35 results on '"Bijeljic, B."'
Search Results
2. Minimal surfaces in porous media: pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone
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Lin, Q, Bijeljic, B, Berg, S, Pini, R, Blunt, MJ, and Krevor, S
- Abstract
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 pressure and with an almost fixed area, removing most of the oil.
- Published
- 2019
3. Pore-scale dissolution by CO₂ saturated brine in a multimineral carbonate at reservoir conditions: impact of physical and chemical heterogeneity
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Al-Khulaifi, Y, Lin, Q, Blunt, MJ, and Bijeljic, B
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0907 Environmental Engineering ,Environmental Engineering ,1402 Applied Economics ,0905 Civil Engineering - Abstract
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.
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- 2019
4. Visualization and quantification of capillary drainage in the pore space of laminated sandstone by a porous plate method using differential imaging X-ray microtomography
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Lin, Q, Bijeljic, B, Rieke, H, Blunt, MJ, and DEA Norge AS
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Science & Technology ,Environmental Engineering ,IMAGES ,POROSITY ,Environmental Sciences & Ecology ,PRESSURE ,CURVATURE ,RESERVOIR CONDITIONS ,TRANSPORT ,0905 Civil Engineering ,0907 Environmental Engineering ,ROCKS ,TOMOGRAPHY ,Physical Sciences ,Limnology ,Water Resources ,Marine & Freshwater Biology ,HETEROGENEITY ,CO2 ,Life Sciences & Biomedicine ,1402 Applied Economics ,Environmental Sciences - Abstract
The experimental determination of capillary pressure drainage curves at the pore scale is of vital importance for the mapping of reservoir fluid distribution. To fully characterize capillary drainage in a complex pore space, we design a differential imaging-based porous plate (DIPP) method using X-ray micro- tomography. For an exemplar mm-scale laminated sandstone microcore with a porous plate, we quantify the displacement from resolvable macropores and subresolution micropores. Nitrogen (N 2 ) was injected as the nonwetting phase at a constant pressure while the porous plate prevented its escape. The measured porosity and capillary pressure at the imaged saturations agree well with helium measurements and experi- ments on larger core samples, while providing a pore-scale explanation of the fluid distribution. We observed that the majority of the brine was displaced by N 2 in macropores at low capillary pressures, fol- lowed by a further brine displacement in micropores when capillary pressure increases. Furthermore, we were able to discern that brine predominantly remained within the subresolution micropores, such as regions of fine lamination. The capillary pressure curve for pressures ranging from 0 to 1151 kPa is provided from the image analysis compares well with the conventional porous plate method for a cm-scale core but was conducted over a period of 10 days rather than up to few months with the conventional porous plate method. Overall, we demonstrate the capability of our method to provide quantitative information on two- phase saturation in heterogeneous core samples for a wide range of capillary pressures even at scales smaller than the micro-CT resolution
- Published
- 2017
5. Insights into non-Fickian solute transport in carbonates
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Bijeljic, B, Mostaghimi, P, Blunt, MJ, PETROLEO BRASILEIRO S. A. PETROBRAS, and Chevron Energy Technology Company
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TIME BEHAVIOR ,Science & Technology ,MOLECULAR-DIFFUSION ,Environmental Engineering ,Environmental Sciences & Ecology ,THROUGH POROUS-MEDIA ,HYDRODYNAMIC DISPERSION ,0905 Civil Engineering ,TRACER TESTS ,0907 Environmental Engineering ,FLUID TRANSPORT ,NMR MEASUREMENTS ,Physical Sciences ,Limnology ,Water Resources ,FLOW PROPAGATORS ,Marine & Freshwater Biology ,NUCLEAR-MAGNETIC-RESONANCE ,TAYLOR DISPERSION ,0406 Physical Geography and Environmental Geoscience ,Life Sciences & Biomedicine ,Environmental Sciences ,Regular Articles - Abstract
[1] We study and explain the origin of early breakthrough and long tailing plume behavior by simulating solute transport through 3-D X-ray images of six different carbonate rock samples, representing geological media with a high degree of pore-scale complexity. A Stokes solver is employed to compute the flow field, and the particles are then transported along streamlines to represent advection, while the random walk method is used to model diffusion. We compute the propagators (concentration versus displacement) for a range of Peclet numbers (Pe) and relate it to the velocity distribution obtained directly on the images. There is a very wide distribution of velocity that quantifies the impact of pore structure on transport. In samples with a relatively narrow spread of velocities, transport is characterized by a small immobile concentration peak, representing essentially stagnant portions of the pore space, and a dominant secondary peak of mobile solute moving at approximately the average flow speed. On the other hand, in carbonates with a wider velocity distribution, there is a significant immobile peak concentration and an elongated tail of moving fluid. An increase in Pe, decreasing the relative impact of diffusion, leads to the faster formation of secondary mobile peak(s). This behavior indicates highly anomalous transport. The implications for modeling field-scale transport are discussed. Citation: Bijeljic, B., P. Mostaghimi, and M. J. Blunt (2013), Insights into non-Fickian solute transport in carbonates, Water Resour. Res., 49, 2714–2728, doi:10.1002/wrcr.20238.
