Publications
141 results found
Franchini S, Krevor S, 2020, Cut, overlap and locate: a deep learning approach for the 3D localization of particles in astigmatic optical setups, EXPERIMENTS IN FLUIDS, Vol: 61, ISSN: 0723-4864
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- Citations: 15
Zahasky C, Krevor S, 2020, Global geologic carbon storage requirements of climate change mitigation scenarios, Energy and Environmental Science, Vol: 13, Pages: 1561-1567, ISSN: 1754-5692
Integrated assessment models have identified carbon capture and storage (CCS) as an important technology for limiting climate change. To achieve 2 °C climate targets, many scenarios require tens of gigatons of CO2 stored per year by mid-century. These scenarios are often unconstrained by growth rates, and uncertainty in global geologic storage assessments limits resource-based constraints. Here we show how logistic growth models, a common tool in resource assessment, provide a mathematical framework for stakeholders to monitor short-term CCS deployment progress and long-term resource requirements in the context of climate change mitigation targets. Growth rate analysis, constrained by historic commercial CO2 storage rates, indicates sufficient growth to achieve several of the 2100 storage targets identified in the assessment reports of the Intergovernmental Panel on Climate Change. A maximum global discovered storage capacity of approximately 2700 Gt is needed to meet the most aggressive targets, with this ceiling growing if CCS deployment is delayed.
Zahasky C, Jackson SJ, Lin Q, et al., 2020, Pore Network Model Predictions of Darcy-Scale Multiphase Flow Heterogeneity Validated by Experiments, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
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- Citations: 16
Jackson SJ, Lin Q, Krevor S, 2020, Representative Elementary Volumes, Hysteresis, and Heterogeneity in Multiphase Flow From the Pore to Continuum Scale, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
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- Citations: 35
Liyanage R, Russell A, Crawshaw JP, et al., 2020, Direct experimental observations of the impact of viscosity contrast on convective mixing in a three-dimensional porous medium, Physics of Fluids, Vol: 32, Pages: 1-10, ISSN: 1070-6631
Analog fluids have been widely used to mimic the convective mixing of carbon dioxide into brine in the study of geological carbon storage. Although these fluid systems had many characteristics of the real system, the viscosity contrast between the resident fluid and the invading front was significantly different and largely overlooked. We used x-ray computed tomography to image convective mixing in a three-dimensional porous medium formed of glass beads and compared two invading fluids that had a viscosity 3.5× and 16× that of the resident fluid. The macroscopic behavior such as the dissolution rate and onset time scaled well with the viscosity contrast. However, with a more viscous invading fluid, fundamentally different plume structures and final mixing state were observed due in large part to greater dispersion.
Kirby ME, Watson JS, Najorka J, et al., 2020, Experimental study of pH effect on uranium (UVI) particle formation and transport through quartz sand in alkaline 0.1 M sodium chloride solutions, Colloids and Surfaces A: Physicochemical and Engineering Aspects, Vol: 592, Pages: 1-11, ISSN: 0927-7757
A thorough understanding of the aqueous uranium VI (UVI) chemistry in alkaline, sodium containing solutions is imperative to address a wide range of critical challenges in environmental engineering, including nuclear waste management. The aim of the present study was to characterise experimentally in more detail the control of pH on the removal of UVI from aqueous alkaline solutions through particle formation and on subsequent transport through porous media. We conducted first static batch experiments in the pH range between 10.5 and 12.5 containing 10 ppm UVI in 0.1 M NaCl solutions and examined the particles formed using filtration, dynamic light scattering, transition electron microscopy and X-ray powder diffraction. We found that at pH 10.5 and 11.5, between 75 and 96 % of UVI was removed from the solutions as clarkeite and studtite over a period of 48 h, forming particles with hydrodynamic diameters of 640 ± 111 nm and 837 ± 142 nm, respectively and representing aggregates of 10′s nm sized crystals randomly orientated. At pH 12.5, the formation of particles >0.2 μm became insignificant and no UVI was removed from solution. The mobility of UVI in these solutions was further studied using column experiments through quartz sand. We found that at pH 10.5 and 11.5, UVI containing particles were immobilised near the column inlet, likely due physical immobilisation of the particles (particle straining). At pH 12.5, however, UVI quantitatively eluted from the columns in the filter fraction <0.2 μm. The findings of our study reinforce a strong control of solution pH on particle size and U removal in alkaline solutions and subsequently on mobility of U through quartz porous media.
