Publications
544 results found
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.
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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- Citations: 8
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
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- Citations: 4
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.
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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- Citations: 10
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
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- Citations: 2
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.
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.
Blunt M, 2022, Acknowledgement of Reviewers for 2021, TRANSPORT IN POROUS MEDIA, Vol: 142, Pages: 407-410, ISSN: 0169-3913
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.
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
Spurin C, Garfi G, Rücker M, et al., 2021, Red noise in steady-state multiphase flow
<jats:p>Understanding the interaction between competing fluids in the pore space of rocks is key for predicting subsurface flow and trapping, such as with CO2 in a saline aquifer. These processes occur over a large span of timescales (from seconds to thousands of years), and length scales (from microns to kilometres). Understanding the link between these temporal and spatial scales will enable us to interpolate between observations made at different resolutions. In this work we explore the temporal scales present during macroscopically steady-state multiphase flow in a porous rock using differential pressure measurements. We observe a cascade of timescales in the pressure differential i.e. a continuous range of frequencies, with lower frequencies having greater amplitudes. We demonstrate a scaling of the spectral density with frequency of S ∼ 1/f^2, or red noise, to describe the dynamics. This scaling is independent of the flow rate of the fluids or the fraction of the flow taken by water. This red, or Brownian, noise indicates a stochastic process where pressure fluctuations are seen throughout the pore space, resulting in intermittent filling of pores over a wide range of time-scales, from seconds to minutes in these experiments. This observation will aid future modelling of subsurface flow as it suggests self-organised critically of the system with no characteristic time or length scale.</jats:p>
Shams R, Masihi M, Boozarjomehry RB, et al., 2021, A hybrid of statistical and conditional generative adversarial neural network approaches for reconstruction of 3D porous media (ST-CGAN), ADVANCES IN WATER RESOURCES, Vol: 158, ISSN: 0309-1708
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- Citations: 9
Alhosani A, Selem AM, Lin Q, et al., 2021, Disconnected gas transport in steady‐state three‐phase flow, Water Resources Research, Vol: 57, Pages: 1-26, ISSN: 0043-1397
We use high-resolution three-dimensional X-ray microtomography to investigate fluid displacement during steady-state three-phase flow in a cm-sized water-wet sandstone rock sample. The pressure differential across the sample is measured which enables the determination of relative permeability; capillary pressure is also estimated from the interfacial curvature. Though the measured relative permeabilities are consistent, to within experimental uncertainty, with values obtained without imaging on larger samples, we discover a unique flow dynamics. The most non-wetting phase (gas) is disconnected across the system: gas flows by periodically opening critical flow pathways in intermediate-sized pores. While this phenomenon has been observed in two-phase flow, here it is significant at low flow rates, where capillary forces dominate at the pore-scale. Gas movement proceeds in a series of double and multiple displacement events. Implications for the design of three-phase flow processes and current empirical models are discussed: the traditional conceptualization of three-phase dynamics based on analogies to two-phase flow vastly over-estimates the connectivity and flow potential of the gas phase.
Karvounis P, Blunt MJ, 2021, Assessment of CO<sub>2</sub> geological storage capacity of saline aquifers under the North Sea, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 111, ISSN: 1750-5836
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- Citations: 5
Yang Y, Zhou Y, Blunt MJ, et al., 2021, Advances in multiscale numerical and experimental approaches for multiphysics problems in porous media, ADVANCES IN GEO-ENERGY RESEARCH, Vol: 5, Pages: 233-238, ISSN: 2207-9963
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- Citations: 25
Mularczyk A, Lin Q, Niblett D, et al., 2021, Operando liquid pressure determination in polymer electrolyte fuel cells., ACS Applied Materials and Interfaces, Vol: 13, Pages: 34003-34011, ISSN: 1944-8244
Extending the operating range of fuel cells to higher current densities is limited by the ability of the cell to remove the water produced by the electrochemical reaction, avoiding flooding of the gas diffusion layers. It is therefore of great interest to understand the complex and dynamic mechanisms of water cluster formation in an operando fuel cell setting as this can elucidate necessary changes to the gas diffusion layer properties with the goal of minimizing the number, size, and instability of the water clusters formed. In this study, we investigate the cluster formation process using X-ray tomographic microscopy at 1 Hz frequency combined with interfacial curvature analysis and volume-of-fluid simulations to assess the pressure evolution in the water phase. This made it possible to observe the increase in capillary pressure when the advancing water front had to overcome a throat between two neighboring pores and the nuanced interactions of volume and pressure evolution during the droplet formation and its feeding path instability. A 2 kPa higher breakthrough pressure compared to static ex situ capillary pressure versus saturation evaluations was observed, which suggests a rethinking of the dynamic liquid water invasion process in polymer electrolyte fuel cell gas diffusion layers.
