Publications
73 results found
Alhosani A, Scanziani A, Lin Q, et al., 2020, Dynamics of water injection in an oil-wet reservoir rock at subsurface conditions: Invasion patterns and pore-filling events, Physical Review E, Vol: 102, Pages: 023110 – 1-023110 – 15, ISSN: 2470-0045
We use fast synchrotron x-ray microtomography to investigate the pore-scale dynamics of water injection in an oil-wet carbonate reservoir rock at subsurface conditions. We measure, in situ, the geometric contact angles to confirm the oil-wet nature of the rock and define the displacement contact angles using an energy-balance-based approach. We observe that the displacement of oil by water is a drainagelike process, where water advances as a connected front displacing oil in the center of the pores, confining the oil to wetting layers. The displacement is an invasion percolation process, where throats, the restrictions between pores, fill in order of size, with the largest available throats filled first. In our heterogeneous carbonate rock, the displacement is predominantly size controlled; wettability has a smaller effect, due to the wide range of pore and throat sizes, as well as largely oil-wet surfaces. Wettability only has an impact early in the displacement, where the less oil-wet pores fill by water first. We observe drainage associated pore-filling dynamics including Haines jumps and snap-off events. Haines jumps occur on single- and/or multiple-pore levels accompanied by the rearrangement of water in the pore space to allow the rapid filling. Snap-off events are observed both locally and distally and the capillary pressure of the trapped water ganglia is shown to reach a new capillary equilibrium state. We measure the curvature of the oil-water interface. We find that the total curvature, the sum of the curvatures in orthogonal directions, is negative, giving a negative capillary pressure, consistent with oil-wet conditions, where displacement occurs as the water pressure exceeds that of the oil. However, the product of the principal curvatures, the Gaussian curvature, is generally negative, meaning that water bulges into oil in one direction, while oil bulges into water in the other. A negative Gaussian curvature provides a topological quantification of th
Foroughi S, Bijeljic B, Lin Q, et al., 2020, Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks, Physical Review E: Statistical, Nonlinear, and Soft Matter Physics, Vol: 102, Pages: 023302 – 1-023302 – 15, ISSN: 1539-3755
A pore-network model is an upscaled representation of the pore space and fluid displacement, which is used to simulate two-phase flow through porous media. We use the results of pore-scale imaging experiments to calibrate and validate our simulations, and specifically to find the pore-scale distribution of wettability. We employ energy balance to estimate an average, thermodynamic, contact angle in the model, which is used as the initial estimate of contact angle. We then adjust the contact angle of each pore to match the observed fluid configurations in the experiment as a nonlinear inverse problem. The proposed algorithm is implemented on two sets of steady state micro-computed-tomography experiments for water-wet and mixed-wet Bentheimer sandstone. As a result of the optimization, the pore-by-pore error between the model and experiment is decreased to less than that observed between repeat experiments on the same rock sample. After calibration and matching, the model predictions for capillary pressure and relative permeability are in good agreement with the experiments. The proposed algorithm leads to a distribution of contact angle around the thermodynamic contact angle. We show that the contact angle is spatially correlated over around 4 pore lengths, while larger pores tend to be more oil-wet. Using randomly assigned distributions of contact angle in the model results in poor predictions of relative permeability and capillary pressure, particularly for the mixed-wet case.
Scanziani A, Lin Q, Alhosani A, et al., 2020, Dynamics of fluid displacement in mixed-wet porous media, Proceedings of the Royal Society A: Mathematical, Physical and Engineering Sciences, Vol: 476, Pages: 1-16, ISSN: 1364-5021
We identify a distinct two-phase flow invasion pattern in a mixed-wet porous medium. Time-resolved high-resolution synchrotron X-ray imaging is used to study the invasion of water through a small rock sample filled with oil, characterized by a wide non-uniform distribution of local contact angles both above and below 90°. The water advances in a connected front, but throats are not invaded in decreasing order of size, as predicted by invasion percolation theory for uniformly hydrophobic systems. Instead, we observe pinning of the three-phase contact between the fluids and the solid, manifested as contact angle hysteresis, which prevents snap-off and interface retraction. In the absence of viscous dissipation, we use an energy balance to find an effective, thermodynamic, contact angle for displacement and show that this angle increases during the displacement. Displacement occurs when the local contact angles overcome the advancing contact angles at a pinned interface: it is wettability which controls the filling sequence. The product of the principal interfacial curvatures, the Gaussian curvature, is negative, implying well-connected phases which is consistent with pinning at the contact line while providing a topological explanation for the high displacement efficiencies in mixed-wet media.