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- 2013
6. Pore-space structure and average dissolution rates: A simulation study
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Pereira Nunes, JP, Bijeljic, B, and Blunt, MJ
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Physics::Fluid Dynamics ,0907 Environmental Engineering ,Environmental Engineering ,1402 Applied Economics ,0905 Civil Engineering ,Physics::Geophysics - Abstract
We study the influence of the pore-space geometry on sample-averaged dissolution rates in millimeter-scale carbonate samples undergoing reaction-controlled mineral dissolution upon the injection of a CO2 -saturated brine. The representation of the pore space is obtained directly from micro-CT images with a resolution of a few microns. Simulations are performed with a particle tracking approach on images of three porous rocks of increasing pore-space complexity: a bead pack, a Ketton oolite, and an Estaillades limestone. Reactive transport is simulated with a hybrid approach that combines a Lagrangian method for transport and reaction with the Eulerian flow field obtained by solving the incompressible Navier-Stokes equations directly on the voxels of three-dimensional images. Particle advection is performed with a semianalytical streamline method and diffusion is simulated via a random walk. Mineral dissolution is defined in terms of the particle flux through the pore-solid interface, which can be related analytically to the batch (intrinsic) reaction rate. The impact of the flow heterogeneity on reactive transport is illustrated in a series of simulations performed at different flow rates. The average dissolution rates depend on both the heterogeneity of the sample and on the flow rate. The most heterogeneous rock may exhibit a decrease of up to two orders of magnitude in the sample-averaged reaction rates in comparison with the batch rate. Furthermore, we provide new insights for the dissolution regime that would be traditionally characterized as uniform. In most cases, at the pore-scale, dissolution preferentially enlarges fast-flow channels which greatly restricts the effective surface available for reaction.
- Published
- 2016
7. Dynamic imaging of oil shale pyrolysis using synchrotron X-ray microtomography
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Saif, T, Lin, Q, Singh, K, Bijeljic, B, and Blunt, MJ
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Multidisciplinary ,Meteorology & Atmospheric Sciences - Abstract
© 2016. The Authors.The structure and connectivity of the pore space during the pyrolysis of oil shales determines hydrocarbon flow behavior and ultimate recovery. We image the time evolution of the pore and microfracture networks during oil shale pyrolysis using synchrotron X-ray microtomography. Immature Green River (Mahogany Zone) shale samples were thermally matured under vacuum conditions at temperatures up to 500°C while being periodically imaged with a 2μmvoxel size. The structural transformation of both organic-rich and organic-lean layers within the shale was quantified. The images reveal a dramatic change in porosity accompanying pyrolysis between 390 and 400°C with the formation of micron-scale heterogeneous pores. With a further increase in temperature, the pores steadily expand resulting in connected microfracture networks that predominantly develop along the kerogen-rich laminations.
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- 2016
8. Pore-scale simulation of carbonate dissolution in micro-CT images
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Pereira Nunes, JP, Blunt, MJ, Bijeljic B, and Engineering & Physical Science Research Council (EPSRC)
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- 2015
9. The impact of residual water on CH4-CO2 dispersion in consolidated rock cores
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Honari, A., Zecca, M., Vogt, S., Iglauer, Stefan, Bijeljic, B., Johns, M., May, E., Honari, A., Zecca, M., Vogt, S., Iglauer, Stefan, Bijeljic, B., Johns, M., and May, E.
- Abstract
Assessment of the viability of enhanced gas recovery (EGR), in which CO2 is injected into natural gas reservoirs, requires accurate and appropriate reservoir simulations. These necessitate provision of parameters describing dispersion between the fluids. Here we systematically measure fluid dispersion in various rock cores (sandstones and carbonates), both dry and at irreducible water saturation, at reservoir conditions. In this manner we evaluate the impact of the irreducible water on the miscible displacement processes. As such this represents the first measurement of dispersion as a function of water saturation for supercritical gases in consolidated media. Complementary measurements of water spatial distribution along the rock axis, as well as the pore size distribution occupied by the water were performed using magnetic resonance techniques. Irreducible water was found to increase dispersivity by a factor of up to 7.3. The dispersion coefficient (K) was measured as a function of velocity and the data for both dry and water-containing samples were successfully combined on a K-Péclet number (Pe) plot, enabling ready future inclusion into EGR reservoir models. The power-law dependence of K upon Pe produced an exponent of 1.2 for dry and water-saturated sandstones and 1.4 for dry and water-saturated carbonates, consistent with literature results (Bijeljic et al., 2011; Honari et al., 2015).
