415 results found
Blunt MJ, Lin Q, Akai T, et al., 2019, A thermodynamically consistent characterization of wettability in porous media using high-resolution imaging., J Colloid Interface Sci, Vol: 552, Pages: 59-65
Conservation of energy is used to derive a thermodynamically-consistent contact angle, θt, when fluid phase 1 displaces phase 2 in a porous medium. Assuming no change in Helmholtz free energy between two local equilibrium states we find that Δa1scosθt=κϕΔS1+Δa12, where a is the interfacial area per unit volume, ϕ is the porosity, S is the saturation and κ the curvature of the fluid-fluid interface. The subscript s denotes the solid, and we consider changes, Δ, in saturation and area. With the advent of high-resolution time-resolved three-dimensional X-ray imaging, all the terms in this expression can be measured directly. We analyse imaging datasets for displacement of oil by water in a water-wet and a mixed-wet sandstone. For the water-wet sample, the curvature is positive and oil bulges into the brine with almost spherical interfaces. In the mixed-wet case, larger interfacial areas are found, as the oil resides in layers. The mean curvature is close to zero, but the interface tends to bulge into brine in one direction, while brine bulges into oil in the other. We compare θt with the values measured geometrically in situ on the pore-scale images, θg. The thermodynamic angle θt provides a robust and consistent characterization of wettability. For the water-wet case the calculated value of θt gives an accurate prediction of multiphase flow properties using pore-scale modelling.
Abd AS, Elhafyan E, Siddiqui AR, et al., 2019, A review of the phenomenon of counter-current spontaneous imbibition: Analysis and data interpretation, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 180, Pages: 456-470, ISSN: 0920-4105
Raeini AQ, Yang J, Bondino I, et al., Validating the generalized pore network model using micro-CT images of two-phase flow, Transport in Porous Media, Pages: 1-20, ISSN: 0169-3913
A reliable prediction of two-phase flow through porous media requires the development and validation of models for flow across multiple length scales. The generalized network model is a step towards efficient and accurate upscaling of flow from the pore to the core scale. This paper presents a validation of the generalized network model using micro-CT images of two-phase flow experiments on a pore-by-pore basis. Three experimental secondary imbibition datasets are studied for both sandstone and carbonate rock samples. We first present a quantification of uncertainties in the experimental measurements. Then, we show that the model can reproduce the experimental fluid occupancies and saturations with a good accuracy, which in some cases is comparable with the similarity between repeat experiments. However, high-resolution images need to be acquired to characterize the pore geometry for modelling, while the results are sensitive to the initial condition at the end of primary drainage. The results provide a methodology for improving our physical models using large experimental datasets which, at the pore scale, can be generated using micro-CT imaging of multiphase flow.
Akai T, Lin Q, Alhosani A, et al., 2019, Quantification of uncertainty and best practice in computing interfacial curvature from complex pore space images., Materials (Basel), Vol: 12, Pages: 1-21, ISSN: 1996-1944
Recent advances in high-resolution three-dimensional X-ray CT imaging have made it possible to visualize fluid configurations during multiphase displacement at the pore-scale. However, there is an inherited difficulty in image-based curvature measurements: the use of voxelized image data may introduce significant error, which has not-to date-been quantified. To find the best method to compute curvature from micro-CT images and quantify the likely error, we performed drainage and imbibition direct numerical simulations for an oil/water system on a bead pack and a Bentheimer sandstone. From the simulations, local fluid configurations and fluid pressures were obtained. We then investigated methods to compute curvature on the oil/water interface. The interface was defined in two ways; in one case the simulated interface with a sub-resolution smoothness was used, while the other was a smoothed interface extracted from synthetic segmented data based on the simulated phase distribution. The curvature computed on these surfaces was compared with that obtained from the simulated capillary pressure, which does not depend on the explicit consideration of the shape of the interface. As distinguished from previous studies which compared an average or peak curvature with the value derived from the measured macroscopic capillary pressure, our approach can also be used to study the pore-by-pore variation. This paper suggests the best method to compute curvature on images with a quantification of likely errors: local capillary pressures for each pore can be estimated to within 30% if the average radius of curvature is more than 6 times the image resolution, while the average capillary pressure can also be estimated to within 11% if the average radius of curvature is more than 10 times the image resolution.