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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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
Alhosani A, Scanziani A, Lin Q, et al., 2020, Pore-scale mechanisms of CO2 storage in oilfields, Scientific Reports, Vol: 10, Pages: 1-9, ISSN: 2045-2322
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 CO2 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.
Mularczyk A, Lin Q, Blunt MJ, et al., 2020, Droplet and percolation network interactions in a fuel cell gas diffusion layer, Journal of The Electrochemical Society, Vol: 167, ISSN: 0013-4651
Product water accumulations in polymer electrolyte fuel cells can cause performance losses and reactant starvation leading to cell degradation. Liquid water removal in the form of droplets, fed by percolation networks in the gas diffusion layer (GDL), is one of the main transport mechanisms by which the water is evacuated from the GDL. In this study, the effect of droplet detachment in the gas channel on the water cluster inside the GDL has been investigated using X-ray tomographic microscopy and X-ray radiography. The droplet growth is captured in varying stages over a sequence of consecutive droplet releases, during which an inflation and deflation of the gas-liquid interface menisci of the percolating water structure in the GDL has been observed and correlated to changes in pressure fluctuations in the water phase via gas-liquid curvature analysis.
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
Gao Y, Lin Q, Bijeljic B, et al., 2020, Pore-scale dynamics and the multiphase Darcy law, Physical Review Fluids, Vol: 5, Pages: 1-12, ISSN: 2469-990X
Synchrotron x-ray microtomography combined with sensitive pressure differential measurements were used to study flow during steady-state injection of equal volume fractions of two immiscible fluids of similar viscosity through a 57-mm-long porous sandstone sample for a wide range of flow rates. We found three flow regimes. (1) At low capillary numbers, Ca, representing the balance of viscous to capillary forces, the pressure gradient, ∇P, across the sample was stable and proportional to the flow rate (total Darcy flux) qt (and hence capillary number), confirming the traditional conceptual picture of fixed multiphase flow pathways in porous media. (2) Beyond Ca∗≈10−6, pressure fluctuations were observed, while retaining a linear dependence between flow rate and pressure gradient for the same fractional flow. (3) Above a critical value Ca>Cai≈10−5 we observed a power-law dependence with ∇P∼qat with a≈0.6 associated with rapid fluctuations of the pressure differential of a magnitude equal to the capillary pressure. At the pore scale a transient or intermittent occupancy of portions of the pore space was captured, where locally flow paths were opened to increase the conductivity of the phases. We quantify the amount of this intermittent flow and identify the onset of rapid pore-space rearrangements as the point when the Darcy law becomes nonlinear. We suggest an empirical form of the multiphase Darcy law applicable for all flow rates, consistent with the experimental results.
Garfi G, Lin Q, Berg S, et al., 2019, Fluid surface coverage showing the controls of rock mineralogy on the wetting state
Alhosani A, Scanziani A, Lin Q, et al., 2019, In situ pore-scale analysis of oil recovery during three-phase near-miscible CO2 injection in a water-wet carbonate rock, Advances in Water Resources, Vol: 134, ISSN: 0309-1708
We study in situ three-phase near-miscible CO2 injection in a water-wet carbonate rock at elevated temperature and pressure using X-ray microtomography. We examine the recovery mechanisms, presence or absence of oil layers, pore occupancy and interfacial areas during a secondary gas injection process. In contrast to an equivalent immiscible system, we did not observe layers of oil sandwiched between gas in the centre of the pore space and water in the corners. At near-miscible conditions, the measured contact angle between oil and gas was approximately 73°, indicating only weak oil wettability in the presence of gas. Oil flows in the centres of large pores, rather than in layers for immiscible injection, when displaced by gas. This allows for a rapid production of oil since it is no longer confined to movement in thin layers. A significant recovery factor of 80% was obtained and the residual oil saturation existed as disconnected blobs in the corners of the pore space. At equilibrium, gas occupied the biggest pores, while oil and water occupied pores of varying sizes (small, medium and large). Again, this was different from an immiscible system, where water occupied only the smallest pores. We suggest that a double displacement mechanism, where gas displaces water that displaces oil is responsible for shuffling water into larger pores than that seen after initial oil injection. This is only possible since, in the absence of oil layers, gas can contact water directly. The gas-oil and oil-water interfacial areas are lower than in the immiscible case, since there are no oil layers and even water layers in the macro-pore space become disconnected; in contrast, there is a larger direct contact of oil to the solid. These results could serve as benchmarks for developing near-miscible pore-scale modelling tools.