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- 2016
10. Continuum‐scale characterization of solute transport based on pore‐scale velocity distributions
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Porta, G. M., primary, Bijeljic, B., additional, Blunt, M. J., additional, and Guadagnini, A., additional
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- 2015
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11. An Experimental Study of Three-Phase Trapping in Sand Packs
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Amaechi, B., Iglauer, Stefan, Pentland, C., Bijeljic, B., Blunt, M., Amaechi, B., Iglauer, Stefan, Pentland, C., Bijeljic, B., and Blunt, M.
- Abstract
The trapped saturations of oil and gas are measured as functions of initial oil and gas saturation in water-wet sand packs. Analogue fluids—water, octane and air—are used at ambient conditions. Starting with a sand-pack column which has been saturated with brine, oil (octane) is injected with the column horizontal until irreducible water saturation is reached. The column is then positioned vertically and air is allowed to enter from the top of the column, while oil is allowed to drain under gravity for varying lengths of time. At this point, the column may be sliced and the fluids analyzed by gas chromatography to obtain the initial saturations. Alternatively, brine is injected through the bottom of the vertical column to trap oil and gas, before slicing the columns and measuring the trapped or residual saturations by gas chromatography and mass balance. The experiments show that in three-phase flow, the total trapped saturations of oil and gas are considerably higher than the trapped saturations reported in the literature for two-phase systems. It is found that the residual saturation of oil and gas combined could be as high as 23 %, as opposed to a maximum two-phase residual of only 14 %. For very high initial gas saturations, the residual gas saturation, up to 17 %, was also higher than for two-phase displacement. These observations are explained in terms of the competition between piston-like displacement and snap-off. It is also observed that less oil is always trapped in three-phase flow than in two-phase displacement, and the difference depends on the amount of gas present. For low and intermediate initial gas saturations, the trapped gas saturation rises linearly with initial saturation, followed by a constant residual, as seen in two-phase displacements. However, at very high initial gas saturations, the residual saturation rises again.
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- 2014
12. Pore-scale imaging and modelling
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Blunt, M., Bijeljic, B., Dong, H., Gharbi, O., Iglauer, Stefan, Mostaghimi, P., Paluszny, A., Pentland, C., Blunt, M., Bijeljic, B., Dong, H., Gharbi, O., Iglauer, Stefan, Mostaghimi, P., Paluszny, A., and Pentland, C.
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Pore-scale imaging and modelling – digital core analysis – is becoming a routine service in the oil and gas industry, and has potential applications in contaminant transport and carbon dioxide storage. This paper briefly describes the underlying technology, namely imaging of the pore space of rocks from the nanometre scale upwards, coupled with a suite of different numerical techniques for simulating single and multiphase flow and transport through these images. Three example applications are then described, illustrating the range of scientific problems that can be tackled: dispersion in different rock samples that predicts the anomalous transport behaviour characteristic of highly heterogeneous carbonates; imaging of super-critical carbon dioxide in sandstone to demonstrate the possibility of capillary trapping in geological carbon storage; and the computation of relative permeability for mixed-wet carbonates and implications for oilfield waterflood recovery. The paper concludes by discussing limitations and challenges, including finding representative samples, imaging and simulating flow and transport in pore spaces over many orders of magnitude in size, the determination of wettability, and upscaling to the field scale. We conclude that pore-scale modelling is likely to become more widely applied in the oil industry including assessment of unconventional oil and gas resources. It has the potential to transform our understanding of multiphase flow processes, facilitating more efficient oil and gas recovery, effective contaminant removal and safe carbon dioxide storage.
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- 2013
13. Nonwetting phase residual saturation in sand packs
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Gittins, P., Iglauer, Stefan, Pentland, C., Al-Mansoori, S., Al-Sayari, S., Bijeljic, B., Blunt, M., Gittins, P., Iglauer, Stefan, Pentland, C., Al-Mansoori, S., Al-Sayari, S., Bijeljic, B., and Blunt, M.
