181 results found
Li M, Foroughi S, Zhao J, et al., 2023, Image-based pore-scale modelling of the effect of wettability on breakthrough capillary pressure in gas diffusion layers, Journal of Power Sources, Vol: 584, ISSN: 0378-7753
Wettability design is of crucial importance for the optimization of multiphase flow behaviour in gas diffusion layers (GDLs) in fuel cells. The accumulation of electrochemically-generated water in the GDLs will impact fuel cell performance. Hence, it is necessary to understand multiphase displacement to design optimal pore structures and wettability to allow the rapid flow of gases and water in GDLs over a wide saturation range. This work uses high-resolution in situ three-dimensional X-ray imaging combined with a pore network model to investigate the breakthrough capillary pressure and water saturation in GDLs manufactured with different mass fractions of polytetrafluoroethylene coating: 5, 20, 40, and 60%, making them more hydrophobic. We first demonstrate that the pore network extraction method provides representative networks for the fibrous porous media examined. Then, using a pore-network flow model we simulate water invasion into initially gas-filled fibrous media, and analyze the effect of wettability on breakthrough capillary pressure and water saturation. With an appropriate pore-scale characterization of wettability, a pore network model can match experimental results and predict displacement behaviour.
Zhang G, Regaieg M, Blunt MJ, et al., 2023, Primary drainage and waterflood capillary pressures and fluid displacement in a mixed-wet microporous reservoir carbonate, Journal of Hydrology, Vol: 625, ISSN: 0022-1694
A porous plate technique was developed to measure capillary pressure during both primary drainage and waterflooding in a reservoir carbonate rock sample. During primary drainage, a water-wet ceramic disc at the end of the sample allowed brine to be displaced but prevented the escape of oil while oil was injected at a sequence of increasing pressures. Saturation was measured using high-resolution three-dimensional X-ray imaging from the differences in greyscale (X-ray adsorption) between dry, partially-saturated and completely-saturated images. A two-step displacement process was observed, with the resolvable macro-pores displaced by oil followed by invasion into unresolved micro-porosity with a variation of two orders of magnitude in capillary pressure. The sample was then exposed to crude oil to render some of the solid surfaces oil-wet. A small amount of spontaneous imbibition (displacement at a positive capillary pressure) was observed in micro-porosity. Then an oil-wet porous plate was added to the outlet, so that water could be injected at a sequence of increasing pressures while only oil could escape. As expected, the oil-wet macro-porosity was displaced by brine at a low capillary pressure with a magnitude similar to that seen during drainage (but of opposite sign). Remarkably though the displacement of oil from micro-porosity occurred at a capillary pressure approximately an order of magnitude lower than in drainage, implying the existence of mixed-wettability with fluid menisci that are approximately minimal surfaces. The work demonstrates that in mixed-wet media displacement of oil from micro-porosity can occur at much lower capillary pressures that would be estimated from primary drainage results using the calculated pore size distribution.
Zhang G, Foroughi S, Bijeljic B, et al., 2023, A method to correct steady-state relative permeability measurements for inhomogeneous saturation profiles in one-dimensional flow, Transport in Porous Media, Vol: 149, Pages: 837-852, ISSN: 0169-3913
Traditionally, steady-state relative permeability is calculated from measurements on small rock samples using Darcy’s law and assuming a homogenous saturation profile and constant capillary pressure. However, these assumptions are rarely correct as local inhomogeneities exist; furthermore, the wetting phase tends to be retained at the outlet–the so-called capillary end effect. We have introduced a new method that corrects the relative permeabilities, analytically, for an inhomogeneous saturation profile along the flow direction. The only data required are the measured pressure drops for different fractional flow values, an estimate of capillary pressure, and the saturation profiles. An optimization routine is applied to find the range of relative permeability values consistent with the uncertainty in the measured pressure. Assuming a homogenous saturation profile systematically underestimates the relative permeability and this effect is most marked for media where one of the phases is strongly wetting with a noticeable capillary end effect. Relative permeabilities from seven two-phase flow experiments in centimetre-scale samples with different wettability were corrected while reconciling some hitherto apparently contradictory results. We reproduce relative permeabilities of water-wet Bentheimer sandstone that are closer to other measurements in the literature on larger samples than the original analysis. Furthermore, we find that the water relative permeability during waterflooding a carbonate sample with a wide range of pore sizes can be high, due to good connectivity through the microporosity. For mixed-wet media with lower capillary pressure and less variable saturation profiles, the corrections are less significant.