Gao Y, Qaseminejad Raeini A, Blunt MJ, et al., 2019, Pore occupancy, relative permeability and flow intermittency measurements using X-ray micro-tomography in a complex carbonate, Advances in Water Resources, Vol: 129, Pages: 56-69, ISSN: 0309-1708
We imaged the steady-state flow of brine and decane (oil) at different fractional flows during dual injection in a micro-porous limestone, Estaillades, using X-ray micro-tomography. We applied differential imaging to: (a) distinguish micro-porous regions from macro-pores, and (b) determine fluid pore occupancy in both regions, and relative permeability at a capillary number, Ca = 7.3 × 10 −6 . The sample porosity was approximately 28%, with 7% in macro-pores and 21% in pores that could not be directly resolved (micro-porosity). Fluid occupancy in micro-porosity was classified into three sub-phases: micro-pore space with oil, micro-pore space with brine, and micro-pores partially filled with oil and brine. Our method indicated an initially higher oil recovery from micro-porosity, consistent with waterflooding in a water-wet rock. The fractional flow and relative permeabilities of the two fluids were obtained from measurements of the pressure differential across the sample and the saturation calculated from the images. The brine saturation and relative permeabilities are impacted by the presence of water-wet micro-porosity which provides additional connectivity to the phases. Furthermore, we find that in addition to brine and decane, a fraction of the macroscopic pore space contains an intermittent phase, which is occupied either by brine or decane during the hour-long scan time. Pore and throat occupancy of oil, brine and intermittent phase were obtained from images at different fractional flows using the generalized pore network extracted from the image of macro-pores. The intermittent phase, where the occupancy fluctuated between oil-filled and brine-filled, was predominantly located in the small and intermediate size pores and throats. Overall, we establish a new experimental methodology to: (i) quantify initial and recovered oil in micro-pores, (ii) characterise intermittent flow, and (iii) measure steady-state relative permeability in carbonates, whi
Lin Q, Bijeljic B, Berg S, et al., 2019, Minimal surfaces in porous media: Pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone, Physical Review E, Vol: 99, Pages: 063105-1-063105-13, ISSN: 1539-3755
High-resolution x-ray imaging was used in combination with differential pressure measurements to measurerelative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on asample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil toalter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flowrate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, x-raytomographic images were taken. The images were used to compute saturation, interfacial area, curvature, andcontact angle. From this information relative permeability and capillary pressure were determined as functionsof saturation. We compare our results with a previously published experiment under water-wet conditions. Theoil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, ofapproximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock.The capillary pressure was slightly negative and 10 times smaller in magnitude than for the water-wet rock,and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area wasalso largely constant in this saturation range. The measured static contact angles had an average of 80◦ with astandard deviation of 17◦. We observed that the oil-brine interfaces were not flat, as may be expected for a verylow mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. Theseinterfaces were approximately minimal surfaces, which implies well-connected phases. Saddle-shaped menisciswept through the pore space at a constant capillary pressure and with an almost fixed area, removing most ofthe oil.
Oliveira TDS, Blunt MJ, Bijeljic B, 2019, Modelling of multispecies reactive transport on pore-space images, Advances in Water Resources, Vol: 127, Pages: 192-208, ISSN: 0309-1708
We present a new model, named poreReact, to simulate multispecies reactive transport on pore space images. We solve the Navier–Stokes equations and the advection-diffusion equation for concentration on an unstructured grid using the finite volume method implemented in OpenFOAM. We couple it with the chemical model Reaktoro, which we use to calculate the chemical equilibrium of homogeneous reactions in each grid cell, considered as a completely mixed batch reactor. We validate the model against analytical solutions and experimental data, and investigate, for a range of Péclet numbers, the interplay between transport and reaction for multispecies reactive transport in a 3D bead pack where two streams of reactants at different pH are injected in parallel. We analyse the distribution of species and the rates of formation and consumption in the pore space and find that, despite the relative homogeneity of the bead pack and symmetry in injection conditions, the concentration fields of the products can be asymmetric because of the interplay between transport and chemical equilibrium. For different Péclet numbers, we calculate relative yields (the ratio between the observed change in concentration and the change that would be obtained if the reactants were completely mixed). We observe that lower Péclet numbers give rise to higher relative yields because of increased transverse mixing by diffusion. However, higher absolute yields are obtained at higher injection velocities because of the larger amount of matter available for reaction in a given time. Reaction is more favoured in the faster-flowing regions of the pore space. However, this effect is more marked for species for which advection is the dominant mechanism of transport to reactive sites, as opposed to diffusion-mediated reactions where the full velocity distribution is sampled before reaction occurs.