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We measure residual nonwetting phase saturation in six unconsolidated sands of different average grain sizes. Wealso analyze the pore structure using three-dimensional images from which topologically equivalent pore networks are extracted. The residual saturations range from 10.8% to 13.1%, which is lower than for most consolidated media. Higher porosity is associated with lower residual saturations, while there is little correlation between grain and pore shape and the degree of trapping. We also study layered packs: the residual saturations are reduced compared to comparable homogeneous systems. We discuss the results in the context of capillary trapping during carbon storage in aquifers.
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- 2010
14. Measurement of Non-Wetting Phase Trapping in Sandpacks
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Pentland, C., Itsekiri, E., Al-Mansoori, S., Iglauer, Stefan, Bijeljic, B., Blunt, M., Pentland, C., Itsekiri, E., Al-Mansoori, S., Iglauer, Stefan, Bijeljic, B., and Blunt, M.
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- 2010
15. Measurements of non-wetting phase trapping applied to carbon dioxide storage
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Al-Mansoori, S., Iglauer, Stefan, Itsekiri, E., Pentland, C., Bijeljic, B., Blunt, M., Al-Mansoori, S., Iglauer, Stefan, Itsekiri, E., Pentland, C., Bijeljic, B., and Blunt, M.
- Abstract
We measure the trapped non-wetting phase saturation as a function of the initial saturation in sand packs. The application of the work is for CO2 storage in aquifers where capillary trapping is a rapid and effective mechanism to render injected CO2 immobile. The CO2 is injected into the formation followed by chase brine injection, or natural groundwater flow, which displaces and traps CO2 on the pore scale as a residual immobile phase. Current models to predict the amount of trapping are based on experiments in consolidated media, while CO2 may be stored in relatively shallow, poorly consolidated systems. We use analogue fluids at ambient conditions. The trapped saturation initially rises linearly with initial saturation to a value of approximately 0.13 for oil/water systems and 0.14 for gas/water systems. There then follows a region where the residual saturation is constant with further increases in initial saturation. This behaviour is not predicted by the traditional literature trapping models, but is physically consistent with unconsolidated media where most of the larger pores can easily be invaded at relatively low saturation and there is, overall, relatively little trapping. A good match to our experimental data was achieved with the trapping model proposed by Aissaoui.
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- 2010
16. Measurements of Non-Wetting Phase Trapping Applied to Carbon Dioxide Storage
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ICGGCT, Al-Mansoori, S., Iglauer, Stefan, Pentland, C., Bijeljic, B., Blunt, M., ICGGCT, Al-Mansoori, S., Iglauer, Stefan, Pentland, C., Bijeljic, B., and Blunt, M.
- Abstract
We measure the trapped non-wetting phase saturation as a function of the initial saturation in sand packs. The application of the work is for carbon dioxide (CO2) storage in aquifers where capillary trapping is a rapid and effective mechanism to render injected CO2 immobile. We used analogue fluids at ambient conditions. The trapped saturation initially rises linearly with initial saturation to a value of 0.11 for oil/water systems and 0.14 for gas/water systems. There then follows a region where the residual saturation is constant with further increases in initial saturation.
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- 2009
17. Pore-scale processes in tertiary low salinity waterflooding in a carbonate rock: Micro-dispersions, water film growth, and wettability change.
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Selem AM, Agenet N, Blunt MJ, and Bijeljic B
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Hypothesis: The wettability change from oil-wet towards more water-wet conditions by injecting diluted brine can improve oil recovery from reservoir rocks, known as low salinity waterflooding. We investigated the underlying pore-scale mechanisms of this process to determine if improved recovery was associated with a change in local contact angle, and if additional displacement was facilitated by the formation of micro-dispersions of water in oil and water film swelling., Experiments: X-ray imaging and high-pressure and temperature flow apparatus were used to investigate and compare high and low salinity waterflooding in a carbonate rock sample. The sample was placed in contact with crude oil to obtain an initial wetting state found in hydrocarbon reservoirs. High salinity brine was then injected at increasing flow rates followed by low salinity brine injection using the same procedure., Findings: Development of water micro-droplets within the oil phase and detachment of oil layers from the rock surface were observed after low salinity waterflooding. During high salinity waterflooding, contact angles showed insignificant changes from the initial value of 115°, while the mean curvature and local capillary pressure values remained negative, consistent with oil-wet conditions. However, with low salinity, the decrease in contact angle to 102° and the shift in the mean curvature and capillary pressure to positive values indicate a wettability change. Overall, our analysis captured the in situ mechanisms and processes associated with the low salinity effect and ultimate increase in oil recovery., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2022. Published by Elsevier Inc.)
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- 2022
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18. Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions.