Moghadasi R, Goodarzi S, Zhang Y, et al., 2023, Pore-scale characterization of residual gas remobilization in CO2 geological storage, Advances in Water Resources, Vol: 179, Pages: 1-8, ISSN: 0309-1708
A decrease in reservoir pressure can lead to remobilization of residually trapped CO2. In this study, the pore-scale processes related to trapped CO2 remobilization under pressure depletion were investigated with the use of high-resolution 3D X-ray microtomography. The distribution of CO2 in the pore space of Bentheimer sandstone was measured after waterflooding at a fluid pressure of 10 MPa, and then at pressures of 8, 6 and 5 MPa. At each stage CO2 was produced, implying that swelling of the gas phase and exsolution allowed the gas to reconnect and flow. After production, the gas reached a new position of equilibrium where it may be trapped again. At the end of the experiment, we imaged the sample again after 30 hours. Firstly, the results showed that an increase in saturation beyond the residual value was required to remobilize the gas, which is consistent with earlier field-scale results. Additionally, Ostwald ripening and continuing exsolution lead to a significant change in fluid saturation: transport of dissolved gas in the aqueous phase to equilibriate capillary pressure led to reconnection of the gas and its flow upwards under gravity. The implications for CO2 storage are discussed: an increase in saturation beyond the residual value is required to mobilize the gas, but Ostwald ripening can allow local reconnection of hitherto trapped gas, thus enhancing migration and may reduce the amount of CO2 that can be capillary trapped in storage operations.
Moghadasi R, Foroughi S, Basirat F, et al., 2023, Pore-scale determination of residual gas remobilization and critical saturation in geological CO2 storage: a pore-network modeling approach, Water Resources Research, Vol: 59, Pages: 1-16, ISSN: 0043-1397
Remobilization of residually trapped CO2 can occur under pressure depletion, caused by any sort of leakage, brine extraction for pressure maintenance purposes, or simply by near wellbore pressure dissipation once CO2 injection has ceased. This phenomenon affects the long-term stability of CO2 residual trapping and should therefore be considered for an accurate assessment of CO2 storage security. In this study, pore-network modeling is performed to understand the relevant physics of remobilization. Gas remobilization occurs at a higher gas saturation than the residual saturation, the so-called critical saturation; the difference is called the mobilization saturation, a parameter that is a function of the network properties and the mechanisms involved. Regardless of the network type and properties, Ostwald ripening tends to slightly increase the mobilization saturation, thereby enhancing the security of residual trapping. Moreover, significant hysteresis and reduction in gas relative permeability is observed, implying slow reconnection of the trapped gas clusters. These observations are safety enhancing features, due to which the remobilization of residual CO2 is delayed. The results, consistent with our previous analysis of the field-scale Heletz experiments, have important implications for underground gas and CO2 storage. In the context of CO2 storage, they provide important insights into the fate of residual trapping in both the short and long term.
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, Pages: 1-8, 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.
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, Pages: 1-21, 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, Physical Review E: Statistical, Nonlinear, and Soft Matter Physics, Vol: 107, ISSN: 1539-3755
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.
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.
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.
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.
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.
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.
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.
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.
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.
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
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.