Al-Khulaifi Y, Lin Q, Blunt MJ, et al., 2019, Pore-scale dissolution by CO₂ saturated brine in a multimineral carbonate at reservoir conditions: impact of physical and chemical heterogeneity, Water Resources Research, Vol: 55, Pages: 3171-3193, ISSN: 0043-1397
We study the impact of physical and chemical heterogeneity on reaction rates in multimineral porous media. We selected two pairs of carbonate samples of different physical heterogeneity in accordance with their initial computed velocity distributions and then injected CO 2 saturated brine at reservoir conditions at two flow rates. We periodically imaged the samples using X-ray microtomography. The mineralogical composition was similar (a ratio of dolomite to calcite of 8:1), but the intrinsic reaction rates and mineral spatial distribution were profoundly different. Visualizations of velocity fields and reacted mineral distributions revealed that a dominant flow channel formed in all cases. The more physically homogeneous samples had a narrower velocity distribution and more preexisting fast channels, which promoted dominant channel formation in their proximity. In contrast, the heterogeneous samples exhibit a broader distribution of velocities and fewer fast channels, which accentuated nonuniform calcite distribution and favored calcite dissolution away from the initially fast pathways. We quantify the impact of physical and chemical heterogeneity by computing the proximity of reacted minerals to the fast flow pathways. The average reaction rates were an order of magnitude lower than the intrinsic ones due to mass transfer limitations. The effective reaction rate of calcite decreased by an order of magnitude, in both fast channels and slow regions. After channel formation calcite was shielded by dolomite whose effective rate in slow regions could even increase. Overall, the preferential channeling effect, as opposed to uniform dissolution, was promoted by a higher degree of physical and/or chemical heterogeneity.
Lin Q, Bijeljic B, Krevor SC, et al., 2019, A new waterflood initialization protocol with wettability alteration for pore-scale multiphase flow experiments, Petrophysics, Vol: 60, Pages: 264-272, ISSN: 1529-9074
© 2019 Society of Well Log Analystists Inc. All rights reserved. In the context of digital rock analysis, pore-scale imaging of multiphase flow experiments using X-ray microtomography can be used to obtain fundamental insights into pore-scale displacement physics. This provides a basis to better calibrate numerical pore-scale simulators, or it can be used to understand local fluid distributions, while simultaneously measuring average properties, equivalent to a traditional SCAL experiment. Imaging studies in the literature have historically been conducted on small water-wet plugs, using kerosene, or another refined oil, as the non-wetting phase. Prior to conducting waterflood experiments, the initial water saturation has been established by dynamic flooding. The disadvantage with this is that a nonuniform saturation profile is established due to the capillary end effect. This will result in a higher average initial water saturation compared with, for instance, standard SCAL techniques, such as the porous-plate method or centrifugation. In this paper, a methodology for initializing multiple small rock samples to the same connate water saturation and wettability state has been developed by adopting best SCAL practices, namely the porous-plate method or centrifugation using crude oil, followed by aging. We drill multiple small plugs from a full-size SCAL core sample, without losing capillary continuity with the base of the original sample. In the example presented, for Bentheimer sandstone, the initial saturation was established using centrifugation. The experiment is designed to prevent a nonuniform saturation profile in the small plugs. We use in-situ imaging to determine the water saturation after primary drainage and show that it is indeed uniform across the sample with a value consistent with larger- scale SCAL measurements and the measured mercury- injection capillary pressure. We also show that a significant wettability alteration had occurred by measuring
Rücker M, Bartels WB, Singh K, et al., 2019, The Effect of Mixed Wettability on Pore-Scale Flow Regimes Based on a Flooding Experiment in Ketton Limestone, Geophysical Research Letters, Vol: 46, Pages: 3225-3234, ISSN: 0094-8276
© 2019. The Authors. Darcy-scale multiphase flow in geological formations is significantly influenced by the wettability of the fluid-solid system. So far it has not been understood how wettability impacts the pore-scale flow regimes within rocks, which were in most cases regarded as an alteration from the base case of strongly water-wet conditions by adjustment of contact angles. In this study, we directly image the pore-scale flow regime in a carbonate altered to a mixed-wet condition by aging with crude oil to represent the natural configuration in an oil reservoir with fast synchrotron-based X-ray computed tomography. We find that the pore-scale flow regime is dominated by ganglion dynamics in which the pore space is intermittently filled with oil and brine. The frequency and size of these fluctuations are greater than in water-wet rock such that their impact on the overall flow and relative permeability cannot be neglected in modeling approaches.