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Selem AM, Agenet N, Gao Y, Raeini AQ, Blunt MJ, and Bijeljic B
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X-ray micro-tomography combined with a high-pressure high-temperature flow apparatus and advanced image analysis techniques were used to image and study fluid distribution, wetting states and oil recovery during low salinity waterflooding (LSW) in a complex carbonate rock at subsurface conditions. The sample, aged with crude oil, was flooded with low salinity brine with a series of increasing flow rates, eventually recovering 85% of the oil initially in place in the resolved porosity. The pore and throat occupancy analysis revealed a change in fluid distribution in the pore space for different injection rates. Low salinity brine initially invaded large pores, consistent with displacement in an oil-wet rock. However, as more brine was injected, a redistribution of fluids was observed; smaller pores and throats were invaded by brine and the displaced oil moved into larger pore elements. Furthermore, in situ contact angles and curvatures of oil-brine interfaces were measured to characterize wettability changes within the pore space and calculate capillary pressure. Contact angles, mean curvatures and capillary pressures all showed a shift from weakly oil-wet towards a mixed-wet state as more pore volumes of low salinity brine were injected into the sample. Overall, this study establishes a methodology to characterize and quantify wettability changes at the pore scale which appears to be the dominant mechanism for oil recovery by LSW., (© 2021. The Author(s).)
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- 2021
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19. Determination of contact angles for three-phase flow in porous media using an energy balance.
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Blunt MJ, Alhosani A, Lin Q, Scanziani A, and Bijeljic B
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Hypothesis: We define contact angles, θ, during displacement of three fluid phases in a porous medium using energy balance, extending previous work on two-phase flow. We test if this theory can be applied to quantify the three contact angles and wettability order in pore-scale images of three-phase displacement., Theory: For three phases labelled 1, 2 and 3, and solid, s, using conservation of energy ignoring viscous dissipation (Δa
1s cosθ12 -Δa12 -ϕκ12 ΔS1 )σ12 =(Δa3s cosθ23 +Δa23 -ϕκ23 ΔS3 )σ23 +Δa13 σ13 , where ϕ is the porosity, σ is the interfacial tension, a is the specific interfacial area, S is the saturation, and κ is the fluid-fluid interfacial curvature. Δ represents the change during a displacement. The third contact angle, θ13 can be found using the Bartell-Osterhof relationship. The energy balance is also extended to an arbitrary number of phases., Findings: X-ray imaging of porous media and the fluids within them, at pore-scale resolution, allows the difference terms in the energy balance equation to be measured. This enables wettability, the contact angles, to be determined for complex displacements, to characterize the behaviour, and for input into pore-scale models. Two synchrotron imaging datasets are used to illustrate the approach, comparing the flow of oil, water and gas in a water-wet and an altered-wettability limestone rock sample. We show that in the water-wet case, as expected, water (phase 1) is the most wetting phase, oil (phase 2) is intermediate wet, while gas (phase 3) is most non-wetting with effective contact angles of θ12 ≈48° and θ13 ≈44°, while θ23 =0 since oil is always present in spreading layers. In contrast, for the altered-wettability case, oil is most wetting, gas is intermediate-wet, while water is most non-wetting with contact angles of θ12 =134°±~10°,θ13 =119°±~10°, and θ23 =66°±~10°., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2020 The Author(s). Published by Elsevier Inc. All rights reserved.)- Published
- 2021
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20. Evaluation of methods using topology and integral geometry to assess wettability.
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Blunt MJ, Akai T, and Bijeljic B
- Abstract
Hypothesis: The development of high-resolution in situ imaging has allowed contact angles to be measured directly inside porous materials. We evaluate the use of concepts in integral geometry to determine contact angle. Specifically, we test the hypothesis that it is possible to determine an average contact angle from measurements of the Gaussian curvature of the fluid/fluid meniscus using the Gauss-Bonnet theorem., Theory and Simulation: We show that it is not possible to unambiguously determine an average contact angle from the Gauss-Bonnet theorem. We instead present an approximate relationship: 2πn(1-cosθ)=4π-∫κ
G12 dS12 , where n is the number of closed loops of the three-phase contact line where phases 1 and 2 contact the surface, θ is the average contact angle, while κG12 is the Gaussian curvature of the fluid meniscus which is integrated over its surface S12 . We then use the results of pore-scale lattice Boltzmann simulations to assess the accuracy of this approach to determine a representative contact angle for two-phase flow in porous media., Findings: We show that in simple cases with a flat solid surface, the approximate expression works well. When applied to simulations on pore space images, the equation provides a robust estimate of contact angle, accurate to within 3°, when averaged over many fluid clusters, although individual values can have significant errors because of the approximations used in the calculation., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2020 The Author(s). Published by Elsevier Inc. All rights reserved.)- Published
- 2020
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21. Using energy balance to determine pore-scale wettability.
