542 results found
Goodarzi S, Zhang Y, Foroughi S, et al., 2024, Trapping, hysteresis and Ostwald ripening in hydrogen storage: A pore-scale imaging study, International Journal of Hydrogen Energy, Vol: 56, Pages: 1139-1151, ISSN: 0360-3199
Green hydrogen, produced from surplus electricity during peak production, can be injected into subsurface reservoirs and retrieved during high-demand periods. In this study, X-ray tomography was employed to examine hysteresis resulting from repeated hydrogen injection and withdrawal. An unsteady state experiment was performed to evaluate the distribution of hydrogen and brine after drainage and imbibition cycles: images of the pore-space configuration of fluids were taken immediately once injection had stopped and after waiting for a period of 16 h with no flow. A Bentheimer sandstone sample with a length of 60 mm and diameter of 12.8 mm was used, and hydrogen was injected at ambient temperature and a pore pressure of 1 MPa. The gas flow rate was decreased from 2 ml/min to 0.08 ml/min over three cycles of gas injection followed by water flooding, while the brine injection rate was kept constant. The results showed the presence of capillary pressure hysteresis and hydrogen migration through Ostwald ripening due to the diffusion of gas dissolved in the brine. These phenomena were characterized through analysis of interfacial curvature, area, connectivity and pore occupancy. The hydrogen tended to reside in the larger pore spaces, consistent with water-wet conditions. 16 h after flow had stopped, the hydrogen aggregated into larger ganglia with a single large connected ganglion dominating the volume. Moreover, the Euler characteristic decreased after 16 h, indicating an improvement in connectivity. The work implies that Ostwald ripening – mass transport of dissolved gas – leads to less hysteresis and better connectivity than would be assumed ignoring this effect, as done in assessments of hydrocarbon flow and trapping.
Siavashi J, Mahdaviara M, Shojaei MJ, et al., 2024, Segmentation of two-phase flow X-ray tomography images to determine contact angle using deep autoencoders, Energy, Vol: 288, ISSN: 0360-5442
This study improves the characterization of in situ contact angles in porous media by employing deep learning techniques (SegNet, UNet, ResNet, and UResNet) for multiphase segmentation of micro-CT images. The algorithms were tested on high-resolution X-ray images of a steady-state flow experiment where two fluid phases were simultaneously injected at different fractional flows. The models were trained to segment the images into solid, aqueous phase, and non-aqueous phase liquid (NAPL). The UResNet demonstrated the best performance with an f1-score of 0.966 for the test dataset. More importantly, the UResNet offered higher reliability than the watershed algorithm for various fractional flows based on visual inspection and phase distribution analysis. The porosity calculation error of the watershed method (7.8 %) was reduced to 5.1 % by UResNet. Furthermore, UResNet accurately depicted the consistently mixed-wet condition of the rock sample throughout the experiment, in contrast to the watershed segmentation that yielded inconsistencies in contact angle calculations at an aqueous phase fractional flow of 0.01.
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.
Selem AM, Agenet N, Foroughi S, et al., 2023, Pore-Scale Imaging of Emulsification of Oil during Tertiary and Secondary Low Salinity Waterflooding in a Reservoir Carbonate, Energy and Fuels, Vol: 37, Pages: 16368-16377, ISSN: 0887-0624
While it is known that changing the salinity of the brine used to displace oil in porous rock can lead to additional recovery, the mechanism by which this occurs at the pore scale is still not fully understood. We investigate whether the emulsification of oil is the process by which recovery is improved, removing oil from the solid surface and rendering the rock more water-wet. High-resolution three-dimensional X-ray imaging was used to visualize the emulsification kinetics during secondary and tertiary low salinity waterflooding in a carbonate reservoir rock. The rock samples were imaged during water flooding, where the salinity of the injected brine was much lower than that of the formation water. An intermediate phase that appeared to be a mixture of oil and brine, and which we hypothesize is an emulsion, was imaged in both tertiary and secondary low salinity waterflooding experiments. The formation of this intermediate phase is observed to be the preliminary step prior to oil mobilization. Gray-level histograms and pore occupancy maps showed a faster displacement of oil in the secondary mode compared to tertiary flooding where the emulsified oil remained in the sample for longer before displacement.
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.
Spurin C, Roberts GG, O'Malley CPB, et al., 2023, Pore-Scale Fluid Dynamics Resolved in Pressure Fluctuations at the Darcy Scale, GEOPHYSICAL RESEARCH LETTERS, Vol: 50, ISSN: 0094-8276
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.
Qu M-L, Blunt MJ, Fan X, et al., 2023, Pore-to-mesoscale network modeling of heat transfer and fluid flow in packed beds with application to process design, AICHE JOURNAL, ISSN: 0001-1541
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
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.
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, 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.
Mukherjee S, Johns RT, Foroughi S, et al., 2023, Fluid- Fluid Interfacial Area and Its Impact on Relative Permeability: A Pore Network Modeling Study, Publisher: SOC PETROLEUM ENG, Pages: 653-663, ISSN: 1086-055X
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.
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
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.
Aljaberi F, Alhosani A, Belhaj H, et al., 2023, Investigating Relationship Between Capillary Pressure, Phase Saturation, and Interfacial Area in a Three-Phase Flow Water-Wet System
Immiscible fluid displacement in porous media is encountered in many applications, including waterflooding in oil reservoirs, carbon capture and storage, groundwater remediation, and underground hydrogen storage. Displacement is controlled by capillary forces which is typically assumed to be a function of saturation (S), although the relationship is known to be hysteretic, in that the capillary pressure (Pc) is different for displacement where the saturation is increasing or decreasing for the same rock sample. A thermodynamically based theory predicts capillary pressure is a function of both saturation and specific fluid-fluid interfacial area (a). Recent advances in X-ray micro-computed tomography (micro-CT) allow for the saturation, capillary pressure, and the fluid-fluid interfacial area to be measured directly in situ on three-dimensional images of the rock sample and fluids. In this study, we investigated the relationship Pc-S-a in a steady-state experiment conducted on a water-wet Bentheimer sandstone. In our three-phase system water was the most wetting phase, oil was intermediate wet, and gas was the non-wetting phase. We examine the effect of introducing the gas to the water-oil fluid pair and the theory for water-oil and oil-gas fluid pairs. The main findings were as follows. (1) Introducing gas will push the oil to intermediate-sized pores while the oil also forms spreading layers, which results in no oil trapping; hence Pc-S hysteresis is not observed for the water-oil fluid pair compared to two-phase flow. Trapping has a significant effect on hysteresis. (2) The Pc-S-a relationship eliminated hysteresis and produced a unique three-dimensional surface, for both fluid pairs for steady-state conditions.
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
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.
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
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
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, PHYSICAL REVIEW E, Vol: 106, ISSN: 2470-0045
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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