Publications
547 results found
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
- Author Web Link
- Cite
- 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.
Blunt MJ, 2021, Acknowledgement of Reviewers for 2020, Transport in Porous Media, Vol: 137, Pages: 283-286, ISSN: 0169-3913
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.
Haghi AH, Chalaturnyk R, Blunt MJ, et al., 2021, Poromechanical controls on spontaneous imbibition in earth materials, Scientific Reports, Vol: 11, ISSN: 2045-2322
Over the last century, the state of stress in the earth’s upper crust has undergone rapid changes because of human activities associated with fluid withdrawal and injection in subsurface formations. The stress dependency of multiphase flow mechanisms in earth materials is a substantial challenge to understand, quantify, and model for many applications in groundwater hydrology, applied geophysics, CO2 subsurface storage, and the wider geoenergy field (e.g., geothermal energy, hydrogen storage, hydrocarbon recovery). Here, we conduct core-scale experiments using N2/water phases to study primary drainage followed by spontaneous imbibition in a carbonate specimen under increasing isotropic effective stress and isothermal conditions. Using X-ray computed micro-tomography images of the unconfined specimen, we introduce a novel coupling approach to reconstruct pore-deformation and simulate multiphase flow inside the deformed pore-space followed by a semi-analytical calculation of spontaneous imbibition. We show that the irreducible water saturation increases while the normalized volume of spontaneously imbibed water into the specimen decreases (46–25%) in response to an increase in effective stress (0–30 MPa), leading to higher residual gas saturations. Furthermore, the imbibition rate decreases with effective stress, which is also predicted by a numerical model, due to a decrease in water relative permeability as the pore-space becomes more confined and tortuous. This fundamental study provides new insights into the physics of multiphase fluid transport, CO2 storage capacity, and recovery of subsurface resources incorporating the impact of poromechanics.
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.
Rezaeizadeh M, Hajiabadi SH, Aghaei H, et al., 2021, Pore-scale analysis of formation damage; A review of existing digital and analytical approaches, ADVANCES IN COLLOID AND INTERFACE SCIENCE, Vol: 288, ISSN: 0001-8686
- Author Web Link
- Cite
- Citations: 10
Purswani P, Johns RT, Karpyn ZT, et al., 2021, Predictive Modeling of Relative Permeability Using a Generalized Equation of State, Publisher: SOC PETROLEUM ENG, Pages: 191-205, ISSN: 1086-055X
- Author Web Link
- Cite
- Citations: 7
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
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.
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
Lin Q, Akai T, Blunt MJ, et al., 2021, Pore-scale imaging of asphaltene-induced pore clogging in carbonate rocks, Fuel, Vol: 283, ISSN: 0016-2361
We propose an experimental methodology to visualize asphaltene precipitation in the pore space of rocks and assess the reduction in permeability. We perform core flooding experiments integrated with X-ray microtomography (micro-CT). The simultaneous injection of pure heptane and crude oil containing asphaltene induces the precipitation of asphaltene in the pore space. The degree of precipitation is controlled by the measurement of differential pressure across the sample. After precipitation, doped heptane is injected to replace the fluid to enhance the contrast between precipitated asphaltene and doped heptane. The micro-CT images are segmented into three phases: void, precipitated asphaltene, and rock. In the experiment, we observed that the precipitated asphaltene which occupied 39.1% of the pore volume caused a 29-fold reduction in permeability. Furthermore, we analyze the spatial distribution of precipitated asphaltene which showed that the asphaltene tended to clog the larger pores. We also computed the flow field numerically on the images and obtained good agreement between simulated and measured permeability. The distribution of local velocity showed that after precipitation the flow was confined to narrow channels in the pore space. This method can be applied to any type of porous system with precipitation.
Karvounis P, Blunt MJ, 2021, Unconstrained Extraction of Fossil Fuels and Implication for Carbon Budgets under Climate Change Scenarios, Journal of Fluid Flow, Heat and Mass Transfer, Vol: 8, Pages: 72-79
Hubbert’s curve was first introduced to project future oil reserves and production in the US. In this paper, Hubbert’s logistic function was used to estimate future production of fossil fuels in different regions of the world. The aim is to adequately fit historical data with minimum error, calculate the projected CO2 emissions that emerge from the unconstrained extraction of coal, oil and natural gas, and hence to determine the consumption of the available carbon budget. For some of the world regions considered, Hubbert’s logistic function fits the data well, while others fail to fall under the bell-shaped curve due to factors not considered in the analysis, such as political decisions to restrict production. An overshoot of the carbon budget to limit global warming to 1.5oC is expected by 2050 in the case of unconstrained production of all fuels, with major contributors being Asia & Pacific regions for coal, the Middle East for oil, and North America for natural gas. In the case of a 2oC global warming scenario, the same major contributors again consume the available budget by 2040 except for natural gas production that stays below the threshold. This analysis emphasizes the importance of capturing and storing carbon dioxide emissions, and/or artificial limits on fossil fuel production to prevent dangerous climate change.