Singh K, Muljadi B, Raeini AQ, et al., The architectural design of smart ventilation and drainage systems in termite nests, Science Advances, ISSN: 2375-2548
Termite nests have been widely studied as effective examples for ventilation and thermoregulation;however, the mechanisms by which the nest properties are controlled by the micro-structure of the outer walls remain unclear. Here, we combine multi-scale X-ray imaging with three-dimensional flow field simulations to investigate the impact of the architectural design of nest walls on CO2and heat transport as well as on water drainage. We show that termites construct an outer wall that contains both small and percolating large pores at the micro-scale. The network of larger micro-scale pores in the outer wall provides a permeability that is 1-2 orders of magnitude greater than that of the smaller pores, andaCO2diffusivitythat is a factor of up to eight times larger. The largerpores and resultant high porosity also reduce the solid mass required for nest construction by ~11-14%. This is energetically favorable and reduces the overall weight of the nest, thus lowering the risk of collapse. In addition, the pore network offers enhanced thermal insulation to the inner parts of the nest and allows quick drainage ofrainwater thereby restoring the ventilation and providing structural stability to the wet nest.
Franchini S, Charogiannis A, Markides CN, et al., 2019, Calibration of astigmatic particle tracking velocimetry based on generalized Gaussian feature extraction, Advances in Water Resources, Vol: 124, Pages: 1-8, ISSN: 0309-1708
Flow and transport in porous media are driven by pore scale processes. Particle tracking in transparent porous media allows for the observation of these processes at the time scale of ms. We demonstrate an application of defocusing particle tracking using brightfield illumination and a CMOS camera sensor. The resulting images have relatively high noise levels. To address this challenge, we propose a new calibration for locating particles in the out-of-plane direction. The methodology relies on extracting features of particle images by fitting generalized Gaussian distributions to particle images. The resulting fitting parameters are then linked to the out-of-plane coordinates of particles using flexible machine learning tools. A workflow is presented which shows how to generate a training dataset of fitting parameters paired to known out-of-plane locations. Several regression models are tested on the resulting training dataset, of which a boosted regression tree ensemble produced the lowest cross-validation error. The efficiacy of the proposed methodology is then examined in a laminar channel flow in a large measurement volume of 2048, 1152 and 3000 μm in length, width and depth respectively. The size of the test domain reflects the representative elementary volume of many fluid flow phenomena in porous media. Such large measurement depths require the collection of images at different focal levels. We acquired images at 21 focal levels 150 μm apart from each other. The error in predicting the out-of-plane location in a single slice of 240 μm thickness was found to be 7 μm, while in-plane locations were determined with sub-pixel resolution (below 0.8 μm). The mean relative error in the velocity measurement was obtained by comparing the experimental results to an analytic model of the flow. The estimated displacement errors in the axial direction of the flow were 0.21 pixel and 0.22 pixel at flows rates of 1.0 mL/h and 2.5 mL/h, respectively. These resu
Saif T, Lin Q, Gao Y, et al., 2019, 4D in situ synchrotron X-ray tomographic microscopy and laser-based heating study of oil shale pyrolysis, Applied Energy, Vol: 235, Pages: 1468-1475, ISSN: 0306-2619
The comprehensive characterization and analysis of the evolution of micro-fracture networks in oil shales during pyrolysis is important to understand the complex petrophysical changes during hydrocarbon recovery. We used time-resolved X-ray microtomography to perform pore-scale dynamic imaging with a synchrotron light source to capture in 4-D (three-dimensional image + real time) the evolution of fracture initiation, growth, coalescence and closure. A laser-based heating system was used to pyrolyze a sample of Eocene Green River (Mahogany Zone) up to 600 °C with tomograms acquired every 30 s at 1.63 µm computed voxel size and analyzed using Digital Volume Correlation (DVC) for full 3-D strain and deformation maps. At 354 °C the first isolated micro-fractures were observed and by 378 °C, a connected fracture network was formed as the solid organic matter was transformed into volatile hydrocarbon components. With increasing temperature, we observed simultaneous pore space growth and coalescence as well as temporary closure of minor fractures caused by local compressive stresses. This indicates that the evolution of individual fractures not only depends on organic matter composition but also on the dynamic development of neighboring fractures. Our results demonstrate that combining synchrotron X-ray tomography, laser-based heating and DVC provides a powerful methodology for characterizing dynamics of multi-scale physical changes during oil shale pyrolysis to help optimize hydrocarbon recovery.
