Publications
530 results found
Mahdaviara M, Shojaei MJ, Siavashi J, et al., 2023, Deep learning for multiphase segmentation of X-ray images of gas diffusion layers, Fuel, Vol: 345, ISSN: 0016-2361
High-resolution X-ray computed tomography (micro-CT) has been widely used to characterise fluid flow in porous media for different applications, including in gas diffusion layers (GDLs) in fuel cells. In this study, we examine the performance of 2D and 3D U-Net deep learning models for multiphase segmentation of unfiltered X-ray tomograms of GDLs with different percentages of hydrophobic polytetrafluoroethylene (PTFE). The data is obtained by micro-CT imaging of GDLs after brine injection. We train deep learning models on base-case data prepared by the 3D Weka segmentation method and test them on the unfiltered unseen datasets. Our assessments highlight the effectiveness of the 2D and 3D U-Net models with test IoU values of 0.901 and 0.916 and f1-scores of 0.947 and 0.954, respectively. Most importantly, the U-Net models outperform conventional 3D trainable Weka and watershed segmentation based on various visual examinations. Lastly, flow simulation studies reveal segmentation errors associated with trainable Weka and watershed segmentation lead to significant errors in the calculated porous media properties, such as absolute permeability. Our findings show 43, 14, 14, and 3.9% deviations in computed permeabilities for GDLs coated by 5, 20, 40, and 60 w% of PTFE, respectively, compared to images segmented by the 3D Weka segmentation method.
Zhang Y, Bijeljic B, Gao Y, et al., 2023, Pore-Scale Observations of Hydrogen Trapping and Migration in Porous Rock: Demonstrating the Effect of Ostwald Ripening, Geophysical Research Letters, Vol: 50, ISSN: 0094-8276
We use high-resolution three-dimensional X-ray imaging to study hydrogen injection and withdrawal in the pore space of Bentheimer sandstone. The results are compared with a replicate experiment using nitrogen. We observe less trapping with hydrogen because the initial saturation after drainage is lower due to channeling. Remarkably we observe that after imbibition, if the sample is imaged again after 12 hr, there is a significant rearrangement of the trapped hydrogen. Many smaller ganglia disappear while the larger ganglia swell, with no detectable change in overall gas volume. For nitrogen, the fluid configuration is largely unchanged. This rearrangement is facilitated by concentration gradients of dissolved gas in the aqueous phase—Ostwald ripening, We estimate the time-scales for this effect to be significant, consistent with the experimental observations. The swelling of larger ganglia potentially increases the gas connectivity, leading to less hysteresis and more efficient withdrawal.
Mukherjee S, Johns RT, Foroughi S, et al., 2023, Fluid-Fluid Interfacial Area and Its Impact on Relative Permeability: A Pore Network Modeling Study, SPE Journal, Vol: 28, Pages: 653-663, ISSN: 1086-055X
Relative permeability (kr) is commonly modeled as an empirical function of phase saturation. Although current empirical models can provide a good match of one or two measured relative permeabilities using saturation alone, they are unable to predict relative permeabilities well when there is hysteresis or when physical properties such as wettability change. Further, current models often result in relative permeability discontinuities that can cause convergence and accuracy problems in simulation. To overcome these problems, recent research has modeled relative permeability as a state function of both saturation (S) and phase connectivity (X). Pore network modeling (PNM) data, however, show small differences in relative permeability for the same S-X value when approached from a different flow direction. This paper examines the impact of one additional Minkowski parameter (Mecke and Arns 2005), the fluid-fluid interfacial area, on relative permeability to identify if that satisfactorily explains this discrepancy. We calculate the total fluid-fluid interfacial areas (IA) during two-phase (oil/water) flow in porous media using PNM. The area is calculated from PNM simulations using the areas associated with corners and throats in pore elements of different shapes. The pore network is modeled after a Bentheimer sandstone, using square, triangular prism, and circular pore shapes. Simulations were conducted for numerous primary drainage (PD) and imbibition cycles at a constant contact angle of 0° for the wetting phase. Simultaneous measurements of capillary pressure, relative permeability, saturation, and phase connectivity are made for each displacement. The fluid-fluid IA is calculated from the PNM capillary pressure, the fluid location in the pore elements, and the pore element dimensional data. The results show that differences in the relative permeability at the same (S, X) point are explained well by differences in the fluid-fluid interfacial area (IA). That is, f