Oliveira R, Bijeljic B, Blunt MJ, et al., 2021, A continuous time random walk approach to predict dissolution in porous media based on validation of experimental NMR data, Advances in Water Resources, Vol: 149, Pages: 1-16, ISSN: 0309-1708
We develop a reactive transport model for dissolution of porous materials using a Continuous Time Random Walk (CTRW) formulation with first-order kinetics. Our model is validated with a dataset for a Ketton carbonate rock sample undergoing dissolution on injection of an acid, monitored using Nuclear Magnetic Resonance (NMR). The experimental data includes the 3D porosity distribution at the beginning and end of the experiment, 1D porosity profiles along the direction of flow during dissolution, as well as the molecular fluid displacement probability distributions (propagators). With the calibration of only a single parameter, we successfully predict the porosity changes and the propagators as a signature of flow heterogeneity evolution in the dissolution experiment.We also demonstrate that heterogeneity in the flow field leads to an effective reaction rate, limited by transport of reactants, that is almost three orders of magnitude lower than measured under batch reaction conditions. The effective reaction rate predicted by the model is in good agreement with the experimentally measured rate. Furthermore, as dissolution proceeds, the formation of channels in the rock focused the flow in a few fast-flowing regions. The predicted dissolution patterns are similar to those observed experimentally. This study establishes a workflow to calibrate and validate the CTRW reactive transport model with NMR experiments.
Alhosani A, Lin Q, Scanziani A, et al., 2021, Pore-scale characterization of carbon dioxide storage at immiscible and near-miscible conditions in altered-wettability reservoir rocks, International Journal of Greenhouse Gas Control, Vol: 105, Pages: 1-15, ISSN: 1750-5836
Carbon dioxide storage combined with enhanced oil recovery (CCS-EOR) is an important approach for reducing greenhouse gas emissions. We use pore-scale imaging to help understand CO2 storage and oil recovery during CCS-EOR at immiscible and near-miscible CO2 injection conditions. We study in situ immiscible CO2 flooding in an oil-wet reservoir rock at elevated temperature and pressure using X-ray micro-tomography. We observe the predicted, but hitherto unreported, three-phase wettability order in strongly oil-wet rocks, where water occupies the largest pores, oil the smallest, while CO2 occupies pores of intermediate size. We investigate the pore occupancy, existence of CO2 layers, recovery and CO2 trapping in the oil-wet rock at immiscible conditions and compare to the results obtained on the same rock type under slightly more weakly oil-wet near-miscible conditions, with the same wettability order. CO2 spreads in connected layers at near-miscible conditions, while it exists as disconnected ganglia in medium-sized pores at immiscible conditions. Hence, capillary trapping of CO2 by oil occurs at immiscible but not at near-miscible conditions. Moreover, capillary trapping of CO2 by water is not possible in both cases since CO2 is more wetting to the rock than water. The oil recovery by CO2 injection alone is reduced at immiscible conditions compared to near-miscible conditions, where low gas-oil capillary pressure improves microscopic displacement efficiency. Based on these results, to maximize the amount of oil recovered and CO2 stored at immiscible conditions, a water-alternating-gas injection strategy is suggested, while a strategy of continuous CO2 injection is recommended at near-miscible conditions.
