Publications
183 results found
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.
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
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.
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.
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.
Oliveira TDS, Blunt M, Bijeljic B, 2020, Multispecies reactive transport in a microporous rock: impact of flow heterogeneity and reversibility of reaction, Water Resources Research, Vol: 56, ISSN: 0043-1397
We study the impact of pore space heterogeneity on mixing and reaction in porous media. We simulate the parallel injection of two streams of reactants at different pH in a three-dimensional microporous consolidated rock whose pore space was resolved by differential micro-CT imaging. As an exemplar of a heterogeneous medium, we consider the pore structure obtained from a Portland carbonate sample. We use direct numerical simulation to study the coupled impact of flow heterogeneity, characterized by a wide distribution of velocities, and chemical reversibility on multispecies reaction. The flow field is found from the Darcy-Brinkman equation while the advection-diffusion equation describes transport, which is coupled to a general multispecies geochemical solver for homogeneous reactions; precipitation and dissolution are ignored.We observe a highly non-uniform spatial distribution of concentration and rates of formation and consumption. For advection-dominated transport, the heterogeneous flow field leads to significant transverse mixing in macropores at early times, followed by a slower mixing driven by diffusion between macro- and micropore regions. The effective rates of formation and consumption are species-dependent and distinct in macro- and microporosity: while some species reach an asymptotic rate in well-mixed regions, others still show a transient non-monotonic behaviour as a consequence of incomplete mixing. Our findings have important implications for the understanding of time- and space-dependent reaction rate behaviour: the coupled impact of pore space heterogeneity and reversible reactions need to be taken into account as key determinants to describe multispecies reactive transport.
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
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.
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.
Alhammadi AM, Gao Y, Akai T, et al., 2020, Pore-scale X-ray imaging with measurement of relative permeability, capillary pressure and oil recovery in a mixed-wet micro-porous carbonate reservoir rock, Fuel, Vol: 268, Pages: 1-14, ISSN: 0016-2361
Differential imaging X-ray microtomography combined with a steady-state flow apparatus was used to elucidate the displacement processes during waterflooding. We simultaneously measured relative permeability and capillary pressure on a carbonate rock sample extracted from a giant producing oil field. We used the pore-scale images of crude oil and brine to measure the interfacial curvature from which the local capillary pressure was calculated; the relative permeability was found from the imposed fractional flow, the image-measured saturation, and the pressure differential across the sample.The relative permeabilities indicated favourable oil recovery for the mixed-wettability conditions. The pore-scale images showed that brine started to flow through pinned wetting layers, micro-porosity and water-wet pores, and then filled the centre of the larger oil-wet pores. Oil was drained to low saturation through connected oil layers. The brine relative permeability remained low until brine invaded a connected pathway of smaller throats at a high brine saturation. The interface between the oil and brine had a small average curvature, indicating a low capillary pressure, but we observed remarkable saddle-shaped interfaces with nearly equal but opposite curvatures in orthogonal directions. This implies good oil phase connectivity, consistent with the favourable recovery and low residual oil saturation attained in the experiments.This work illuminated displacement processes from both macro-pores and micro-pores which have important implications for improved oil recovery and, potentially, on carbon storage. In future, the measured relative permeability, capillary pressure and pore-scale fluid distribution could be used to benchmark and validate pore-scale models.
Akai T, Blunt MJ, Bijeljic B, 2020, Pore-scale numerical simulation of low salinity water flooding using the lattice Boltzmann method, Journal of Colloid and Interface Science, Vol: 566, Pages: 444-453, ISSN: 0021-9797
HYPOTHESIS: The change of wettability toward more water-wet by the injection of low salinity water can improve oil recovery from porous rocks, which is known as low salinity water flooding. To simulate this process at the pore-scale, we propose that the alteration in surface wettability mediated by thin water films which are below the resolution of simulation grid blocks has to be considered, as observed in experiments. This is modeled by a wettability alteration model based on rate-limited adsorption of ions onto the rock surface. SIMULATIONS: The wettability alteration model is developed and incorporated into a lattice Boltzmann simulator which solves both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport. The model is validated against two experiments in the literature, then applied to 3D micro-CT images of a rock. FINDINGS: Our model correctly simulated the experimental observations caused by the slow wettability alteration driven by the development of water films. In the simulations on the 3D rock pore structure, a distinct difference in the mixing of high and low salinity water is observed between secondary and tertiary low salinity flooding, resulting in different oil recoveries.