Giudici LM, Qaseminejad Raeini A, Blunt MJ, et al., 2023, Representation of Fully Three-Dimensional Interfacial Curvature in Pore-Network Models, Water Resources Research, Vol: 59, ISSN: 0043-1397
Quasi two-dimensional approximations of interfacial curvature, present in current network models of multiphase flow in porous media, are extended to three dimensions. The new expressions for threshold capillary pressure are validated and calibrated using high-resolution direct numerical simulations on synthetic geometries. The effects of pore-space expansion and sagittal interface curvature on displacement are quantified, and are shown to be a key step in improving the physical accuracy of network models. Finally, the calibrated network model is used to obtain predictions for relative permeability and capillary pressure in a water-wet Bentheimer sandstone. The predictions are compared to experimental measurements, revealing that the inclusion of three-dimensional interfacial curvature leads to more accurate predictions.
Giudici LM, Raeini AQ, Akai T, et al., 2023, Pore-scale modeling of two-phase flow: A comparison of the generalized network model to direct numerical simulation., Phys Rev E, Vol: 107
Despite recent advances in pore-scale modeling of two-phase flow through porous media, the relative strengths and limitations of various modeling approaches have been largely unexplored. In this work, two-phase flow simulations from the generalized network model (GNM) [Phys. Rev. E 96, 013312 (2017)2470-004510.1103/PhysRevE.96.013312; Phys. Rev. E 97, 023308 (2018)2470-004510.1103/PhysRevE.97.023308] are compared with a recently developed lattice-Boltzmann model (LBM) [Adv. Water Resour. 116, 56 (2018)0309-170810.1016/j.advwatres.2018.03.014; J. Colloid Interface Sci. 576, 486 (2020)0021-979710.1016/j.jcis.2020.03.074] for drainage and waterflooding in two samples-a synthetic beadpack and a micro-CT imaged Bentheimer sandstone-under water-wet, mixed-wet, and oil-wet conditions. Macroscopic capillary pressure analysis reveals good agreement between the two models, and with experiments, at intermediate saturations but shows large discrepancy at the end-points. At a resolution of 10 grid blocks per average throat, the LBM is unable to capture the effect of layer flow which manifests as abnormally large initial water and residual oil saturations. Critically, pore-by-pore analysis shows that the absence of layer flow limits displacement to invasion-percolation in mixed-wet systems. The GNM is able to capture the effect of layers, and exhibits predictions closer to experimental observations in water and mixed-wet Bentheimer sandstones. Overall, a workflow for the comparison of pore-network models with direct numerical simulation of multiphase flow is presented. The GNM is shown to be an attractive option for cost and time-effective predictions of two-phase flow, and the importance of small-scale flow features in the accurate representation of pore-scale physics is highlighted.
Hematpur H, Abdollahi R, Rostami S, et al., 2023, Review of underground hydrogen storage: Concepts and challenges, Advances in Geo-Energy Research, Vol: 7, Pages: 111-131, ISSN: 2207-9963
The energy transition is the pathway to transform the global economy away from its current dependence on fossil fuels towards net zero carbon emissions. This requires the rapid and large-scale deployment of renewable energy. However, most renewables, such as wind and solar, are intermittent and hence generation and demand do not necessarily match. One way to overcome this problem is to use excess renewable power to generate hydrogen by electrolysis, which is used as an energy store, and then consumed in fuel cells, or burnt in generators and boilers on demand, much as is presently done with natural gas, but with zero emissions. Using hydrogen in this way necessitates large-scale storage: the most practical manner to do this is deep underground in salt caverns, or porous rock, as currently implemented for natural gas and carbon dioxide. This paper reviews the concepts, and challenges of underground hydrogen storage. As well as summarizing the state-of-the-art, with reference to current and proposed storage projects, suggestions are made for future work and gaps in our current understanding are highlighted. The role of hydrogen in the energy transition and storage methods are described in detail. Hydrogen flow and its fate in the subsurface are reviewed, emphasizing the unique challenges compared to other types of gas storage. In addition, site selection criteria are considered in the light of current field experience.