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Akai T, Lin Q, Bijeljic B, and Blunt MJ
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Hypothesis: Based on energy balance during two-phase displacement in porous media, it has recently been shown that a thermodynamically consistent contact angle can be determined from micro-tomography images. However, the impact of viscous dissipation on the energy balance has not been fully understood. Furthermore, it is of great importance to determine the spatial distribution of wettability. We use direct numerical simulation to validate the determination of the thermodynamic contact angle both in an entire domain and on a pore-by-pore basis., Simulations: Two-phase direct numerical simulations are performed on complex 3D porous media with three wettability states: uniformly water-wet, uniformly oil-wet, and non-uniform mixed-wet. Using the simulated fluid configurations, the thermodynamic contact angle is computed, then compared with the input contact angles., Findings: The impact of viscous dissipation on the energy balance is quantified; it is insignificant for water flooding in water-wet and mixed-wet media, resulting in an accurate estimation of a representative contact angle for the entire domain even if viscous effects are ignored. An increasing trend in the computed thermodynamic contact angle during water injection is shown to be a manifestation of the displacement sequence. Furthermore, the spatial distribution of wettability can be represented by the thermodynamic contact angle computed on a pore-by-pore basis., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2020 The Author(s). Published by Elsevier Inc. All rights reserved.)
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- 2020
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22. Pore-scale mechanisms of CO 2 storage in oilfields.
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Alhosani A, Scanziani A, Lin Q, Raeini AQ, Bijeljic B, and Blunt MJ
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Rapid implementation of global scale carbon capture and storage is required to limit temperature rises to 1.5 °C this century. Depleted oilfields provide an immediate option for storage, since injection infrastructure is in place and there is an economic benefit from enhanced oil recovery. To design secure storage, we need to understand how the fluids are configured in the microscopic pore spaces of the reservoir rock. We use high-resolution X-ray imaging to study the flow of oil, water and CO
2 in an oil-wet rock at subsurface conditions of high temperature and pressure. We show that contrary to conventional understanding, CO2 does not reside in the largest pores, which would facilitate its escape, but instead occupies smaller pores or is present in layers in the corners of the pore space. The CO2 flow is restricted by a factor of ten, compared to if it occupied the larger pores. This shows that CO2 injection in oilfields provides secure storage with limited recycling of gas; the injection of large amounts of water to capillary trap the CO2 is unnecessary.- Published
- 2020
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23. Pore-scale numerical simulation of low salinity water flooding using the lattice Boltzmann method.
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Akai T, Blunt MJ, and Bijeljic B
- Abstract
Hypothesis: The change of wettability toward more water-wet by the injection of low salinity water can improve oil recovery from porous rocks, which is known as low salinity water flooding. To simulate this process at the pore-scale, we propose that the alteration in surface wettability mediated by thin water films which are below the resolution of simulation grid blocks has to be considered, as observed in experiments. This is modeled by a wettability alteration model based on rate-limited adsorption of ions onto the rock surface., Simulations: The wettability alteration model is developed and incorporated into a lattice Boltzmann simulator which solves both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport. The model is validated against two experiments in the literature, then applied to 3D micro-CT images of a rock., Findings: Our model correctly simulated the experimental observations caused by the slow wettability alteration driven by the development of water films. In the simulations on the 3D rock pore structure, a distinct difference in the mixing of high and low salinity water is observed between secondary and tertiary low salinity flooding, resulting in different oil recoveries., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2020 The Authors. Published by Elsevier Inc. All rights reserved.)
- Published
- 2020
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24. A thermodynamically consistent characterization of wettability in porous media using high-resolution imaging.
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Blunt MJ, Lin Q, Akai T, and Bijeljic B
- Abstract
Conservation of energy is used to derive a thermodynamically-consistent contact angle, θ
t , 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 Δa1s cosθt =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., (Copyright © 2019 The Authors. Published by Elsevier Inc. All rights reserved.)- Published
- 2019
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25. Quantification of Uncertainty and Best Practice in Computing Interfacial Curvature from Complex Pore Space Images.
- Author
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Akai T, Lin Q, Alhosani A, Bijeljic B, and Blunt MJ
- Abstract
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.
- Published
- 2019
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26. Time-resolved synchrotron X-ray micro-tomography datasets of drainage and imbibition in carbonate rocks.
- Author
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Singh K, Menke H, Andrew M, Rau C, Bijeljic B, and Blunt MJ
- Abstract
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.
- Published
- 2018
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27. Wettability in complex porous materials, the mixed-wet state, and its relationship to surface roughness.