Akai T, Bijeljic B, Blunt M, 2020, Local Capillary Pressure Estimation Based on Curvature of the Fluid Interface-Validation with Two-Phase Direct Numerical Simulations, ISSN: 2555-0403
With the advancement of high-resolution three-dimensional X-ray imaging, it is now possible to directly calculate the curvature of the interface of two phases extracted from segmented CT images during two-phase flow experiments to derive capillary pressure. However, there is an inherent difficulty of this image-based curvature measurement: The use of voxelized image data for the calculation of curvature can cause significant errors. To address this, we first perform two-phase direct numerical simulations to obtain the oil and water phase distribution, the exact location of the interface, and local fluid pressure. We then investigate a method to compute curvature on the oil/water interface. The interface is defined in two ways. In one case the simulated interface which has a sub-resolution smoothness is used, while the other is a smoothed interface which is extracted from synthetic segmented data based on the simulated phase distribution. Computed mean curvature on these surfaces are compared with that obtained from the fluid pressure computed directly in the simulation. We discuss the accuracy of image-based curvature measurements for the calculation of capillary pressure and propose the best way to extract an accurate curvature measurement, quantifying the likely uncertainties.
Scanziani A, Singh K, Menke H, et al., 2020, Dynamics of enhanced gas trapping applied to CO2 storage in the presence of oil using synchrotron X-ray micro tomography, Applied Energy, Vol: 259, ISSN: 0306-2619
During CO2 storage in depleted oil fields, under immiscible conditions, CO2 can be trapped in the pore space by capillary forces, providing safe storage over geological times - a phenomenon named capillary trapping. Synchrotron X-ray imaging was used to obtain dynamic three-dimensional images of the flow of the three phases involved in this process - brine, oil and gas (nitrogen) - at high pressure and temperature, inside the pore space of Ketton limestone. First, using continuous imaging of the porous medium during gas injection, performed after waterflooding, we observed chains of multiple displacements between the three phases, caused by the connectivity of the pore space. Then, brine was re-injected and double capillary trapping - gas trapping by oil and oil trapping by brine - was the dominant double displacement event. We computed pore occupancy, saturations, interfacial area, mean curvature and Euler characteristic to elucidate these double capillary trapping phenomena, which lead to a high residual gas saturation. Pore occupancy and saturation results show an enhancement of gas trapping in the presence of both oil and brine, which potentially makes CO2 storage in depleted oil reservoirs attractive, combining safe storage with enhanced oil recovery through immiscible gas injection. Mean curvature measurements were used to assess the capillary pressures between fluid pairs during double displacements and these confirmed the stability of the spreading oil layers observed, which facilitated double capillary trapping. Interfacial area and Euler characteristic increased, indicating lower oil and gas connectivity, due to the capillary trapping events.
Gao Y, Lin Q, Bijeljic B, et al., 2020, Pore-scale dynamics and the multiphase Darcy law, Physical Review Fluids, Vol: 5, Pages: 1-12, ISSN: 2469-990X
Synchrotron x-ray microtomography combined with sensitive pressure differential measurements were used to study flow during steady-state injection of equal volume fractions of two immiscible fluids of similar viscosity through a 57-mm-long porous sandstone sample for a wide range of flow rates. We found three flow regimes. (1) At low capillary numbers, Ca, representing the balance of viscous to capillary forces, the pressure gradient, ∇P, across the sample was stable and proportional to the flow rate (total Darcy flux) qt (and hence capillary number), confirming the traditional conceptual picture of fixed multiphase flow pathways in porous media. (2) Beyond Ca∗≈10−6, pressure fluctuations were observed, while retaining a linear dependence between flow rate and pressure gradient for the same fractional flow. (3) Above a critical value Ca>Cai≈10−5 we observed a power-law dependence with ∇P∼qat with a≈0.6 associated with rapid fluctuations of the pressure differential of a magnitude equal to the capillary pressure. At the pore scale a transient or intermittent occupancy of portions of the pore space was captured, where locally flow paths were opened to increase the conductivity of the phases. We quantify the amount of this intermittent flow and identify the onset of rapid pore-space rearrangements as the point when the Darcy law becomes nonlinear. We suggest an empirical form of the multiphase Darcy law applicable for all flow rates, consistent with the experimental results.
Akai T, Alhammadi AM, Blunt MJ, et al., 2019, Mechanisms of microscopic displacement during enhanced oil recovery in mixed-wet rocks revealed using direct numerical simulation, Transport in Porous Media, Vol: 130, Pages: 731-749, ISSN: 0169-3913
We demonstrate how to use numerical simulation models directly on micro-CT images to understand the impact of several enhanced oil recovery (EOR) methods on microscopic displacement efficiency. To describe the physics with high-fidelity, we calibrate the model to match a water-flooding experiment conducted on the same rock sample (Akai et al. in Transp Porous Media 127(2):393–414, 2019. https://doi.org/10.1007/s11242-018-1198-8). First we show comparisons of water-flooding processes between the experiment and simulation, focusing on the characteristics of remaining oil after water-flooding in a mixed-wet state. In both the experiment and simulation, oil is mainly present as thin oil layers confined to pore walls. Then, taking this calibrated simulation model as a base case, we examine the application of three EOR processes: low salinity water-flooding, surfactant flooding and polymer flooding. In low salinity water-flooding, the increase in oil recovery was caused by displacement of oil from the centers of pores without leaving oil layers behind. Surfactant flooding gave the best improvement in the recovery factor of 16% by reducing the amount of oil trapped by capillary forces. Polymer flooding indicated improvement in microscopic sweep efficiency at a higher capillary number, while it did not show an improvement at a low capillary number. Overall, this work quantifies the impact of different EOR processes on local displacement efficiency and establishes a workflow based on combining experiment and modeling to design optimal recovery processes.
