependence on the pressure at constant salinity is very small. For this system, at a constant pressure, the contact angle decreases for increasing brine salinity. The results show that the carbon dioxide is the nonwetting phase in the pressure and salinity range studied. This behavior can be quantitatively understood in terms of the expected dependencies of the three interfacial tensions (IFTs) in Young's equation on pressure and brine salinity. For rock system II, the effectively oil-wet substrate, brine, and CO 2 system, the dependency of contact angle on pressure is considerable. This study proves that carbon dioxide becomes the wetting phase at pressures higher than 10.0 MPa. Beyond 10.0 MPa (i.e., in the supercritical region), the contact angle remains practically constant. The effect of salinity on the contact angle of the oil-wet rock system II is small. The behavior can again be quantitatively understood based on expected trends of the three IFTs that determine the contact angle. It is also shown that use of the equation of state method makes it possible to approach the experimental data quantitatively. We conclude that contact angle measurements form an essential ingredient to determine the efficiency of carbon dioxide flooding and storage.
In Situ Wettability Investigation of Aging of Sandstone Surface in Alkane via X-ray Microtomography
Energies
Wettability of surfaces remains of paramount importance for understanding various natural and artificial colloidal and interfacial phenomena at various length and time scales. One of the problems discussed in this work is the wettability alteration of a three-phase system comprising high salinity brine as the aqueous phase, Doddington sandstone as porous rock, and decane as the nonaqueous phase liquid. The study utilizes the technique of in situ contact angle measurements of the several 2D projections of the identified 3D oil phase droplets from the 3D images of the saturated sandstone miniature core plugs obtained by X-ray microcomputed tomography (micro-CT). Earlier works that utilize in situ contact angles measurements were carried out for a single plane. The saturated rock samples were scanned at initial saturation conditions and after aging for 21 days. This study at ambient conditions reveals that it is possible to change the initially intermediate water-wet conditions of the ...