Alhosani A, Selem A, Foroughi S, et al., 2023, Steady-state three-phase flow in a mixed-wet porous medium: a pore-scale X-ray microtomography study, Advances in Water Resources, Vol: 172, Pages: 1-19, ISSN: 0309-1708
We use three-dimensional X-ray imaging to investigate steady-state three-phase flow in a mixed-wet reservoir rock, while measuring both relative permeability and capillary pressure. Oil occupied the smallest pores, gas the biggest, while water occupied medium-sized pores. We report a distinct flow pattern, where gas flows in the form of disconnected ganglia by periodically opening critical flow pathways. Despite having capillary-controlled displacements, a significant fraction of the pore space was intermittently occupied by gas-oil and oil-water phases. Both types of intermittency occurred in intermediate-sized pores. Gas mainly displaces oil, and oil displaces water as the gas flow rate is increased, while oil displaces gas, and water displaces oil as gas flow is decreased. At the resolution of the images, no detectable gas was trapped in the rock due to its mixed-wettability which prevents either oil or water completely surrounding gas, suppressing snap-off and capillary trapping, which has significant implications for the design of gas storage in three-phase systems.
Amrouche F, Blunt MJ, Iglauer S, et al., 2023, Using magnesium oxide nanoparticles in a magnetic field to enhance oil production from oil-wet carbonate reservoirs, MATERIALS TODAY CHEMISTRY, Vol: 27, ISSN: 2468-5194
Zhang G, Foroughi S, Raeini AQ, et al., 2023, The impact of bimodal pore size distribution and wettability on relative permeability and capillary pressure in a microporous limestone with uncertainty quantification, Advances in Water Resources, Vol: 171, ISSN: 0309-1708
Pore-scale X-ray imaging combined with a steady-state flow experiment was used to study the displacement processes during waterflooding in an altered-wettability carbonate, Ketton limestone, with more than two orders of magnitude difference in pore size between macropores and microporosity. We simultaneously characterized macroscopic and local multiphase flow parameters, including relative permeability, capillary pressure, wettability, and fluid occupancy in pores and throats. An accurate method was applied for porosity and fluid saturation measurements using greyscale based differential imaging without image segmentation. The relative permeability values were corrected by considering the measured saturation profile along the sample length to account for the so-called capillary end effect. The behaviour of relative permeability and capillary pressure was compared to other measurements in the literature to demonstrate the combined effects of wettability and pore structure. Typical oil-wet behaviour in resolvable macropores was measured from contact angle, fluid occupancy and curvature. The capillary pressure was negative while the oil relative permeability dropped quickly as oil was drained to low saturation and flowed through connected oil layers. Brine initially largely flowed through water-wet microporosity, and then filled the centre of large oil-wet pore bodies. Thus, the brine relative permeability remained exceptionally low until brine formed a connected flow path in the macropores leading to a substantial increase in relative permeability. Overall, this work demonstrates that not only wettability but also pore size distribution and microporosity have significant impact on displacement processes.