Garfi G, John CM, Lin Q, et al., 2020, Fluid Surface Coverage Showing the Controls of Rock Mineralogy on the Wetting State, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276
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- Citations: 25
Rücker M, Bartels W-B, Bultreys T, et al., 2020, Workflow for upscaling wettability from the nano- to core-scales, International Symposium of the Society of Core Analysts
Rucker M, Bartels W-B, Garfi G, et al., 2020, Relationship between wetting and capillary pressure in a crude oil/brine/rock system: From nano-scale to core-scale, Journal of Colloid and Interface Science, Vol: 562, Pages: 159-169, ISSN: 0021-9797
HypothesisThe wetting behaviour is a key property of a porous medium that controls hydraulic conductivity in multiphase flow. While many porous materials, such as hydrocarbon reservoir rocks, are initially wetted by the aqueous phase, surface active components within the non-wetting phase can alter the wetting state of the solid. Close to the saturation endpoints wetting phase fluid films of nanometre thickness impact the wetting alteration process. The properties of these films depend on the chemical characteristics of the system. Here we demonstrate that surface texture can be equally important and introduce a novel workflow to characterize the wetting state of a porous medium.ExperimentsWe investigated the formation of fluid films along a rock surface imaged with atomic force microscopy using ζ-potential measurements and a computational model for drainage. The results were compared to spontaneous imbibition test to link sub-pore-scale and core-scale wetting characteristics of the rock.FindingsThe results show a dependency between surface coverage by oil, which controls the wetting alteration, and the macroscopic wetting response. The surface-area coverage is dependent on the capillary pressure applied during primary drainage. Close to the saturation endpoint, where the change in saturation was minor, the oil-solid contact changed more than 80%.
Imanovs E, Krevor S, Zadeh AM, 2020, CO2-EOR and Storage Potentials in Depleted Reservoirs in the NorwegianContinental Shelf (NCS)
Two global challenges are an increase in carbon dioxide (CO2) concentration in the atmosphere, causingglobal warming and an increase in energy demand (UNFCCC, 2015; EIA, 2018). Carbon Capture andStorage (CCS) is believed to be a major technology to considerably reduce CO2 emissions (Budinis et al.,2018). Applying this technology, the anthropogenic CO2 could be injected into depleted reservoirs andpermanently stored in the subsurface. However, standalone CCS projects may not be economically feasibledue to CO2 separation, transportation and storage costs (Pires et al., 2011). On the other hand, one of themost efficient Enhanced Oil Recovery (EOR) methods is carbon dioxide injection (Holm, 1959). Therefore,a combination of CO2-EOR and storage schemes could offer an opportunity to produce additional oil fromdepleted reservoirs and permanently store CO2 in the subsurface in an economically efficient manner. In this study, a depleted sandstone reservoir located in the Norwegian Continental Shelf (NCS) is used. Aninnovative development scenario is considered, involving two phases: CO2 storage phase at the beginningof the project followed by a CO2-EOR phase. The objective of this paper is to evaluate the effect of differentinjection methods, including continuous gas injection (CGI), continuous water injection (CWI), WaterAlternating Gas (WAG), Tapered WAG (TWAG), Simultaneous Water Above Gas Co-injection (SWGCO),Simultaneous Water and Gas Injection (SWGI) and cyclic SWGI on oil recovery and CO2 storage potentialin the depleted reservoir. A conceptual 2D high-resolution heterogeneous model with one pair injector-producer is used toinvestigate the mechanisms taking place in the reservoir during different injection methods. This knowledgeis applied in a field scale, realistic 3D compositional reservoir model of a depleted sandstone reservoir inthe NCS including ten oil producers and twenty water/gas injectors. The simulation results demonstrate that innovative development scen
Krevor S, Blunt MJ, Trusler JPM, et al., 2020, Chapter 8: An introduction to subsurface CO<inf>2</inf> storage, RSC Energy and Environment Series, Pages: 238-295, ISBN: 9781788014700
The costs of carbon capture and storage are driven by the capture of CO2 from exhaust streams or the atmosphere. However, its role in climate change mitigation is underpinned by the potential of the vast capacity for storage in subsurface geologic formations. This storage potential is confined to sedimentary rocks, which have substantial porosity and high permeability in comparison to crystalline igneous and metamorphic rocks. These in turn occur in the sedimentary basins of the Earth's continents and near shore. However, the specific capacity for storage is not correlated simply to the existence of a basin. Consideration must also be made of reservoir permeability, caprock integrity, injectivity, fluid dynamics, and geomechanical properties of pressurisation and faulting. These are the topics addressed in this chapter. These processes and properties will combine in complex ways in a wide range of settings to govern the practicality of storing large volumes of CO2. There is clear potential for storage at the scale required to mitigate the worst impacts of global climate change, estimated to be in the order of 10 Gt CO2 per year by 2050. However, until at least dozens of commercial projects have been built in a range of geologic environments, the upper reaches of what can be achieved, and how quickly, will remain uncertain.