Leu L, Bertier P, Georgiadis A, et al., 2019, SAXS and WAXS microscopy applied to mudrocks: A new method for systematic multiscale studies of porosity, pore orientation and mineralogy
© 2019 European Association of Geoscientists and Engineers, EAGE. All Rights Reserved. We apply scanning SAXS and WAXS microscopy to different mudrock samples. The method characterizes the microstructure in terms of porosity and preferential pore alignment of small pores 6 -202 nm size. These small features are experimentally challenging to resolve for statistically relevant sample volumes with state of the art characterization techniques, such as imaging methods. A key novelty in this study is the quantification of the mineralogy and mineral phase content from the WAXS measurements. Thus, a detailed quantification and comparison of important microstructural parameters is achieved. The method is used in a raster scanning mode, where thousands of consecutive measurements are performed, with a high micrometric spatial resolution, over mm sized sample areas. Therefore, simultaneously the variation of the microstructure is resolved on the pore and lamina scale. We propose to use scanning SAXS-WAXS microcopy in future studies for investigations of the systematic relationships between mineralogy and the pore network.
Scanziani A, Alhammadi A, Bijeljic B, et al., 2019, Three-phase flow visualization and characterization for a mixed-wet carbonate rock
© Copyright 2018, Society of Petroleum Engineers. A novel method is presented to characterise in situ three-phase flow, including wettability, pore occupancy and displacement mechanisms, at the pore scale. We used X-ray microtomography to obtain 3D images of a carbonate reservoir rock saturated with crude oil and formation brine at subsurface conditions. The sample had been aged with crude oil from the same reservoir to replicate the sunsurface wetting conditions. The pore occupancy analysis shows that brine is non-wetting to oil and gas is non-wetting to brine with a wettability order of oil-brine-gas from the most to the least wetting fluid. The waterflood recovery after 1 pore volume injected was only 14%, but this increased to 48% after further gas injection. New multiple displacement mechanisms were observed, with gas displacing brine, which in turn displaces oil. The results from this work can be used to improve the prediction accuracy of the three-phase network models and helps in the design of gas injection processes.
Akai T, Alhammadi AM, Blunt MJ, et al., 2019, Direct multiphase numerical simulation on mixed-wet reservoir carbonates
© Copyright 2018, Society of Petroleum Engineers. To better understand local displacement efficiency, direct numerical simulations of water-flooding in a mixed-wet rock from a producing reservoir were performed using the multiphase Lattice Boltzmann (LB) method. Experimentally measured contact angles (AlRatrout et al., 2017) were incorporated into the simulation models using our previously reported wetting boundary condition for the LB method (Akai et al., 2018b). The simulation model was calibrated by comparing pore occupancy and fluid conductivity with results from an experimental water-flooding study where the fluid configurations were imaged at a resolution of a few microns (Alhammadi et al., 2017, 2018). Furthermore, to investigate the impact of several enhanced oil recovery (EOR) schemes on recovery, the calibrated simulation model was also used for a sensitivity study. Taking the calibrated model as a base case, three EOR cases were investigated; low salinity water-flooding, surfactant flooding and polymer flooding. For low salinity water-flooding, the wettability of pore walls was changed to be more water-wet than that of the base case. For surfactant flooding, the interfacial tension was reduced. For polymer flooding, the viscosity of injection water was increased. A significant change in oil recovery factor was observed in these cases. These results make it possible to better understand the impact of EOR schemes on microscopic recovery. We demonstrate the predictive power of our direct numerical simulation by presenting comparisons of the fluid distribution at the pore-scale between the experiment and simulation. Then, we show how direct numerical simulation helps understand EOR schemes. This work provides a comprehensive workflow for pore-scale modeling from experiments to modeling.
Singh K, Menke H, Andrew M, et al., 2018, Timeresolved synchrotron X-ray micro-tomography datasets of drainage and imbibition in carbonate rocks, Scientific Data, Vol: 5, ISSN: 2052-4463
Multiphase flow in permeable media is a complex pore-scale phenomenon, which is important in many natural and industrial processes. To understand the pore-scale dynamics of multiphase flow, we acquired time-series synchrotron X-ray micro-tomographic data at a voxel-resolution of 3.28 μm and time-resolution of 38 s during drainage and imbibition in a carbonate rock, under a capillary-dominated flow regime at elevated pressure. The time-series data library contains 496 tomographic images (gray-scale and segmented) for the complete drainage process, and 416 tomographic images (gray-scale and segmented) for the complete imbibition process. These datasets have been uploaded on the publicly accessible British Geological Survey repository, with the objective that the time-series information can be used by other groups to validate pore-scale displacement models such as direct simulations, pore-network and neural network models, as well as to investigate flow mechanisms related to the displacement and trapping of the non-wetting phase in the pore space. These datasets can also be used for improving segmentation algorithms for tomographic data with limited projections.