Oliveira R, Blunt MJ, Bijeljic B, 2023, Impact of physical heterogeneity and transport conditions on effective reaction rates in dissolution, Transport in Porous Media, Vol: 146, Pages: 113-138, ISSN: 0169-3913
A continuous-time random walk (CTRW) reactive transport model is used to study the impact of physical heterogeneity on the effective reaction rates in porous media in a sample of length 15 cm over timescales up to 108 s (3 years). The model has previously been validated using nuclear magnetic resonance (NMR) measurements during dissolution of a limestone. The model assumes first-order reaction. We construct three domains with increasing physical heterogeneity and study dissolution at four Péclet numbers, Pe = 0.0542, 0.542, 5.42 and 54.2. We characterize signatures of physical heterogeneity in the three porous media using velocity distributions and show how these imprint on the signatures of particle displacement, namely particle propagator distributions. In addition, we demonstrate the ability of our CTRW model to capture the impact of physical heterogeneity on the longitudinal dispersion coefficient over several orders of magnitude in space and time. Reactive transport simulations show that the effective reaction rates depend on (i) initial physical heterogeneity and (ii) transport conditions. For all heterogeneities and Pe, the late-time reaction rate exhibits a time dependence t−a with a≠0.5 that indicates the persistence of incomplete mixing. We show that the higher the initial heterogeneity, the lower the late-time reaction rate. A decrease in Pe promotes mixing by diffusion over advection, resulting in higher reaction rates. The post-dissolution propagators indicate an increase in the degree of non-Fickian transport. Overall, we establish a framework to demonstrate and quantify the impact of physical heterogeneity on transport and effective reaction rates in porous media.
Khoshtarash H, Siavashi M, Ramezanpour M, et al., 2022, Pore-scale analysis of two-phase nanofluid flow and heat transfer in open-cell metal foams considering Brownian motion, Applied Thermal Engineering, Vol: 221, Pages: 1-16, ISSN: 1359-4311
Simultaneous use of porous media and nanofluids will increase the convective heat transfer multiple times compared to non-porous and pure fluid conditions. Heat transfer and flow transport of nanofluids inside porous media are usually simulated in large-scale with average properties, which are typically highly uncertain. Pore-scale simulation as an alternative approach can capture the characteristics of flow and heat transfer more accurately. Only few studies have been conducted to study nanofluid flow through porous media in pore-scale, and most of them employed single-phase approach without focus on different affective forces. This paper uses a pore-scale approach to investigate the flow characteristics and convective heat transfer of two-phase nanofluid flow in open-cell metal foams (OCMFs). Simulation of fluid flow and heat transfer is achieved by Buongiorno’s model. Therefore, a computational code through the OpenFOAM library that operates by a direct numerical simulation (DNS) approach and the finite volume method (FVM) is used. The momentum, energy, continuity, and nanoparticle distribution equations are discretized, and the SIMPLE algorithm is utilized for pressure and velocity coupling. In the present study, three OCMFs with a constant porosity (0.86) and various pore densities are investigated. Also, variations of pressure gradient, Nusselt number, and Darcy velocity are investigated as a function of pore density (as a geometric parameter), nanoparticle diameter, concentration, and Brownian motion force. The results indicate that the Brownian force enhances the heat transfer in OCMFs from 2% by up to 14% for the nanofluid flowing with 3% nanoparticle concentration. Also, increasing the diameter of nanoparticles reduces the Darcy velocity and heat transfer by up to 4%. On the other hand, increasing particle concentration from 3% to 5%, increases heat transfer by up to 10% and reduces the Darcy velocity by up to 9%. Finally, doubling the pore density d
Selem AM, Agenet N, Blunt MJ, et al., 2022, Pore-scale processes in tertiary low salinity waterflooding in a carbonate rock: Micro-dispersions, water film growth, and wettability change, Journal of Colloid and Interface Science, Vol: 628, Pages: 486-498, ISSN: 0021-9797
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.