Imanovs E, Krevor S, Zadeh AM, 2020, CO<inf>2</inf>-EOR and storage potentials in depleted reservoirs in the norwegian continental shelf NCS
Two global challenges are an increase in carbon dioxide (CO2) concentration in the atmosphere, causing global warming and an increase in energy demand (UNFCCC, 2015; EIA, 2018). Carbon Capture and Storage (CCS) is believed to be a major technology to considerably reduce CO2 emissions (Budinis et al., 2018). Applying this technology, the anthropogenic CO2 could be injected into depleted reservoirs and permanently stored in the subsurface. However, standalone CCS projects may not be economically feasible due to CO2 separation, transportation and storage costs (Pires et al., 2011). On the other hand, one of the most efficient Enhanced Oil Recovery (EOR) methods is carbon dioxide injection (Holm, 1959). Therefore, a combination of CO2-EOR and storage schemes could offer an opportunity to produce additional oil from depleted reservoirs and permanently store CO2 in the subsurface in an economically efficient manner. In this study, a depleted sandstone reservoir located in the Norwegian Continental Shelf (NCS) is used. An innovative development scenario is considered, involving two phases: CO2 storage phase at the beginning of the project followed by a CO2-EOR phase. The objective of this paper is to evaluate the effect of different injection methods, including continuous gas injection (CGI), continuous water injection (CWI), Water Alternating Gas (WAG), Tapered WAG (TWAG), Simultaneous Water Above Gas Co-injection (SWGCO), Simultaneous Water and Gas Injection (SWGI) and cyclic SWGI on oil recovery and CO2 storage potential in the depleted reservoir. A conceptual 2D high-resolution heterogeneous model with one pair injector-producer is used to investigate the mechanisms taking place in the reservoir during different injection methods. This knowledge is applied in a field scale, realistic 3D compositional reservoir model of a depleted sandstone reservoir in the NCS including ten oil producers and twenty water/gas injectors. The simulation results demonstrate that innovative
Niu B, Krevor S, 2020, The Impact of Mineral Dissolution on Drainage Relative Permeability and Residual Trapping in Two Carbonate Rocks, TRANSPORT IN POROUS MEDIA, Vol: 131, Pages: 363-380, ISSN: 0169-3913
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- Citations: 5
Krevor S, Blunt MJ, Trusler AJPM, et al., 2020, An Introduction to Subsurface CO<sub>2</sub> Storage, CARBON CAPTURE AND STORAGE, Editors: Bui, Dowell, Publisher: ROYAL SOC CHEMISTRY, Pages: 238-295, ISBN: 978-1-78801-145-7
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- Citations: 3
Garfi G, Lin Q, Berg S, et al., 2019, Fluid surface coverage showing the controls of rock mineralogy on the wetting state
Garfi G, John CM, Berg S, et al., 2019, The sensitivity of estimates of multiphase fluid and solid properties of porous rocks to image processing, Transport in Porous Media, Vol: 131, Pages: 985-1005, ISSN: 0169-3913
X-ray microcomputed tomography (X-ray μ-CT) is a rapidly advancing technology that has been successfully employed to study flow phenomena in porous media. It offers an alternative approach to core scale experiments for the estimation of traditional petrophysical properties such as porosity and single-phase flow permeability. It can also be used to investigate properties that control multiphase flow such as rock wettability or mineral topology. In most applications, analyses are performed on segmented images obtained employing a specific processing pipeline on the greyscale images. The workflow leading to a segmented image is not straightforward or unique and, for most of the properties of interest, a ground truth is not available. For this reason, it is crucial to understand how image processing choices control properties estimation. In this work, we assess the sensitivity of porosity, permeability, specific surface area, in situ contact angle measurements, fluid–fluid interfacial curvature measurements and mineral composition to processing choices. We compare the results obtained upon the employment of two processing pipelines: non-local means filtering followed by watershed segmentation; segmentation by a manually trained random forest classifier. Single-phase flow permeability, in situ contact angle measurements and mineral-to-pore total surface area are the most sensitive properties, as a result of the sensitivity to processing of the phase boundary identification task. Porosity, interfacial fluid–fluid curvature and specific mineral descriptors are robust to processing. The sensitivity of the property estimates increases with the complexity of its definition and its relationship to boundary shape.