Singh K, Anabaraonye BU, Blunt MJ, et al., 2018, Partial dissolution of carbonate rock grains during reactive CO<inf>2</inf>-saturated brine injection under reservoir conditions, Advances in Water Resources, Vol: 122, Pages: 27-36, ISSN: 0309-1708
One of the major concerns of carbon capture and storage (CCS) projects is the prediction of the long-term storage security of injected CO2. When injected underground in saline aquifers or depleted oil and gas fields, CO2mixes with the resident brine to form carbonic acid. The carbonic acid can react with the host carbonate rock, and alter the rock structure and flow properties. In this study, we have used X-ray micro-tomography and focused ion beam scanning electron microscopy (FIB-SEM) techniques to investigate the dissolution behavior in wettability-altered carbonate rocks at the nm- to µm-scale, to investigate CO2storage in depleted oil fields that have oil-wet or mixed-wet conditions. Our novel procedure of injecting oil after reactive transport has revealed previously unidentified (ghost) regions of partially-dissolved rock grains that were difficult to identify in X-ray tomographic images after dissolution from single fluid phase experiments. We show that these ghost regions have a significantly higher porosity and pore sizes that are an order of magnitude larger than that of unreacted grains. The average thickness of the ghost regions as well as the overall rock dissolution decreases with increasing distance from the injection point. During dissolution micro-porous rock retains much of its original fabric. This suggests that considering the solid part of these ghost regions as macro (bulk) pore space can result in the overestimation of porosity and permeability predicted from segmented X-ray tomographic images, or indeed from reactive transport models that assume a uniform, sharp reaction front at the grain surface.
Akai T, Alhammadi AM, Blunt MJ, et al., 2018, Modeling oil recovery in mixed-wet rocks: Pore-scale comparison between experiment and simulation, Transport in Porous Media, ISSN: 0169-3913
To examine the need to incorporate in situ wettability measurements in direct numerical simulations, we compare waterflooding experiments in a mixed-wet carbonate from a producing reservoir and results of direct multiphase numerical simulations using the color-gradient lattice Boltzmann method. We study the experiments of Alhammadi et al. (Sci Rep 7(1):10753, 2017. https://doi.org/10.1038/s41598-017-10992-w) where the pore-scale distribution of remaining oil was imaged using micro-CT scanning. In the experiment, in situ contact angles were measured using an automated algorithm (AlRatrout et al. in Adv Water Resour 109:158–169, 2017. https://doi.org/10.1016/j.advwatres.2017.07.018), which indicated a mixed-wet state with spatially non-uniform angles. In our simulations, the pore structure was obtained from segmented images of the sample used in the experiment. Furthermore, in situ measured angles were also incorporated into our simulations using our previously developed wetting boundary condition (Akai et al. in Adv Water Resour 116(March):56–66, 2018. https://doi.org/10.1016/j.advwatres.2018.03.014). We designed six simulations with different contact angle assignments based on experimentally measured values. Both a constant contact angle based on the average value of the measured values and non-uniform contact angles informed by the measured values gave a good agreement for fluid pore occupancy between the simulation and the experiment. However, the constant contact angle assignment predicted 54% higher water effective permeability after waterflooding than that estimated for the experimental result, whereas the non-uniform contact angle assignment gave less than 1% relative error. This means that to correctly predict fluid conductivity in mixed-wet rocks, a spatially heterogeneous wettability state needs to be taken into account. The novelty of this work is to provide a direct pore-scale comparison between experiments and simulations employing experiment
Scanziani A, Singh K, Bultreys T, et al., 2018, In situ characterization of immiscible three-phase flow at the pore scale for a water-wet carbonate rock, Advances in Water Resources, Vol: 121, Pages: 446-455, ISSN: 0309-1708
X-ray micro-tomography is used to image the pore-scale configurations of fluid in a rock saturated with three phases - brine, oil and gas - mimicking a subsurface reservoir, at high pressure and temperature. We determine pore occupancy during a displacement sequence that involves waterflooding, gas injection and water re-injection. In the water-wet sample considered, brine occupied the smallest pores, gas the biggest, while oil occupied pores of intermediate size and is displaced by both water and gas. Double displacement events have been observed, where gas displaces oil that displaces water or vice versa. The thickness of water and oil layers have been quantified, as have the contact angles between gas and oil, and oil and water. These results are used to explain the nature of trapping in three-phase flow, specifically how oil preferentially traps gas in the presence of water.