Imani G, Zhang L, Blunt MJ, et al., 2022, Three-dimensional simulation of droplet dynamics in a fractionally-wet constricted channel, ADVANCES IN WATER RESOURCES, Vol: 170, ISSN: 0309-1708
Ranaee E, Khattar R, Inzoli F, et al., 2022, Assessment and uncertainty quantification of onshore geological CO2 storage capacity in China, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 121, ISSN: 1750-5836
Foroughi S, Bijeljic B, Blunt MJ, 2022, A closed-form equation for capillary pressure in porous media for all wettabilities, Transport in Porous Media, Vol: 145, Pages: 683-696, ISSN: 0169-3913
A saturation–capillary pressure relationship is proposed that is applicable for all wettabilities, including mixed-wet and oil-wet or hydrophobic media. This formulation is more flexible than existing correlations that only match water-wet data, while also allowing saturation to be written as a closed-form function of capillary pressure: we can determine capillary pressure explicitly from saturation, and vice versa. We proposePc=A+Btan(π2−πSCe)for0≤Se≤1,where Se is the normalized saturation. A indicates the wettability: A>0 is a water-wet medium, A<0 is hydrophobic while small A suggests mixed wettability. B represents the average curvature and pore-size distribution which can be much lower in mixed-wet compared to water-wet media with the same pore structure if the menisci are approximately minimal surfaces. C is an exponent that controls the inflection point in the capillary pressure and the asymptotic behaviour near end points. We match the model accurately to 29 datasets in the literature for water-wet, mixed-wet and hydrophobic media, including rocks, soils, bead and sand packs and fibrous materials with over four orders of magnitude difference in permeability and porosities from 20% to nearly 90%. We apply Leverett J-function scaling to make the expression for capillary pressure dimensionless and discuss the behaviour of analytical solutions for spontaneous imbibition.
Blunt MJ, 2022, Ostwald ripening and gravitational equilibrium: Implications for long-term subsurface gas storage., Phys Rev E, Vol: 106
The equilibrium configuration of a gas and brine in a porous medium, and the timescales to reach equilibrium, are investigated analytically. If the gas is continuous in the pore space, we have the traditional gravity-capillary transition zone: P_{c}(S_{w})=Δρgz where P_{c} is the capillary pressure (pressure difference between the gas and aqueous phases), S_{w} is the aqueous phase (brine) saturation, Δρ=ρ_{w}-ρ_{g} is the density difference between the phases, g is the gravitational acceleration, and z is a vertical distance coordinate increasing upwards, where z=0 indicates the level where P_{c}=0. However, if the gas is disconnected, as may occur during water influx in carbon dioxide and hydrogen storage, then the nature of equilibrium is different where diffusion through the aqueous phase (Ostwald ripening) maintains a capillary pressure gradient consistent with the thermodynamically-determined brine density as a function of depth: P_{c}=P^{*}[e^{(V_{g}ρ_{w}-m_{g})gz/RT}-1]+ρ_{w}gz, where P^{*} is the aqueous phase pressure at z=0, V_{g} is the specific molar volume of the gas dissolved in the aqueous phase, m_{g} is the molecular mass of the gas, R is the universal gas constant, and T is the absolute temperature. The capillary pressure decreases with depth. This means that a deep column of trapped gas cannot be sustained indefinitely. Instead a transition zone forms in equilibrium with connected gas near the top of the formation: its thickness is typically less than 1 m for carbon dioxide, hydrogen, methane or nitrogen in a permeable reservoir. The timescales to reach equilibrium are, however, estimated to be millions of years, and hence do not significantly affect long-term storage over millennia. At the scale of laboratory experiments, in contrast, Ostwald ripening leads to local capillary equilibrium in a few weeks to a year, dependent on the gas considered.
Amrouche F, Xu D, Short M, et al., 2022, Experimental study of electrical heating to enhance oil production from oil-wet carbonate reservoirs, Fuel: the science and technology of fuel and energy, Vol: 324, Pages: 1-12, ISSN: 0016-2361
New approaches for enhanced oil recovery (EOR) with a reduced environmental footprint are required to improve recovery from mature oil fields, and when combined with carbon capture and storage (CCS) can provide useful options for resource maximisation during the net zero transition. Electrical heating is investigated as a potential EOR method in carbonate reservoirs. Samples were placed in an apparatus surrounded by a wire coil across which different DC (direct current) voltages were applied. Monitoring the imbibition of both deionized water (DW) and seawater (SW) into initially oil-wet Austin chalk showed that water imbibed into the rock faster when heated in the presence of a magnetic field. This was associated with a reduction in the water–air contact angle over time measured on the external surface of the sample. Without heating, the contact angle reduced from 127° approaching water-wet conditions, 90°, in 52 min, while in the presence of heating with 3 V, 6 V, and 9 V applied across a sample 17 mm in length, the time required to reach the same contact angle was only 47, 38 and 26 min, respectively, while a further reduction in contact angle was witnessed with SW. The ultimate recovery factor (RF) for an initially oil-wet sample imbibed by DW was 13% while by seawater (SW) the recorded RF was 26% in the presence of an electrical heating compared with 2.8% for DW and 11% for SW without heating. We propose heating as an effective way to improve oil recovery, enhancing capillary-driven natural water influx, and observe that renewable-powered heating for EOR with CCS may be one option to improve recovery from mature oil fields with low environmental footprint.