Blunt MJ, Alhosani A, Lin Q, et al., 2021, Determination of contact angles for three-phase flow in porous media using an energy balance, Journal of Colloid and Interface Science, Vol: 582, Pages: 283-290, ISSN: 0021-9797
HYPOTHESIS: We define contact angles, θ, during displacement of three fluid phases in a porous medium using energy balance, extending previous work on two-phase flow. We test if this theory can be applied to quantify the three contact angles and wettability order in pore-scale images of three-phase displacement. THEORY: For three phases labelled 1, 2 and 3, and solid, s, using conservation of energy ignoring viscous dissipation (Δa1scosθ12-Δa12-ϕκ12ΔS1)σ12=(Δa3scosθ23+Δa23-ϕκ23ΔS3)σ23+Δa13σ13, where ϕ is the porosity, σ is the interfacial tension, a is the specific interfacial area, S is the saturation, and κ is the fluid-fluid interfacial curvature. Δ represents the change during a displacement. The third contact angle, θ13 can be found using the Bartell-Osterhof relationship. The energy balance is also extended to an arbitrary number of phases. FINDINGS: X-ray imaging of porous media and the fluids within them, at pore-scale resolution, allows the difference terms in the energy balance equation to be measured. This enables wettability, the contact angles, to be determined for complex displacements, to characterize the behaviour, and for input into pore-scale models. Two synchrotron imaging datasets are used to illustrate the approach, comparing the flow of oil, water and gas in a water-wet and an altered-wettability limestone rock sample. We show that in the water-wet case, as expected, water (phase 1) is the most wetting phase, oil (phase 2) is intermediate wet, while gas (phase 3) is most non-wetting with effective contact angles of θ12≈48° and θ13≈44°, while θ23=0 since oil is always present in spreading layers. In contrast, for the altered-wettability case, oil is most wetting, gas is intermediate-wet, while water is most non-wetting with contact angles of θ12=134°±~10°,θ13=119°&p
Selem AM, Agenet N, Blunt MJ, et al., 2021, Pore-scale imaging of tertiary low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions
We investigated pore-scale oil displacement and rock wettability in tertiary low salinity waterflooding (LSW) in a heterogeneous carbonate sample using high-resolution three-dimensional imaging. This enabled the underlying mechanisms of the low salinity effect (LSE) to be observed and quantified in terms of changes in wettability and pore-scale fluid configuration, while also measuring the overall effect on recovery. The results were compared to the behavior under high salinity waterflooding (HSW). To achieve the wetting state found in oil reservoirs, an Estaillades limestone core sample was aged at 11 MPa and 80°C for threeweeks. The moderately oil-wet sample was then injected with high salinity brine (HSB) at a range of increasing flow rates, namely at 1, 2,4, 11, 22 and 42 µL/min with 10 pore volumes injected at each rate.Subsequently, low salinity brine (LSB) was injected following the same procedure. X-ray micro-computed tomography (micro-CT) was usedto visualize the fluid configuration in the pore space.A total of eight micro-CT images, with a resolution of 2.3 µm/voxel, wereacquired after both low salinity and high salinity floods.These high-resolution images were used to monitor fluid configuration in the porespace and obtain fluid saturations and occupancy maps. Wettabilitywascharacterized by measurements of in situ contactanglesand curvatures. The results show that the pore-scale mechanisms of improved recovery in LSW are consistent with the development of water micro-dropletswithin the oil and the expansion of thin water films between the oil and rock surface. Before waterflooding and during HSW, the measured contact angles were constant and above 110°, while the meancurvature and the capillary pressure values remained negative, suggesting that the HSB did not change the wettability state of the rock. However, with LSW the capillary pressure increased towards positive values as the wettability shifted towards a mixed-wet state. The flu
Blunt M, Kearney L, Alhosani A, et al., 2021, Wettability characterization from pore-scale images using topology and energy balance with implications for recovery and storage
We present two methods to measure contact angles inside porous media using high-resolution images. The direct determination of contact angle at the three-phase contact line is often ambiguous due to uncertainties with image segmentation. Instead, we propose two alternative approaches that provide an averaged assessment of wettability. The first uses fundamental principles in topology to relate the contact angle to the integral of the Gaussian curvature over the fluid-fluid meniscus. The advantage of this approach is that it replaces the uncertain determination of an angle at a point with a more accurate determination of an integral over a surface. However, in mixed-wet porous media, many interfaces are pinned with a hinging contact angle. For predictive pore-scale models, we need to determine the contact angle at which displacement occurs when the interfaces move. To address this problem we apply an energy balance, ignoring viscous dissipation, to estimate the contact angle from the meniscus curvature and changes in interfacial areas and saturation. We apply these methods to characterize wettability on pore-scale images of two- and three-phase flow. We also discuss the implications of the results for recovery and storage applications.
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