Selem A, Agenet N, Gao Y, et al., 2021, PORE-SCALE IMAGING OF CONTROLLED-SALINITY WATERFLOODING IN A HETEROGENEOUS CARBONATE ROCK AT RESERVOIR CONDITIONS, Pages: 2272-2276
Controlled salinity water-flooding (CSW) is a promising enhanced oil recovery technique, yet the pore-scale mechanisms that control the process remain poorly understood especially in carbonate rocks. The aim of this experimental study is, therefore, to gain novel insights into CSW and characterize oil, water and the pore space in carbonates. X-ray imaging combined with a high-pressure high-temperature flow apparatus was used to image and study in situ CSW in a complex carbonate rock. To establish the conditions found in oil reservoirs, the Estaillades limestone core sample (5.9 mm in diameter and 10 mm in length) was aged for three weeks at 11 MPa and 80°C. This weakly oil-wet sample was then flooded by injecting low salinity brine at a range of increasing flow rates. Tomographic images were acquired at 2.9-micron spatial resolution after each flow rate. A total of 60 pore volumes of low salinity brine were injected recovering 85% of the oil initially in place in macro-pores. Contact angles and brine-oil curvatures were obtained to characterize wettability changes within the rock pore space. Our analysis shows that wettability alteration towards a mixed wet system caused by low salinity brine was the main mechanism for increased oil recovery.
Gao Y, Raeini AQ, Blunt MJ, et al., 2021, Dynamic fluid configurations in steady-state two-phase flow in Bentheimer sandstone, Physical Review E, Vol: 103, ISSN: 2470-0045
Fast synchrotron tomography is used to study the impact of capillary number, Ca, on fluid configurations in steady-state two-phase flow in porous media. Brine and n-decane were co-injected at fixed fractional flow, fw=0.5, in a cylindrical Bentheimer sandstone sample for a range of capillary numbers 2.1×10−7≤Ca≤4.2×10−5, while monitoring the pressure differential. As we have demonstrated in Gao et al. [Phys. Rev. Fluids 5, 013801 (2020)], dependent on Ca, different flow regimes have been identified: at low Ca only fixed flow pathways exist, while after a certain threshold dynamic effects are observed resulting in intermittent fluctuations in fluid distribution which alter fluid connectivity. Additionally, the flow paths, for each capillary number, were imaged multiple times to quantify the less frequent changes in fluid occupancy, happening over timescales longer than the duration of our scans (40 s). In this paper we demonstrate how dynamic connectivity results from the interaction between oil ganglia populations. At low Ca connected pathways of ganglia are fixed with time-independent small, medium, and large ganglia populations. However, with an increase in Ca we see fluctuations in the size and numbers of the larger ganglia. With the onset of intermittency, fluctuations occur mainly in pores and throats of intermediate size. When Ca is further increased, we see rapid changes in occupancy in pores of all size. By combining observations on pressure fluctuations and flow regimes at various capillary numbers, we summarize a phase diagram over a range of capillary numbers for the wetting and nonwetting phases, Caw and Canw, respectively, to quantify the degree of intermittent flow. These different regimes are controlled by a competition between viscous forces on the flowing fluids and the capillary forces acting in the complex pore space. Furthermore, we plot the phase diagrams of the transition from Darcy flow to intermittent flow over a
Alhosani A, Scanziani A, Lin Q, et al., 2020, Three-phase flow displacement dynamics and Haines jumps in a hydrophobic porous medium, Proceedings of the Royal Society A: Mathematical, Physical and Engineering Sciences, Vol: 476, ISSN: 1364-5021
We use synchrotron X-ray micro-tomography to investigate the displacement dynamics during three-phase—oil, water and gas—flow in a hydrophobic porous medium. We observe a distinct gas invasion pattern, where gas progresses through the pore space in the form of disconnected clusters mediated by double and multiple displacement events. Gas advances in a process we name three-phase Haines jumps, during which gas re-arranges its configuration in the pore space, retracting from some regions to enable the rapid filling of multiple pores. The gas retraction leads to a permanent disconnection of gas ganglia, which do not reconnect as gas injection proceeds. We observe, in situ, the direct displacement of oil and water by gas as well as gas–oil–water double displacement. The use of local in situ measurements and an energy balance approach to determine fluid–fluid contact angles alongside the quantification of capillary pressures and pore occupancy indicate that the wettability order is oil–gas–water from most to least wetting. Furthermore, quantifying the evolution of Minkowski functionals implied well-connected oil and water, while the gas connectivity decreased as gas was broken up into discrete clusters during injection. This work can be used to design CO2 storage, improved oil recovery and microfluidic devices.