Spurin C, Rucker M, Moura M, et al., 2022, Red Noise in Steady-State Multiphase Flow in Porous Media, WATER RESOURCES RESEARCH, Vol: 58, ISSN: 0043-1397
Blunt MJ, Lin Q, 2022, Flow in Porous Media in the Energy Transition, ENGINEERING, Vol: 14, Pages: 10-14, ISSN: 2095-8099
Raeini AQ, Giudici LM, Blunt MJ, et al., 2022, Generalized network modelling of two-phase flow in a water-wet and mixed-wet reservoir sandstone: Uncertainty and validation with experimental data, Advances in Water Resources, Vol: 164, Pages: 1-14, ISSN: 0309-1708
We use a generalized pore network model in combination with image-based experiments to understand the parameters that control upscaled flow properties. The study is focued on water-flooding through a reservoir sandstone under water-wet and mixed-wet conditions. A set of sensitivity studies is presented to quantify the role of wettability, pore geometry, initial and boundary conditions as well as a selection of model parameters used in the computation of fluid volumes, curvatures and flow and electrical conductivities. We quantify the uncertainty in the model predictions, which match the measured relative permeability and capillary pressure within the uncertainty of the experiments. Our results show that contact angle, initial saturation, image quality and image processing algorithm are amongst the parameters which introduce the largest variance in the predictions of upscaled flow properties for both mixed-wet and water-wet conditions.
Zhang Y, Lin Q, Raeini AQ, et al., 2022, Pore-scale imaging of asphaltene deposition with permeability reduction and wettability alteration, Fuel, Vol: 316, Pages: 1-9, ISSN: 0016-2361
To better understand asphaltene deposition mechanisms and their influence on rock permeability and wettability, we have developed an in situ micro-CT imaging capability to observe asphaltene precipitation during multiphase flow at high resolution in three dimensions. Pure heptane and crude oil were simultaneously injected to induce asphaltene precipitation in the pore space of a sandstone rock sample. The heptane permeability across the sample was nine times lower after the first asphaltene precipitation, while it was reduced by a factor of ninety due to asphaltene migration and growth after subsequent brine injection. Furthermore, through quantifying the curvatures and contact angles on the images before and after asphaltene precipitation, we observed that the wettability of the porous medium changed from water-wet to mixed-wet. Overall, we demonstrate a micro-CT imaging and analysis workflow to quantify asphaltene deposition, permeability reduction and wettability change which can be used for reservoir characterisation and remediation.