Lin Q, Bijeljic B, Raeini AQ, et al., 2021, Drainage capillary pressure distribution and fluid displacement in a heterogeneous laminated sandstone, Geophysical Research Letters, Vol: 48, Pages: 1-11, ISSN: 0094-8276
We applied three-dimensional X-ray microtomography to image a capillary drainage process (0–1,000 kPa) in a cm-scale heterogeneous laminated sandstone containing three distinct regions with different pore sizes to study the capillary pressure. We used differential imaging to distinguish solid, macropore, and five levels of subresolution pore phases associated with each region. The brine saturation distribution was computed based on average CT values. The nonwetting phase displaced the wetting phase in order of pore size and connectivity. The drainage capillary pressure in the highly heterogeneous rock was dependent on the capillary pressures in the individual regions as well as distance to the boundary between regions. The complex capillary pressure distribution has important implications for accurate water saturation estimation, gas and/or oil migration and the capillary rise of water in heterogeneous aquifers.
Selem AM, Agenet N, Gao Y, et al., 2021, Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions, Scientific Reports, Vol: 11, Pages: 1-14, ISSN: 2045-2322
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.
Shams M, Singh K, Bijeljic B, et al., 2021, Direct numerical simulation of pore-scale trapping events during capillary-dominated two-phase flow in porous media, Transport in Porous Media, Vol: 138, Pages: 443-458, ISSN: 0169-3913
This study focuses on direct numerical simulation of imbibition, displacement of the non-wetting phase by the wetting phase, through water-wet carbonate rocks. We simulate multiphase flow in a limestone and compare our results with high-resolution synchrotron X-ray images of displacement previously published in the literature by Singh et al. (Sci Rep 7:5192, 2017). We use the results to interpret the observed displacement events that cannot be described using conventional metrics such as pore-to-throat aspect ratio. We show that the complex geometry of porous media can dictate a curvature balance that prevents snap-off from happening in spite of favourable large aspect ratios. We also show that pinned fluid-fluid-solid contact lines can lead to snap-off of small ganglia on pore walls; we propose that this pinning is caused by sub-resolution roughness on scales of less than a micron. Our numerical results show that even in water-wet porous media, we need to allow pinned contacts in place to reproduce experimental results.
Lin Q, Bijeljic B, Foroughi S, et al., 2021, Pore-scale imaging of displacement patterns in an altered-wettability carbonate, Chemical Engineering Science, Vol: 235, Pages: 1-12, ISSN: 0009-2509
High-resolution X-ray imaging combined with a steady-state flow experiment is used to demonstrate how pore-scale displacement affects macroscopic properties in an altered-wettability microporous carbonate, where porosity and fluid saturation can be directly obtained from the grey-scale micro-CT images. The resolvable macro pores are largely oil-wet with an average thermodynamic contact angle of 120°. The pore-by-pore analysis shows locally either oil or brine almost fully occupied the macro pores, with some oil displacement in the micro-porosity. We observed a typical oil-wet behaviour consistent with the contact angle measurement. The brine tended to occupy the larger macro pores, leading to a higher brine relative permeability, lower residual oil saturation, than under water-wet conditions and in a mixed-wet sandstone. The capillary pressure was negative and seven times larger in the carbonate than the sandstone, despite having a similar average pore size. These different displacement patterns are principally determined by the difference in wettability.
Foroughi S, Bijeljic B, Blunt MJ, 2021, Pore-by-pore modelling, validation and prediction of waterflooding in oil-wet rocks using dynamic synchrotron data, Transport in Porous Media, Vol: 138, Pages: 285-308, ISSN: 0169-3913
We predict waterflood displacement on a pore-by-pore basis using pore network modelling. The pore structure is captured by a high-resolution image. We then use an energy balance applied to images of the displacement to assign an average contact angle, and then modify the local pore-scale contact angles in the model about this mean to match the observed displacement sequence. Two waterflooding experiments on oil-wet rocks are analysed where the displacement sequence was imaged using time-resolved synchrotron imaging. In both cases the capillary pressure in the model matches the experimentally obtained values derived from the measured interfacial curvature. We then predict relative permeability for the full saturation range. Using the optimised contact angles distributed randomly in space has little effect on the predicted capillary pressures and relative permeabilities, indicating that spatial correlation in wettability is not significant in these oil-wet samples. The calibrated model can be used to predict properties outside the range of conditions considered in the experiment.