Zahasky C, Jackson S, Lin Q, et al., 2019, Pore network model predictions of Darcy-scale multiphase flow heterogeneity validated by experiments
Spurin C, Bultreys T, Bijeljic B, et al., 2019, Mechanisms controlling fluid breakup and reconnection during two-phase flow in porous media, Physical Review E, Vol: 100, ISSN: 2470-0045
The use of Darcy's law to describe steady-state multiphase flow in porous media has been justified by the assumption that the fluids flow in continuously connected pathways. However, a range of complex interface dynamics have been observed during macroscopically steady-state flow, including intermittent pathway flow where flow pathways periodically disconnect and reconnect. The physical mechanisms controlling this behavior have remained unclear, leading to uncertainty concerning the occurrence of the different flow regimes. We observe that the fraction of intermittent flow pathways is dependent on the capillary number and viscosity ratio. We propose a phase diagram within this parameter space to quantify the degree of intermittent flow.
Spurin C, Krevor S, Bultreys T, et al., 2019, Intermittent fluid connectivity during two-phase flow in a heterogeneous carbonate rock
Garfi G, John C, Berg S, et al., 2019, The sensitivity of estimates of multiphase fluid and solid properties of porous rocks to image processing
Spurin C, Bultreys T, Bijeljic B, et al., 2019, Intermittent fluid connectivity during two-phase flow in a heterogeneous carbonate rock, Physical Review E, Vol: 100, ISSN: 2470-0045
Subsurface fluid flow is ubiquitous in nature, and understanding the interaction of multiple fluids as they flow within a porous medium is central to many geological, environmental, and industrial processes. It is assumed that the flow pathways of each phase are invariant when modeling subsurface flow using Darcy's law extended to multiphase flow, a condition that is assumed to be valid during steady-state flow. However, it has been observed that intermittent flow pathways exist at steady state even at the low capillary numbers typically encountered in the subsurface. Little is known about the pore structure controls or the impact of intermittency on continuum scale flow properties. Here we investigate the impact of intermittent pathways on the connectivity of the fluids for a carbonate rock. Using laboratory-based micro computed tomography imaging we observe that intermittent pathway flow occurs in intermediate-sized pores due to the competition between both flowing fluids. This competition moves to smaller pores when the flow rate of the nonwetting phase increases. Intermittency occurs in poorly connected pores or in regions where the nonwetting phase itself is poorly connected. Intermittent pathways lead to the interrupted transport of the fluids; this means they are important in determining continuum scale flow properties, such as relative permeability. The impact of intermittency on flow properties is significant because it occurs at key locations, whereby the nonwetting phase is otherwise disconnected.
Spurin C, Krevor S, Bultreys T, et al., 2019, Mechanisms controlling fluid break-up and reconnection during two-phase flow in porous media
Jackson S, Lin Q, Krevor S, 2019, Representative elementary volumes, hysteresis and heterogeneity in multiphase flow from the pore to continuum scale
De Simone S, Jackson SJ, Krevor S, 2019, The error in using superposition to estimate pressure during multi‐site subsurface CO 2 storage, Geophysical Research Letters, Vol: 46, Pages: 6525-6533, ISSN: 0094-8276
Analytic pressure estimates for multisite CO2 injection are typically performed through the superposition of single‐site injection models. This is theoretically invalid for multiphase flow because of its nonlinearity. We quantify the error associated with the application of superposition in scenarios with sites located in a rectangular grid geometry. We show that the use of superposition results in overestimates of the pressure buildup, because it neglects the presence of multiple CO2 plumes, which increase the reservoir fluid mobility. The adoption of a dimensionless time scaled to the geometric average between the advective and diffusive characteristic times allows us to define a general model for the maximum error, which may be used to evaluate the validity of using superposition, or to correct the pressure estimates when errors are significant. This procedure can be applied to any analytical solution and advances the extension of single‐well models to scenarios of multiple injection sites.
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.