Zahasky C, Jackson S, Lin Q, et al., 2019, Pore network model predictions of Darcy-scale multiphase flow heterogeneity validated by experiments
Jackson S, Lin Q, Krevor S, 2019, Representative elementary volumes, hysteresis and heterogeneity in multiphase flow from the pore to continuum scale
Blunt MJ, Lin Q, Akai T, et al., 2019, A thermodynamically consistent characterization of wettability in porous media using high-resolution imaging, Journal of Colloid and Interface Science, Vol: 552, Pages: 59-65, ISSN: 0021-9797
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.
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.
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.
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 – The SPWLA Journal of Formation Evaluation and Reservoir Description, Vol: 60, Pages: 264-272, ISSN: 1529-9074
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
Suttle M, Genge M, Folco L, et al., 2019, The atmospheric entry of fine-grained micrometeorites: the role of volatile gases in heating and fragmentation, Meteoritics and Planetary Science, Vol: 54, Pages: 503-520, ISSN: 1086-9379
The early stages of atmospheric entry are investigated in four large (250–950 μm) unmelted micrometeorites (three fine‐grained and one composite), derived from the Transantarctic Mountain micrometeorite collection. These particles have abundant, interconnected, secondary pore spaces which form branching channels and show evidence of enhanced heating along their channel walls. Additionally, a micrometeorite with a double‐walled igneous rim is described, suggesting that some particles undergo volume expansion during entry. This study provides new textural data which links together entry heating processes known to operate inside micrometeoroids, thereby generating a more comprehensive model of their petrographic evolution. Initially, flash heated micrometeorites develop a melt layer on their exterior; this igneous rim migrates inwards. Meanwhile, the particle core is heated by the decomposition of low‐temperature phases and by volatile gas release. Where the igneous rim acts as a seal, gas pressures rise, resulting in the formation of interconnected voids and higher particle porosities. Eventually, the igneous rim is breached and gas exchange with the atmosphere occurs. This mechanism replaces inefficient conductive rim‐to‐core thermal gradients with more efficient particle‐wide heating, driven by convective gas flow. Interconnected voids also increase the likelihood of particle fragmentation during entry and, may therefore explain the rarity of large fine‐grained micrometeorites among collections.
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.
Lin Q, Alhammadi AM, Gao Y, et al., 2019, Iscal for complete rock characterization: Using pore-scale imaging to determine relative permeability and capillary pressure
We combine steady-state measurements of relative permeability with pore-scale imaging to estimate local capillary pressure. High-resolution three-dimensional X-ray tomography enables the pore structure and fluid distribution to be quantified at reservoir temperatures and pressures with a resolution of a few microns. Two phases are injected through small cylindrical samples at a series of fractional flows until the pressure differential across the core is constant. Then high-quality images are acquired from which saturation is calculated, using differential imaging to quantify the phase distributions in micro-porosity which cannot be explicitly resolved. The relative permeability is obtained from the pressure drop and fractional flow, as in conventional measurements. The curvature of the fluid/fluid interfaces in the larger pore spaces is found, then from the Young-Laplace equation, the capillary pressure is calculated. In addition, the sequence of images of fluid distribution captures the displacement process. Observed gradients in capillary pressure - the capillary end effect - can be accounted for analytically in the calculation of relative permeability. We illustrate our approach with three examples of increasing complexity. First, we compare the measured relative permeability and capillary pressure for Bentheimer sandstone, both for a clean sample and a mixed-wet core that had been aged in reservoir crude oil after centrifugation. We characterize the distribution of contact angles to demonstrate that the mixed-wet sample has a wide range of angle centred, approximately, on 90°. We then study a water-wet micro-porous carbonate to illustrate the impact of sub-resolution porosity on the flow behaviour: here oil, as the non-wetting phase, is present in both the macro-pores and micro-porosity. Finally, we present results for a mixed-wet reservoir carbonate. We show that the oil/water interfaces in the mixed-wet samples are saddle-shaped with two opposite, but alm
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.