- Author
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AlRatrout A, Blunt MJ, and Bijeljic B
- Abstract
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., Competing Interests: The authors declare no conflict of interest., (Copyright © 2018 the Author(s). Published by PNAS.)
- Published
- 2018
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28. A study to investigate viscous coupling effects on the hydraulic conductance of fluid layers in two-phase flow at the pore level.
- Author
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Shams M, Raeini AQ, Blunt MJ, and Bijeljic B
- Abstract
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., (Copyright © 2018 The Authors. Published by Elsevier Inc. All rights reserved.)
- Published
- 2018
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29. Editorial.
- Author
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Bijeljic B, Icardi M, and Prodanović M
- Published
- 2018
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30. Modelling and upscaling of transport in carbonates during dissolution: Validation and calibration with NMR experiments.
- Author
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Muljadi BP, Bijeljic B, Blunt MJ, Colbourne A, Sederman AJ, Mantle MD, and Gladden LF
- Subjects
- Calcium Carbonate, Calibration, Magnetic Resonance Imaging, Models, Theoretical, Porosity, Carbonates chemistry, Magnetic Resonance Spectroscopy methods
- Abstract
We present an experimental and numerical study of transport in carbonates during dissolution and its upscaling from the pore (∼μm) to core (∼cm) scale. For the experimental part, we use nuclear magnetic resonance (NMR) to probe molecular displacements (propagators) of an aqueous hydrochloric acid (HCl) solution through a Ketton limestone core. A series of propagator profiles are obtained at a large number of spatial points along the core at multiple time-steps during dissolution. For the numerical part, first, the transport model-a particle-tracking method based on Continuous Time Random Walks (CTRW) by Rhodes et al. (2008)-is validated at the pore scale by matching to the NMR-measured propagators in a beadpack, Bentheimer sandstone, and Portland carbonate (Scheven et al., 2005). It was found that the emerging distribution of particle transit times in these samples can be approximated satisfactorily using the power law function ψ(t) ∼ t
-1-β , where 0 <β < 2. Next, the evolution of the propagators during reaction is modelled: at the pore scale, the experimental data is used to calibrate the CTRW parameters; then the shape of the propagators is predicted at later observation times. Finally, a numerical upscaling technique is employed to obtain CTRW parameters for the core. From the NMR-measured propagators, an increasing frequency of displacements in stagnant regions was apparent as the reaction progressed. The present model predicts that non-Fickian behaviour exhibited at the pore scale persists on the centimetre scale., (Copyright © 2017 The Authors. Published by Elsevier B.V. All rights reserved.)- Published
- 2018
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31. In situ characterization of mixed-wettability in a reservoir rock at subsurface conditions.
- Author
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Alhammadi AM, AlRatrout A, Singh K, Bijeljic B, and Blunt MJ
- Abstract
We used X-ray micro-tomography to image the in situ wettability, the distribution of contact angles, at the pore scale in calcite cores from a producing hydrocarbon reservoir at subsurface conditions. The contact angle was measured at hundreds of thousands of points for three samples after twenty pore volumes of brine flooding.We found a wide range of contact angles with values both above and below 90°. The hypothesized cause of wettability alteration by an adsorbed organic layer on surfaces contacted by crude oil after primary drainage was observed with Scanning Electron Microscopy (SEM) and identified using Energy Dispersive X-ray (EDX) analysis. However, not all oil-filled pores were altered towards oil-wet conditions, which suggests that water in surface roughness, or in adjacent micro-porosity, can protect the surface from a strong wettability alteration. The lowest oil recovery was observed for the most oil-wet sample, where the oil remained connected in thin sheet-like layers in the narrower regions of the pore space. The highest recovery was seen for the sample with an average contact angle close to 90°, with an intermediate recovery in a more water-wet system, where the oil was trapped in ganglia in the larger regions of the pore space.
- Published
- 2017
- Full Text
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32. Dynamics of snap-off and pore-filling events during two-phase fluid flow in permeable media.
- Author
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Singh K, Menke H, Andrew M, Lin Q, Rau C, Blunt MJ, and Bijeljic B
- Abstract
Understanding the pore-scale dynamics of two-phase fluid flow in permeable media is important in many processes such as water infiltration in soils, oil recovery, and geo-sequestration of CO
2 . The two most important processes that compete during the displacement of a non-wetting fluid by a wetting fluid are pore-filling or piston-like displacement and snap-off; this latter process can lead to trapping of the non-wetting phase. We present a three-dimensional dynamic visualization study using fast synchrotron X-ray micro-tomography to provide new insights into these processes by conducting a time-resolved pore-by-pore analysis of the local curvature and capillary pressure. We show that the time-scales of interface movement and brine layer swelling leading to snap-off are several minutes, orders of magnitude slower than observed for Haines jumps in drainage. The local capillary pressure increases rapidly after snap-off as the trapped phase finds a position that is a new local energy minimum. However, the pressure change is less dramatic than that observed during drainage. We also show that the brine-oil interface jumps from pore-to-pore during imbibition at an approximately constant local capillary pressure, with an event size of the order of an average pore size, again much smaller than the large bursts seen during drainage.- Published
- 2017
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33. Investigation of longitudinal and transverse dispersion in stable displacements with a high viscosity and density contrast between the fluids.