Alhammadi AM, AlRatrout A, Bijeljic B, et al., 2018, Pore-scale Imaging and Characterization of Hydrocarbon Reservoir Rock Wettability at Subsurface Conditions Using X-ray Microtomography., Journal of Visualized Experiments, ISSN: 1940-087X
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 three-dimensional 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 CO2 in subsurface formations.
Lutz-Bueno V, Arboleda C, Leu L, et al., 2018, Model-free classification of X-ray scattering signals applied to image segmentation, Journal of Applied Crystallography, Vol: 51, Pages: 1378-1386, ISSN: 0021-8898
In most cases, the analysis of small-angle and wide-angle X-ray scattering(SAXS and WAXS, respectively) requires a theoretical model to describe thesample’s scattering, complicating the interpretation of the scattering resultingfrom complex heterogeneous samples. This is the reason why, in general, theanalysis of a large number of scattering patterns, such as are generated by time-resolved and scanning methods, remains challenging. Here, a model-freeclassification method to separate SAXS/WAXS signals on the basis of theirinflection points is introduced and demonstrated. This article focuses on thesegmentation of scanning SAXS/WAXS maps for which each pixel correspondsto an azimuthally integrated scattering curve. In such a way, the samplecomposition distribution can be segmented through signal classification withoutapplying a model or previous sample knowledge. Dimensionality reduction andclustering algorithms are employed to classify SAXS/WAXS signals according totheir similarity. The number of clusters,i.e.the main sample regions detected bySAXS/WAXS signal similarity, is automatically estimated. From each cluster, amain representative SAXS/WAXS signal is extracted to uncover the spatialdistribution of the mixtures of phases that form the sample. As examples ofapplications, a mudrock sample and two breast tissue lesions are segmented.
Mosser L, Dubrule O, Blunt MJ, 2018, Stochastic Reconstruction of an Oolitic Limestone by Generative Adversarial Networks, TRANSPORT IN POROUS MEDIA, Vol: 125, Pages: 81-103, ISSN: 0169-3913
Lin Q, Bijeljic B, Pini R, et al., 2018, Imaging and measurement of pore‐scale interfacial curvature to determine capillary pressure simultaneously with relative permeability, Water Resources Research, Vol: 54, Pages: 7046-7060, ISSN: 0043-1397
There are a number of challenges associated with the determination of relative permeability and capillary pressure. It is difficult to measure both parameters simultaneously on the same sample using conventional methods. Instead, separate measurements are made on different samples, usually with different flooding protocols. Hence, it is not certain that the pore structure and displacement processes used to determine relative permeability are the same as those when capillary pressure was measured. Moreover, at present, we do not use pore‐scale information from high‐resolution imaging to inform multiphase flow properties directly. We introduce a method using pore‐scale imaging to determine capillary pressure from local interfacial curvature. This, in combination with pressure drop measurements, allows both relative permeabilities and capillary pressure to be determined during steady state coinjection of two phases through the core. A steady state waterflood experiment was performed in a Bentheimer sandstone, where decalin and brine were simultaneously injected through the core at increasing brine fractional flows from 0 to 1. The local saturation and the curvature of the oil‐brine interface were determined. Using the Young‐Laplace law, the curvature was related to a local capillary pressure. There was a detectable gradient in both saturation and capillary pressure along the flow direction. The relative permeability was determined from the experimentally measured pressure drop and average saturation obtained by imaging. An analytical correction to the brine relative permeability could be made using the capillary pressure gradient. The results for both relative permeability and capillary pressure are consistent with previous literature measurements on larger samples.