Veillard C, John C, Krevor S, et al., 2019, Rock-buffered recrystallization of Marion Plateau dolomites at low temperature evidenced by clumped isotope thermometry and X-Ray diffraction analysis, Geochimica et Cosmochimica Acta, Vol: 252, Pages: 190-212, ISSN: 0016-7037
Much debate exists on the extent to which early dolomites recrystallize and preserve the signature of their primary diagenetic setting. Here, we combine clumped isotopes thermometry with X-ray diffraction and thin section petrography to study dolomite recrystallization under shallow burial (<1 km) conditions. We analysed 26 dolomite samples from two Miocene carbonate platforms on the Marion Plateau, NE Australia. Marion Plateau dolomites provide an ideal case study to examine the effects of recrystallization because of the relative simplicity of the geological setting, with simple subsidence, and several episodes of early dolomitization by normal Miocene sea water. Results show that Marion Plateau dolomites are very rich in calcium and their formation temperature inferred from clumped isotopes T(Δ47dol) ranges between 12 and 35°C. The apparent fluid composition (δ18Ow (app)) falls in the range of sea water composition, but a correlation between T(Δ47dol), δ18Odol, and δ18Ow (app) exists: the higher the crystallization temperature, the more negative the fluid composition is. T(Δ47dol) and δ18Ow (app) increase with depth, whereas δ18Odol and δ13Cdol tend to both decrease with depth. We interpret the negative correlation between T(Δ47dol) and δ18Ow (app) as evidence of shallow burial recrystallization via dissolution/re-precipitation. Modelling of the T(Δ47dol), δ18Odol, and δ18Ow (app) indicates that the recrystallization happened at very low water to rock ratio. Carbon isotopes are inherited from the dolomitization process, and not reset during recrystallization. This study shows that dolomite recrystallization has the potential to affect T(Δ47dol) at depths shallower than previously demonstrated. It emphasizes the fact that high calcium dolomites (and possibly aragonite and high Mg-calcite) can have a range of T(Δ47dol) before entering the solid-state reordering re
Lin Q, Bijeljic B, Krevor SC, et al., 2019, A New Waterflood Initialization Protocol With Wettability Alteration for Pore-Scale Multiphase Flow Experiments, Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description, Vol: 60, Pages: 264-272, ISSN: 1529-9074
Jackson SJ, Krevor S, 2019, Characterization of hysteretic multiphase flow from the mm to m scale in heterogeneous rocks, The 32nd International Symposium of the Society of Core Analysts, Publisher: EDP Sciences, ISSN: 2267-1242
Incorporating mm-m scale capillary pressure heterogeneity into upscaled numerical models is key to the successful prediction of low flow potential plume migration and trapping at the field scale. Under such conditions, the upscaled, equivalent relative permeability incorporating capillary pressure heterogeneity is far from that derived conventionally at the viscous limit, dependent on the heterogeneity structure and flow rate, i.e. dependent on the capillary number. Recent work at the SCA 2017 symposium (SCA2017-022) demonstrated how equivalent functions can be obtained on heterogeneous rock cores from the subsurface under drainage conditions; going beyond traditional SCAL. Experimental observations using medical CT scanning can be combined with numerical modelling so that heterogeneous subsurface rock cores can be directly characterized and used to populate field scale reservoir models. In this work, we extend this characterization approach by incorporating imbibition cycles into the methodology. We use a Bunter sandstone core with several experimental CO 2 -Brine core flood datasets at different flow rates (2x drainage, 1x imbibition and 2x trapping) to demonstrate the characterization of hysteretic multiphase flow functions in water-wet rocks. We show that mm-m scale experimental saturations and equivalent, low flow potential relative permeabilities can be predicted during drainage and imbibition, along with trapping characteristics. Equivalent imbibition relative permeabilities appear as a function of capillary number, as in the drainage cases. We also find that the form of capillary pressure function during imbibition has a large impact on the trapping characteristics, with local heterogeneity trapping reduced (or removed), if the capillary pressure drops to zero, or below at the residual saturation.
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, Publisher: EarthArXiv
We observed features of pore scale fluid distributions during oil-brine displacement in a mixed-wet sandstone rock sample. High-resolution X-ray imaging was used in combination with differential pressure measurements to measure relative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on a sample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil to alter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flow rate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, X-ray tomographic images were taken. The images were used to compute saturation, interfacial area, curvature and contact angle. From this information relative permeability and capillary pressure were determined as functions of saturation. We compare our results with a previously published experiment with strongly water-wet conditions. The oil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, of approximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock. The capillary pressure was slightly negative and ten times smaller in magnitude than a similar water-wet rock, and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area was also largely constant in this saturation range. The measured static contact angles had an average of $80^{\circ}$ with a standard deviation of $17^{\circ}$.We observed that the oil-brine interfaces were not flat, as may be expected for a very low mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. These interfaces were approximately minimal surfaces which allow efficient displacement and imply well-connected phases. Saddle-shaped menisci swept through the pore space at a constant capillary
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
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