- Author
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Alkindi A, Al-Wahaibi Y, Bijeljic B, and Muggeridge A
- Subjects
- Chemical Phenomena, Ethanol chemistry, Glycerol chemistry, Gravitation, Hydrodynamics, Salts chemistry, Viscosity, Water chemistry, Soil Pollutants chemistry, Water Pollutants, Chemical chemistry
- Abstract
Transverse and longitudinal dispersion in gravity stable, favourable viscosity ratio flows are investigated and compared with earlier data obtained for miscible fluids and for tracer flow. Data from laboratory measurements of longitudinal dispersion in low viscosity ratio (8.63×10(-)(4)) and high density contrast (471 kg m(-3)) displacements are compared with literature data for more modest viscosity ratios and density differences and with earlier theoretical analysis. The longitudinal dispersivity was reduced by a factor of 2 for flows influenced by gravity. This reduction was relatively insensitive to the magnitude of the density contrast and the flow rate, for Peclet numbers less than 100 and found to be consistent with earlier theoretical predictions. Additional transverse dispersion data was obtained for fluids with a density contrast of 225 kg m(-3) and a matched viscosity ratio over a range of Peclet numbers (1
- Published
- 2011
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34. Non-Fickian transport in porous media with bimodal structural heterogeneity.
- Author
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Bijeljic B, Rubin S, Scher H, and Berkowitz B
- Subjects
- Algorithms, Chemical Phenomena, Particle Size, Permeability, Water Movements, Environmental Monitoring, Soil Pollutants analysis, Water Pollutants, Chemical analysis
- Abstract
Tracer tailing in breakthrough curves in porous media with two distinct porosities is analyzed in terms of the dynamic responses of experimental fixed bed columns filled either with solid or porous beads. The flow is fast in the column interstitial space between beads (for both solid and porous beads) but slow within the porous beads that act as controlled 'traps' constituting an immobile zone. The transport is quantified using a Continuous Time Random Walk (CTRW) framework, which accounts for domains with controlled structural and flow heterogeneity associated with two distinct spatial and time spectra. We first demonstrate that breakthrough curves for a column containing solid glass beads exhibit non-Fickian transport, quantifiable both in fitting and validation mode by a CTRW based on a power law transition time distribution. We then examine breakthrough curves in the porous bead case, obtaining fits with a two-scale CTRW model that accounts explicitly for the two time spectra. Because the porous beads are uniform, tracer trapping within them is described by a simple first-order approximation trap model, with relatively weak capture and relatively faster release rates. The extent of tailing apparent in the porous bead breakthrough curves, due to the traps, can be quantitatively distinguished from the contribution to tailing due to mobile zone non-Fickian transport. A parameter study of the two-scale CTRW adds further insight into the dynamics of the process, showing the interaction between the advective non-Fickian transport and the mass exchange to immobile regions., (Copyright © 2010 Elsevier B.V. All rights reserved.)
- Published
- 2011
- Full Text
- View/download PDF
35. Mixing, spreading and reaction in heterogeneous media: a brief review.
- Author
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Dentz M, Le Borgne T, Englert A, and Bijeljic B
- Subjects
- Adsorption, Kinetics, Chemical Phenomena, Hydrodynamics, Models, Theoretical, Soil Pollutants analysis, Water Pollutants chemistry
- Abstract
Geological media exhibit heterogeneities in their hydraulic and chemical properties, which can lead to enhanced spreading and mixing of the transported species and induce an effective reaction behavior that is different from the one for a homogeneous medium. Chemical heterogeneities such as spatially varying adsorption properties and specific reactive surface areas can act directly on the chemical reaction dynamics and lead to different effective reaction laws. Physical heterogeneities affect mixing-limited chemical reactions in an indirect way by their impact on spreading and mixing of dissolved species. To understand and model large-scale reactive transport the interactions of these coupled processes need to be understood and quantified. This paper provides a brief review on approaches of non-reactive and reactive transport modeling in geological media., (Copyright © 2010 Elsevier B.V. All rights reserved.)
- Published
- 2011
- Full Text
- View/download PDF
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