Spurin C, Bultreys T, Rucker M, et al., 2020, Real-Time Imaging Reveals Distinct Pore-Scale Dynamics During Transient and Equilibrium Subsurface Multiphase Flow, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
- Author Web Link
- Cite
- Citations: 18
Gao Y, Raeini AQ, Selem AM, et al., 2020, Pore-scale imaging with measurement of relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions, Advances in Water Resources, Vol: 146, Pages: 1-18, ISSN: 0309-1708
Using micro-CT imaging and differential pressure measurements, we design a comparative study in which we simultaneously measure relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions during steady-state waterflooding experiments. This allows us to isolate the impact of wettability on a pore-by-pore basis and its effect on the macroscopic parameters, capillary pressure and relative permeability, while keeping the pore-space geometry unchanged.First, oil and brine were injected through a water-wet reservoir sandstone sample at a fixed total flow rate, but in a sequence of increasing brine fractional flows with micro-CT scans of the fluid phases taken in each step. Then the sample was brought back to initial water saturation and the surface wettability of the sample was altered after prolonged contact with crude oil and the same measurement procedure was repeated on the altered-wettability sample which we call mixed-wet.Geometric contact angles were measured, which discriminated the water-wet and mixed-wet cases with average values of 75° and 89° respectively. Additionally, an energy balance was used to determine the effective contact angles for displacement which indicated that a higher advancing contact angle of 116° was needed to displace oil in the mixed-wet case. For the water-wet experiment the filling sequence was pore-size dependent, with a strong correlation between pore size and oil occupancy. However, in the mixed-wet experiment the principal determinant of the filling sequence was the wettability rather than the pore size, and there was no correlation between pore size and the residual oil occupancy.The oil-water interfacial area had a larger maximum in the mixed-wet case which was supported by the observation of sheet or saddle-like menisci shapes present throughout the sample volume that impede the flow. These shapes were quantified by much larger negative Gaussian curvature
Spurin C, Rücker M, Bultreys T, et al., 2020, The development of intermittent multiphase fluid flow pathways through a porous rock
Zhang Z, Wang T, Blunt MJ, et al., 2020, Advances in carbon capture, utilization and storage, APPLIED ENERGY, Vol: 278, ISSN: 0306-2619
- Author Web Link
- Cite
- Citations: 99
Akai T, Lin Q, Bijeljic B, et al., 2020, Using energy balance to determine pore-scale wettability, Journal of Colloid and Interface Science, Vol: 576, Pages: 486-495, ISSN: 0021-9797
HypothesisBased on energy balance during two-phase displacement in porous media, it has recently been shown that a thermodynamically consistent contact angle can be determined from micro-tomography images. However, the impact of viscous dissipation on the energy balance has not been fully understood. Furthermore, it is of great importance to determine the spatial distribution of wettability. We use direct numerical simulation to validate the determination of the thermodynamic contact angle both in an entire domain and on a pore-by-pore basis.SimulationsTwo-phase direct numerical simulations are performed on complex 3D porous media with three wettability states: uniformly water-wet, uniformly oil-wet, and non-uniform mixed-wet. Using the simulated fluid configurations, the thermodynamic contact angle is computed, then compared with the input contact angles.FindingsThe impact of viscous dissipation on the energy balance is quantified; it is insignificant for water flooding in water-wet and mixed-wet media, resulting in an accurate estimation of a representative contact angle for the entire domain even if viscous effects are ignored. An increasing trend in the computed thermodynamic contact angle during water injection is shown to be a manifestation of the displacement sequence. Furthermore, the spatial distribution of wettability can be represented by the thermodynamic contact angle computed on a pore-by-pore basis.