Reyes F, Lin Q, Cilliers JJ, et al., 2018, Quantifying mineral liberation by particle grade and surface exposure using X-ray microCT, Minerals Engineering, Vol: 125, Pages: 75-82, ISSN: 0892-6875
Liberation is a key driver in all mineral separation processes as it limits the maximum possible grade for a given recovery. In flotation, this is further complicated by the fact that it is surface exposure of the floatable minerals that determines the ultimate performance. Liberation, grade and surface exposure are commonly quantified using Scanning Electron Microscopy coupled to Energy Dispersive X-ray spectroscopy (SEM/EDX) analysis of polished sections. The intrinsically 2D nature of this technique can result in significant sampling errors and stereological effects that can affect the quantification of the ore's textural characteristics. X-ray microCT (XMT) is an imaging method that can non-invasively and non-destructively delineate ore fragments in 3D, thus providing an alternative method that eliminates the need for stereological corrections and readily provides surface exposure. A methodology and automated algorithm were developed for extracting this information from images of closely packed particles. By dividing these particles into classes based on both their surface exposure and grade, the extent to which there is preferential breakage of the particles can be assessed—an important consideration if sufficient surface liberation for good flotation performance is to be achieved at coarser particle sizes. Using low energy scanning simple 3D mineral maps can be obtained via XMT, allowing for the assessment of liberation and surface exposure for each mineral species. The methodology was tested on low grade porphyry copper ore as this is representative of the most commonly treated ore types for copper production.
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.
Lin Q, Andrew M, Thompson W, et al., 2018, Optimization of image quality and acquisition time for lab-based X-ray microtomography using an iterative reconstruction algorithm, Advances in Water Resources, Vol: 115, Pages: 112-124, ISSN: 0309-1708
© 2018 The Authors Non-invasive laboratory-based X-ray microtomography has been widely applied in many industrial and research disciplines. However, the main barrier to the use of laboratory systems compared to a synchrotron beamline is its much longer image acquisition time (hours per scan compared to seconds to minutes at a synchrotron), which results in limited application for dynamic in situ processes. Therefore, the majorit y of existing laboratory X-ray microtomography is limited to static imaging; relatively fast imaging (tens of minutes per scan) can only be achieved by sacrificing imaging quality, e.g. reducing exposure time or number of projections. To alleviate this barrier, we introduce an optimized implementation of a well-known iterative reconstruction algorithm that allows users to reconstruct tomographic images with reasonable image quality, but requires lower X-ray signal counts and fewer projections than conventional methods. Quantitative analysis and comparison between the iterative and the conventional filtered back-projection reconstruction algorithm was performed using a sandstone rock sample with and without liquid phases in the pore space. Overall, by implementing the iterative reconstruction algorithm, the required image acquisition time for samples such as this, with sparse object structure, can be reduced by a factor of up to 4 without measurable loss of sharpness or signal to noise ratio.
Gao Y, Lin Q, Bijeljic B, et al., 2017, X-ray Microtomography of Intermittency in Multiphase Flow at Steady State Using a Differential Imaging Method, Water Resources Research, Vol: 53, Pages: 10274-10292, ISSN: 0043-1397
We imaged the steady state flow of brine and decane in Bentheimer sandstone. We devised an experimental method based on differential imaging to examine how flow rate impacts impact the pore-scale distribution of fluids during coinjection. This allows us to elucidate flow regimes (connected, or breakup of the nonwetting phase path ways) for a range of fractional flows at two capillary numbers, Ca, namely 3.0 × 10 −7 and 7.5 × 10 −6 . At the lower Ca, for a fixed fractional flow, the two phases appear to flow in connected unchanging subnetworks of the pore space, consistent with conventional theory. At the higher Ca, we observed that a significant fraction of the pore space contained sometimes oil and sometimes brine during the 1 h scan: this intermittent occupancy, which was interpreted as regions of the pore space that contained both fluid phases for some time, is necessary to explain the flow and dynamic connectivity of the oil phase; pathways of always oil-filled portions of the void space did not span the core. This phase was segmented from the differential image between the 30 wt % KI brine image and the scans taken at each fractional flow. Using the grey scale histogram distribution of the raw images, the oil proportion in the intermittent phase was calculated. The pressure drops at each fractional flow at low and high flow rates were measured by high-precision differential pressure sensors. The relative permeabilities and fractional flow obtained by our experiment at the mm-scale compare well with data from the literature on cm-scale samples.