AlRatrout A, Blunt MJ, Bijeljic B, 2018, Spatial correlation of contact angle and curvature in pore-space images, Water Resources Research, Vol: 54, Pages: 6133-6152, ISSN: 0043-1397
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, https://doi.org/10.1016/j.advwatres.2017.07.018), with a recently developed method for pore-network extraction (Raeini et al., 2017, https://doi.org/10.1103/PhysRevE.96.013312). The automated methods allow us to study image volumes of diameter approximately 1.9 mm and 1.2 mm long, obtaining hundreds of thousands of values from a data set with 435 million voxels. We calculate the capillary pressure based on the mode oil/brine interface curvature value and associate this value with a nearby throat in the pore space. We demonstrate the capability of our methods to distinguish different wettability states in the samples studied: water-wet, weakly oil-wet, and mixed-wet. The contact angle and oil/brine interface curvature are spatially correlated over approximately the scale of an average pore. There is a wide distribution of contact angles within a single pore. A range of local oil/brine interface curvature is found with both positive and negative values. There is a correlation between interfacial curvature and contact angle in trapped ganglia, with ganglia in water-wet patches tending to have a positive curvature and oil-wet regions seeing negative curvature. We observed a weak correlation between average contact angle and pore size, with the larger pores tending to be more oil-wet.
AlRatrout A, Blunt MJ, Bijeljic B, 2018, Wettability in complex porous materials, the mixed-wet state, and its relationship to surface roughness, Proceedings of the National Academy of Sciences, ISSN: 0027-8424
A quantitative in situ characterization of the impact of surface roughness on wettability in porous media is currently lacking. We use reservoir condition micrometer-resolution X-ray tomography combined with automated methods for the measurement of contact angle, interfacial curvature, and surface roughness to examine fluid/fluid and fluid/solid interfaces inside a porous material. We study oil and water in the pore space of limestone from a giant producing oilfield, acquiring millions of measurements of curvature and contact angle on three millimeter-sized samples. We identify a distinct wetting state with a broad distribution of contact angle at the submillimeter scale with a mix of water-wet and water-repellent regions. Importantly, this state allows both fluid phases to flow simultaneously over a wide range of saturation. We establish that, in media that are largely water wet, the interfacial curvature does not depend on solid surface roughness, quantified as the local deviation from a plane. However, where there has been a significant wettability alteration, rougher surfaces are associated with lower contact angles and higher interfacial curvature. The variation of both contact angle and interfacial curvature increases with the local degree of roughness. We hypothesize that this mixed wettability may also be seen in biological systems to facilitate the simultaneous flow of water and gases; furthermore, wettability-altering agents could be used in both geological systems and material science to design a mixed-wetting state with optimal process performance.
Shams M, Raeini AQ, Blunt MJ, et al., 2018, A study to investigate viscous coupling effects on the hydraulic conductance of fluid layers in two-phase flow at the pore level, Journal of Colloid and Interface Science, Vol: 522, Pages: 299-310, ISSN: 0021-9797
This paper examines the role of momentum transfer across fluid-fluid interfaces in two-phase flow. A volume-of-fluid finite-volume numerical method is used to solve the Navier-Stokes equations for two-phase flow at the micro-scale. The model is applied to investigate viscous coupling effects as a function of the viscosity ratio, the wetting phase saturation and the wettability, for different fluid configurations in simple pore geometries. It is shown that viscous coupling effects can be significant for certain pore geometries such as oil layers sandwiched between water in the corner of mixed wettability capillaries. A simple parametric model is then presented to estimate general mobility terms as a function of geometric properties and viscosity ratio. Finally, the model is validated by comparison with the mobilities computed using direct numerical simulation.
Akai T, Bijeljic B, Blunt MJ, 2018, Wetting boundary condition for the color-gradient lattice Boltzmann method: Validation with analytical and experimental data, Advances in Water Resources, Vol: 116, Pages: 56-66, ISSN: 0309-1708
In the color gradient lattice Boltzmann model (CG-LBM), a fictitious-density wetting boundary condition has been widely used because of its ease of implementation. However, as we show, this may lead to inaccurate results in some cases. In this paper, a new scheme for the wetting boundary condition is proposed which can handle complicated 3D geometries. The validity of our method for static problems is demonstrated by comparing the simulated results to analytical solutions in 2D and 3D geometries with curved boundaries. Then, capillary rise simulations are performed to study dynamic problems where the three-phase contact line moves. The results are compared to experimental results in the literature (Heshmati and Piri, 2014). If a constant contact angle is assumed, the simulations agree with the analytical solution based on the Lucas–Washburn equation. However, to match the experiments, we need to implement a dynamic contact angle that varies with the flow rate.
Alyafei N, Blunt MJ, 2018, Estimation of relative permeability and capillary pressure from mass imbibition experiments, ADVANCES IN WATER RESOURCES, Vol: 115, Pages: 88-94, ISSN: 0309-1708
Bultreys T, Lin Q, Gao Y, et al., 2018, Validation of model predictions of pore-scale fluid distributions during two-phase flow, Physical Review E, Vol: 97, ISSN: 2470-0045
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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