Blunt MJ, Akai T, Bijeljic B, 2020, Evaluation of methods using topology and integral geometry to assess wettability, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 576, Pages: 99-108, ISSN: 0021-9797
- Author Web Link
- Open Access Link
- Cite
- Citations: 10
Scanziani A, Alhosani A, Lin Q, et al., 2020, In situ characterization of three‐phase flow in mixed‐wet porous media using synchrotron imaging, Water Resources Research, Vol: 56, ISSN: 0043-1397
We use fast synchrotron X‐ray microtomography to understand three‐phase flow in mixed‐wet porous media to design either enhanced permeability or capillary trapping. The dynamics of these phenomena are of key importance in subsurface hydrology, carbon dioxide storage, oil recovery, food and drug manufacturing, and chemical reactors. We study the dynamics of a water‐gas‐water injection sequence in a mixed‐wet carbonate rock. During the initial waterflooding, water displaced oil from pores of all size, indicating a mixed‐wet system with local contact angles both above and below 90°. When gas was injected, gas displaced oil preferentially with negligible displacement of water. This behavior is explained in terms of the gas pressure needed for invasion. Overall, gas behaved as the most nonwetting phase with oil as the most wetting phase; however, pores of all size were occupied by oil, water, and gas, as a signature of mixed‐wet media. Thick oil wetting layers were observed, which increased oil connectivity and facilitated its flow during gas injection. A chase waterflooding resulted in additional oil flow, while gas was trapped by oil and water. Furthermore, we quantified the evolution of the surface areas and both Gaussian and the total curvature, from which capillary pressure could be estimated. These quantities are related to the Minkowski functionals which quantify the degree of connectivity and trapping. The combination of water and gas injection, under mixed‐wet immiscible conditions, leads to both favorable oil flow and significant trapping of gas, which is advantageous for storage applications.
Alhosani A, Scanziani A, Lin Q, et al., 2020, Dynamics of water injection in an oil-wet reservoir rock at subsurface conditions: Invasion patterns and pore-filling events, Physical Review E, Vol: 102, Pages: 023110 – 1-023110 – 15, ISSN: 2470-0045
We use fast synchrotron x-ray microtomography to investigate the pore-scale dynamics of water injection in an oil-wet carbonate reservoir rock at subsurface conditions. We measure, in situ, the geometric contact angles to confirm the oil-wet nature of the rock and define the displacement contact angles using an energy-balance-based approach. We observe that the displacement of oil by water is a drainagelike process, where water advances as a connected front displacing oil in the center of the pores, confining the oil to wetting layers. The displacement is an invasion percolation process, where throats, the restrictions between pores, fill in order of size, with the largest available throats filled first. In our heterogeneous carbonate rock, the displacement is predominantly size controlled; wettability has a smaller effect, due to the wide range of pore and throat sizes, as well as largely oil-wet surfaces. Wettability only has an impact early in the displacement, where the less oil-wet pores fill by water first. We observe drainage associated pore-filling dynamics including Haines jumps and snap-off events. Haines jumps occur on single- and/or multiple-pore levels accompanied by the rearrangement of water in the pore space to allow the rapid filling. Snap-off events are observed both locally and distally and the capillary pressure of the trapped water ganglia is shown to reach a new capillary equilibrium state. We measure the curvature of the oil-water interface. We find that the total curvature, the sum of the curvatures in orthogonal directions, is negative, giving a negative capillary pressure, consistent with oil-wet conditions, where displacement occurs as the water pressure exceeds that of the oil. However, the product of the principal curvatures, the Gaussian curvature, is generally negative, meaning that water bulges into oil in one direction, while oil bulges into water in the other. A negative Gaussian curvature provides a topological quantification of th
Scanziani A, Lin Q, Alhosani A, et al., 2020, Dynamics of fluid displacement in mixed-wet porous media, Proceedings of the Royal Society A: Mathematical, Physical and Engineering Sciences, Vol: 476, Pages: 1-16, ISSN: 1364-5021
We identify a distinct two-phase flow invasion pattern in a mixed-wet porous medium. Time-resolved high-resolution synchrotron X-ray imaging is used to study the invasion of water through a small rock sample filled with oil, characterized by a wide non-uniform distribution of local contact angles both above and below 90°. The water advances in a connected front, but throats are not invaded in decreasing order of size, as predicted by invasion percolation theory for uniformly hydrophobic systems. Instead, we observe pinning of the three-phase contact between the fluids and the solid, manifested as contact angle hysteresis, which prevents snap-off and interface retraction. In the absence of viscous dissipation, we use an energy balance to find an effective, thermodynamic, contact angle for displacement and show that this angle increases during the displacement. Displacement occurs when the local contact angles overcome the advancing contact angles at a pinned interface: it is wettability which controls the filling sequence. The product of the principal interfacial curvatures, the Gaussian curvature, is negative, implying well-connected phases which is consistent with pinning at the contact line while providing a topological explanation for the high displacement efficiencies in mixed-wet media.