Imani G, Zhang L, Blunt MJ, et al., 2022, Quantitative determination of the threshold pressure for a discontinuous phase to pass through a constriction using microscale simulation, INTERNATIONAL JOURNAL OF MULTIPHASE FLOW, Vol: 153, ISSN: 0301-9322
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Shojaei MJ, Bijeljic B, Zhang Y, et al., 2022, Minimal surfaces in porous materials: x-ray image-based measurement of the contact angle and curvature in gas diffusion layers to design optimal performance of fuel cells, ACS Applied Energy Materials, Vol: 5, Pages: 4613-4621, ISSN: 2574-0962
We inject water at a low flow rate through gas diffusion layers containing different percentages of polytetrafluoroethylene (PTFE) coating: 5, 20, 40, and 60%. We use high-resolution three-dimensional X-ray imaging to identify the arrangement of fibers, water, and air in the pore space. We also quantify the contact angle and meniscus curvature once the water has spanned the layer, flow has ceased, and water has reached a position of equilibrium. The average contact angle and water pressure at breakthrough increase with the amount of coating, although we see a wide range of contact angles with values both above and below 90°, indicating a mixed-wet state. We identify that the menisci form minimal surfaces (interfaces of zero curvature) consistent with pinned gas-water-solid contacts. Scanning electron microscopy images of the fibers show that the coated fibers have a rough surface. Between 93 and 100% of the contacts identified were found on the rough, hydrophobic, coated fibers or at the boundary between uncoated (hydrophilic) and coated (hydrophobic) regions; we hypothesize that these contacts are pinned. The one exception is the 60% PTFE layer, which shows distinctly hydrophobic properties and a negative capillary pressure (the water pressure is higher than that of air). The presence of minimal surfaces suggests that the water and gas pressures are equal, allowing water to flow readily without pressure build-up. From topological principles, the negative Gaussian curvature of the menisci implies that the fluid phases are well connected. The implication of these results is explored for the design of porous materials where the simultaneous flow of two phases occurs over a wide saturation range.
Qu M-L, Lu S-Y, Lin Q, et al., 2022, Characterization of Water Transport in Porous Building Materials Based on an Analytical Spontaneous Imbibition Model, TRANSPORT IN POROUS MEDIA, Vol: 143, Pages: 417-432, ISSN: 0169-3913
Blunt M, 2022, Acknowledgement of Reviewers for 2021, TRANSPORT IN POROUS MEDIA, Vol: 142, Pages: 407-410, ISSN: 0169-3913
Ramezanpour M, Siavashi M, Raeini AQ, et al., 2022, Pore-scale simulation of nanoparticle transport and deposition in a microchannel using a Lagrangian approach, JOURNAL OF MOLECULAR LIQUIDS, Vol: 355, ISSN: 0167-7322
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Singh K, Bultreys T, Raeini AQ, et al., 2022, New type of pore-snap-off and displacement correlations in imbibition, Journal of Colloid and Interface Science, Vol: 609, Pages: 384-392, ISSN: 0021-9797
HYPOTHESIS: Imbibition of a fluid into a porous material involves the invasion of a wetting fluid in the pore space through piston-like displacement, film and corner flow, snap-off and pore bypassing. These processes have been studied extensively in two-dimensional (2D) porous systems; however, their relevance to three-dimensional (3D) natural porous media is poorly understood. Here, we investigate these pore-scale processes in a natural rock sample using time-resolved 3D (i.e., four-dimensional or 4D) X-ray imaging. EXPERIMENTS: We performed a capillary-controlled drainage-imbibition experiment on an initially brine-saturated carbonate rock sample. The sample was imaged continuously during imbibition using 4D X-ray imaging to visualize and analyze fluid displacement and snap-off processes at the pore-scale. FINDINGS: We discover a new type of snap-off that occurs in pores, resulting in the entrapment of a small portion of the non-wetting phase in pore corners. This contrasts with previously-observed snap-off in throats which traps the non-wetting phase in pore centers. We relate the new type of pore-snap-off to the pinning of fluid-fluid interfaces at rough surfaces, creating contact angles close to 90°. Subsequently, we provide correlations for displacement events as a function of pore-throat geometry. Our findings indicate that having a small throat does not necessarily favor snap-off: the key criterion is the throat radius in relation to the pore radius involved in a displacement event, captured by the aspect ratio.