Alhosani A, Bijeljic B, Blunt MJ, 2021, Pore-scale imaging and analysis of wettability order, trapping and displacement in three-phase flow in porous media with various wettabilities, Transport in Porous Media, Vol: 140, Pages: 59-84, ISSN: 0169-3913
Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤ 1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas
Hashemi L, Blunt M, Hajibeygi H, 2021, Pore-scale modelling and sensitivity analyses of hydrogen-brine multiphase flow in geological porous media, Scientific Reports, Vol: 11, ISSN: 2045-2322
Underground hydrogen storage (UHS) in initially brine-saturated deep porous rocks is a promising large-scale energy storage technology, due to hydrogen’s high specific energy capacity and the high volumetric capacity of aquifers. Appropriate selection of a feasible and safe storage site vitally depends on understanding hydrogen transport characteristics in the subsurface. Unfortunately there exist no robust experimental analyses in the literature to properly characterise this complex process. As such, in this work, we present a systematic pore-scale modelling study to quantify the crucial reservoir-scale functions of relative permeability and capillary pressure and their dependencies on fluid and reservoir rock conditions. To conduct a conclusive study, in the absence of sufficient experimental data, a rigorous sensitivity analysis has been performed to quantify the impacts of uncertain fluid and rock properties on these upscaled functions. The parameters are varied around a base-case, which is obtained through matching to the existing experimental study. Moreover, cyclic hysteretic multiphase flow is also studied, which is a relevant aspect for cyclic hydrogen-brine energy storage projects. The present study applies pore-scale analysis to predict the flow of hydrogen in storage formations, and to quantify the sensitivity to the micro-scale characteristics of contact angle (i.e., wettability) and porous rock structure.
Spurin C, Bultreys T, Rücker M, et al., 2021, The development of intermittent multiphase fluid flow pathways through a porous rock, Advances in Water Resources, Vol: 150, Pages: 1-7, ISSN: 0309-1708
storage and natural gas production. However, due to experimental limitations, it has not been possible to identify why intermittency occurs at subsurface conditions and what the implications are for upscaled flow properties such as relative permeability. We address these questions with observations of nitrogen and brine flowing at steady-state through a carbonate rock. We overcome previous imaging limitations with high-speed (1s resolution), synchrotron-based X-ray micro-computed tomography combined with pressure measurements recorded while controlling fluid flux. We observe that intermittent fluid transport allows the non-wetting phase to flow through a more ramified network of pores, which would not be possible with connected pathway flow alone for the same flow rate. The volume of fluid intermittently fluctuating increases with capillary number, with the corresponding expansion of the flow network minimising the role of inertial forces in controlling flow even as the flow rate increases. Intermittent pathway flow sits energetically between laminar and turbulent through connected pathways. While a more ramified flow network favours lowered relative permeability, intermittency is more dissipative than laminar flow through connected pathways, and the relative permeability remains unchanged for low capillary numbers where the pore geometry controls the location of intermittency. However, as the capillary number increases further, the role of pore structure in controlling intermittency decreases which corresponds to an increase in relative permeability. These observations can serve as the basis of a model for the causal links between intermittent fluid flow, fluid distribution throughout the pore space, and the upscaled manifestation in relative permeability.
Karlsson O, Rocklöv J, Lehoux AP, et al., 2021, The human exposome and health in the Anthropocene, International Journal of Epidemiology, Vol: 50, Pages: 378-389, ISSN: 0300-5771
Wang YD, Blunt MJ, Armstrong RT, et al., 2021, Deep learning in pore scale imaging and modeling, EARTH-SCIENCE REVIEWS, Vol: 215, ISSN: 0012-8252
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- Citations: 72
Zhang Y, Bijeljic B, Gao Y, et al., 2021, Quantification of non‐linear multiphase flow in porous media, Geophysical Research Letters, Vol: 48, Pages: 1-7, ISSN: 0094-8276
We measure the pressure difference during two‐phase flow across a sandstone sample for a range of injection rates and fractional flows of water, the wetting phase, during an imbibition experiment. We quantify the onset of a transition from a linear relationship between flow rate and pressure gradient to a nonlinear power‐law dependence. We show that the transition from linear (Darcy) to nonlinear flow and the exponent in the power‐law is a function of fractional flow. We use energy balance to accurately predict the onset of intermittency for a range of fractional flows, fluid viscosities, and different rock types.
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