Foroughi S, Bijeljic B, Lin Q, et al., 2020, Pore-by-pore modeling, analysis, and prediction of two-phase flow in mixed-wet rocks, Physical Review E: Statistical, Nonlinear, and Soft Matter Physics, Vol: 102, Pages: 023302 – 1-023302 – 15, ISSN: 1539-3755
A pore-network model is an upscaled representation of the pore space and fluid displacement, which is used to simulate two-phase flow through porous media. We use the results of pore-scale imaging experiments to calibrate and validate our simulations, and specifically to find the pore-scale distribution of wettability. We employ energy balance to estimate an average, thermodynamic, contact angle in the model, which is used as the initial estimate of contact angle. We then adjust the contact angle of each pore to match the observed fluid configurations in the experiment as a nonlinear inverse problem. The proposed algorithm is implemented on two sets of steady state micro-computed-tomography experiments for water-wet and mixed-wet Bentheimer sandstone. As a result of the optimization, the pore-by-pore error between the model and experiment is decreased to less than that observed between repeat experiments on the same rock sample. After calibration and matching, the model predictions for capillary pressure and relative permeability are in good agreement with the experiments. The proposed algorithm leads to a distribution of contact angle around the thermodynamic contact angle. We show that the contact angle is spatially correlated over around 4 pore lengths, while larger pores tend to be more oil-wet. Using randomly assigned distributions of contact angle in the model results in poor predictions of relative permeability and capillary pressure, particularly for the mixed-wet case.
Spurin C, Bultreys T, Ruecker M, et al., 2020, Real-time imaging reveals distinct pore scale dynamics during transient and equilibrium subsurface multiphase flow
Bultreys T, Singh K, Raeini AQ, et al., 2020, Verifying pore network models of imbibition in rocks using time‐resolved synchrotron imaging, Water Resources Research, Vol: 56, Pages: 1-13, ISSN: 0043-1397
At the pore scale, slow invasion of a wetting fluid in porous materials is often modeled with quasi‐static approximations which only consider capillary forces in the form of simple pore‐filling rules. The appropriateness of this approximation, often applied in pore network models, is contested in the literature, reflecting the difficulty of predicting imbibition relative permeability with these models. However, validation by sole comparison to continuum‐scale experiments is prone to induce model overfitting. It has therefore remained unclear whether difficulties generalizing the model performance are caused by errors in the predicted filling sequence or by subsequent calculations. Here, we address this by examining whether such a model can predict the pore‐scale fluid distributions underlying the behavior at the continuum scale. To this end, we compare the fluid arrangement evolution measured in fast synchrotron micro‐CT experiments on two rock types to quasi‐static simulations which implement capillary‐dominated pore filling and snap‐off, including a sophisticated model for cooperative pore filling. The results indicate that such pore network models can, in principle, predict fluid distributions accurately enough to estimate upscaled flow properties of strongly wetted rocks at low capillary numbers.
Alhosani A, Scanziani A, Lin Q, et al., 2020, Pore-scale mechanisms of CO2 storage in oilfields, Scientific Reports, Vol: 10, Pages: 1-9, ISSN: 2045-2322
Rapid implementation of global scale carbon capture and storage is required to limit temperature rises to 1.5 °C this century. Depleted oilfields provide an immediate option for storage, since injection infrastructure is in place and there is an economic benefit from enhanced oil recovery. To design secure storage, we need to understand how the fluids are configured in the microscopic pore spaces of the reservoir rock. We use high-resolution X-ray imaging to study the flow of oil, water and CO2 in an oil-wet rock at subsurface conditions of high temperature and pressure. We show that contrary to conventional understanding, CO2 does not reside in the largest pores, which would facilitate its escape, but instead occupies smaller pores or is present in layers in the corners of the pore space. The CO2 flow is restricted by a factor of ten, compared to if it occupied the larger pores. This shows that CO2 injection in oilfields provides secure storage with limited recycling of gas; the injection of large amounts of water to capillary trap the CO2 is unnecessary.
This data is extracted from the Web of Science and reproduced under a licence from Thomson Reuters. You may not copy or re-distribute this data in whole or in part without the written consent of the Science business of Thomson Reuters.