Zhang Y, Bijeljic B, Blunt MJ, 2022, Nonlinear multiphase flow in hydrophobic porous media, Journal of Fluid Mechanics, Vol: 934, Pages: 1-10, ISSN: 0022-1120
Multiphase flow in porous materials is conventionally described by an empirical extension to Darcy's law, which assumes that the pressure gradient is proportional to the flow rate. Through a series of two-phase flow experiments, we demonstrate that even when capillary forces are dominant at the pore scale, there is a nonlinear intermittent flow regime with a power-law dependence between pressure gradient and flow rate. Energy balance is used to predict accurately the start of the intermittent regime in hydrophobic porous media. The pore-scale explanation of the behaviour based on the periodic filling of critical flow pathways is confirmed through 3D micron-resolution X-ray imaging.
Mukherjee S, Johns RT, Foroughi S, et al., 2022, Fluid - Fluid Interfacial Area and Its Impact on Relative Permeability - A Pore Network Modeling Study
Relative permeability (kr) is commonly modeled as an empirical function of phase saturation. Although current empirical models can provide a good match of one or two measured relative permeabilities using saturation alone, they are unable to predict relative permeabilities well when there is hysteresis or when physical properties such as wettability change. Further, current models often result in relative permeability discontinuities that can cause convergence and accuracy problems in simulation. To overcome these problems, recent research has modeled relative permeability as a state function of both saturation (S) and phase connectivity (X). Pore network modeling (PNM) data, however, shows small differences in relative permeability for the same S-X value when approached from a different flow direction. This paper examines the impact of one additional Minkowski parameter (Mecke and Arns, 2005), the fluid-fluid interfacial area, on relative permeability to identify if that satisfactorily explains this discrepancy. We calculate the total fluid-fluid interfacial areas (IA) during two-phase (oil/water) flow in porous media using pore network modeling. The area is calculated from PNM simulations using the areas associated with corners and throats in pore elements of different shapes. The pore network is modeled after a Bentheimer sandstone, using square, triangular, and circular pore shapes. Simulations were conducted for numerous primary drainage and imbibition cycles at a constant contact angle of 0° for the wetting phase. Simultaneous measurements of capillary pressure, relative permeability, saturation, and phase connectivity are made for each displacement. Fluid-fluid interfacial area is calculated from the PNM capillary pressure, the fluid location in the pore elements, and the pore element dimensional data. The results show that differences in the relative permeability at the same (S,X) point is explained well by differences in the fluid-fluid interfacial area
Ladipo L, Blunt MJ, King PR, 2022, Crossflow effects on low salinity displacement in stratified heterogeneity, Journal of Petroleum Science and Engineering, Vol: 208, Pages: 1-26, ISSN: 0920-4105
Crossflow is a major factor affecting recovery efficiency in heterogeneous permeable media. In typical water-oil displacements, viscous-dominated crossflow improves oil recovery efficiency relative to no-crossflow depending on the shock-front and/or the mobility ratio across the displacement front. Its impact is not yet fully understood for augmented or engineered waterfloods such as controlled/low salinity waterflooding (LSWF). This is critical in such a flood with two distinct displacement shock-fronts – unlike a standard waterflood – that are potentially influenced by mixing of the brines which further complicates the crossflow behaviour. This paper presents a comprehensive treatment of crossflow effects on recovery or displacement efficiency along stratified media of contrasting properties during LSWF considering physical dispersion.We define dimensionless numbers to characterize no-crossflow, viscous- and gravity-dominated crossflow regimes for different mobility-ratios. In two-dimensional numerical simulations, we explore the influence of property contrasts and mobility-ratios across the two distinct shock-fronts on the viscous crossflow behaviour in a LSWF. The sensitivity of viscous crossflow recovery and (low-salinity) engineered-water sweep efficiency to mobility-ratios is evaluated at different performance times relative to no-crossflow displacement.Viscous crossflow (VC) is found to be relevant in water-oil displacements for permeability contrasts less than or equal to 1000, but less important for EOR low-salinity displacement once the permeability contrast exceeds 50. For the mobility-ratio cases considered, VC is unidirectional – from the fast to slow layer – only when the mobility-ratios across the two distinct shock-fronts are both favourable. Unlike a typical water-oil displacement, the weak dependency of late-time recovery efficiency on VC is observed to be a function of the mobility-ratio and dispersion in LSWF. An unfavour
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