Al-Khulaifi Y, Lin Q, Blunt MJ, et al., 2017, Reservoir-condition pore-scale imaging of dolomite reaction with supercritical CO<inf>2</inf>acidified brine: Effect of pore-structure on reaction rate using velocity distribution analysis, International Journal of Greenhouse Gas Control, Vol: 68, Pages: 99-111, ISSN: 1750-5836
To investigate the impact of rock heterogeneity and flowrate on reaction rates and dissolution dynamics, four millimetre-scale Silurian dolomite samples were pre-screened based on their physical heterogeneity, defined by the simulated velocity distributions characterising each flow field. Two pairs of cores with similar heterogeneity were flooded with supercritical carbon-dioxide (scCO 2 ) saturated brine under reservoir conditions, 50 °C and 10 MPa, at a high (0.5 ml/min) and low (0.1 ml/min) flowrate. Changes to the pore structure brought about by dissolution were captured in situ using X-ray microtomography (micro-CT) imaging. Mass balance from effluent analysis sh owed a good agreement with calculations from imaging. Image calculated reaction rates (r eff ) were 5-38 times lower than the corresponding batch reaction rate under the same conditions of temperature and pressure but without mass transfer limitations. For both high (Péclet number = 2600-1200) and low (Péclet number = 420-300) flow rates, an impact of the initial rock heterogeneity was observed on both reaction rates and permeability-porosity relationships.
Reyes F, Lin Q, Udoudo O, et al., 2017, Calibrated X-ray micro-tomography for mineral ore quantification, Minerals Engineering, Vol: 110, Pages: 122-130, ISSN: 0892-6875
Scanning Electron Microscopy (SEM) based assessments are the most widely used and trusted imaging technique for mineral ore quantification. X-ray micro tomography (XMT) is a more recent addition to the mineralogy toolbox, but with the potential to extend the measurement capabilities into the three dimensional (3D) assessment of properties such as mineral liberation, grain size and textural characteristics. In addition, unlike SEM based assessments which require the samples to be sectioned, XMT is non-invasive and non-destructive. The disadvantage of XMT, is that the mineralogy must be inferred from the X-ray attenuation measurements, which can make it hard to distinguish from one another, whereas SEM when coupled with Energy-Dispersive X-ray Spectroscopy (EDX) provides elemental compositions and thus a more direct method for distinguishing different minerals. A new methodology that combines both methods at the mineral grain level is presented. The rock particles used to test the method were initially imaged in 3D using XMT followed by sectioning and the 2D imaging of the slices using SEM-EDX. An algorithm was developed that allowed the mineral grains in the 2D slice to be matched with their 3D equivalents in the XMT based images. As the mineralogy of the grains from the SEM images can be matched to a range of X-ray attenuations, this allows minerals which have similar attenuations to one another to be distinguished, with the level of uncertainty in the classification quantified. In addition, the methodology allowed for the estimation of the level of uncertainty in the quantification of grain size by XMT, the assessment of stereological effects in SEM 2D images and ultimately obtaining a simplified 3D mineral map from low energy XMT images. Copper sulphide ore fragments, with chalcopyrite and pyrite as the main sulphide minerals, were used to demonstrate the effectiveness of this procedure.
Lin Q, Bijeljic B, Rieke H, et al., 2017, Visualization and quantification of capillary drainage in the pore space of laminated sandstone by a porous plate method using differential imaging X-ray microtomography, WATER RESOURCES RESEARCH, Vol: 53, Pages: 7457-7468, ISSN: 0043-1397
The experimental determination of capillary pressure drainage curves at the pore scale is ofvital importance for the mapping of reservoir fluid distribution. To fully characterize capillary drainage in acomplex 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 quantifythe displacement from resolvable macropores and subresolution micropores. Nitrogen (N2) was injected asthe nonwetting phase at a constant pressure while the porous plate prevented its escape. The measuredporosity 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. Weobserved that the majority of the brine was displaced by N2in macropores at low capillary pressures, fol-lowed by a further brine displacement in micropores when capillary pressure increases. Furthermore, wewere able to discern that brine predominantly remained within the subresolution micropores, such asregions of fine lamination. The capillary pressure curve for pressures ranging from 0 to 1151 kPa is providedfrom the image analysis compares well with the conventional porous plate method for a cm-scale core butwas conducted over a period of 10 days rather than up to few months with the conventional porous platemethod. 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 scalessmaller than the micro-CT resolution
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