Alhosani A, Scanziani A, Lin Q, et al., 2019, In situ pore-scale analysis of oil recovery during three-phase near-miscible CO2 injection in a water-wet carbonate rock, Advances in Water Resources, Vol: 134, ISSN: 0309-1708
We study in situ three-phase near-miscible CO2 injection in a water-wet carbonate rock at elevated temperature and pressure using X-ray microtomography. We examine the recovery mechanisms, presence or absence of oil layers, pore occupancy and interfacial areas during a secondary gas injection process. In contrast to an equivalent immiscible system, we did not observe layers of oil sandwiched between gas in the centre of the pore space and water in the corners. At near-miscible conditions, the measured contact angle between oil and gas was approximately 73°, indicating only weak oil wettability in the presence of gas. Oil flows in the centres of large pores, rather than in layers for immiscible injection, when displaced by gas. This allows for a rapid production of oil since it is no longer confined to movement in thin layers. A significant recovery factor of 80% was obtained and the residual oil saturation existed as disconnected blobs in the corners of the pore space. At equilibrium, gas occupied the biggest pores, while oil and water occupied pores of varying sizes (small, medium and large). Again, this was different from an immiscible system, where water occupied only the smallest pores. We suggest that a double displacement mechanism, where gas displaces water that displaces oil is responsible for shuffling water into larger pores than that seen after initial oil injection. This is only possible since, in the absence of oil layers, gas can contact water directly. The gas-oil and oil-water interfacial areas are lower than in the immiscible case, since there are no oil layers and even water layers in the macro-pore space become disconnected; in contrast, there is a larger direct contact of oil to the solid. These results could serve as benchmarks for developing near-miscible pore-scale modelling tools.
Raeini AQ, Yang J, Bondino I, et al., 2019, Validating the generalized pore network model using micro-CT images of two-phase flow, Transport in Porous Media, Vol: 130, Pages: 405-424, ISSN: 0169-3913
A reliable prediction of two-phase flow through porous media requires the development and validation of models for flow across multiple length scales. The generalized network model is a step towards efficient and accurate upscaling of flow from the pore to the core scale. This paper presents a validation of the generalized network model using micro-CT images of two-phase flow experiments on a pore-by-pore basis. Three experimental secondary imbibition datasets are studied for both sandstone and carbonate rock samples. We first present a quantification of uncertainties in the experimental measurements. Then, we show that the model can reproduce the experimental fluid occupancies and saturations with a good accuracy, which in some cases is comparable with the similarity between repeat experiments. However, high-resolution images need to be acquired to characterize the pore geometry for modelling, while the results are sensitive to the initial condition at the end of primary drainage. The results provide a methodology for improving our physical models using large experimental datasets which, at the pore scale, can be generated using micro-CT imaging of multiphase flow.
Spurin C, Bultreys T, Bijeljic B, et al., 2019, Mechanisms controlling fluid breakup and reconnection during two-phase flow in porous media, Physical Review E, Vol: 100, ISSN: 2470-0045
The use of Darcy's law to describe steady-state multiphase flow in porous media has been justified by the assumption that the fluids flow in continuously connected pathways. However, a range of complex interface dynamics have been observed during macroscopically steady-state flow, including intermittent pathway flow where flow pathways periodically disconnect and reconnect. The physical mechanisms controlling this behavior have remained unclear, leading to uncertainty concerning the occurrence of the different flow regimes. We observe that the fraction of intermittent flow pathways is dependent on the capillary number and viscosity ratio. We propose a phase diagram within this parameter space to quantify the degree of intermittent flow.
Spurin C, Bultreys T, Bijeljic B, et al., 2019, Intermittent fluid connectivity during two-phase flow in a heterogeneous carbonate rock, Physical Review E, Vol: 100, ISSN: 2470-0045
Subsurface fluid flow is ubiquitous in nature, and understanding the interaction of multiple fluids as they flow within a porous medium is central to many geological, environmental, and industrial processes. It is assumed that the flow pathways of each phase are invariant when modeling subsurface flow using Darcy's law extended to multiphase flow, a condition that is assumed to be valid during steady-state flow. However, it has been observed that intermittent flow pathways exist at steady state even at the low capillary numbers typically encountered in the subsurface. Little is known about the pore structure controls or the impact of intermittency on continuum scale flow properties. Here we investigate the impact of intermittent pathways on the connectivity of the fluids for a carbonate rock. Using laboratory-based micro computed tomography imaging we observe that intermittent pathway flow occurs in intermediate-sized pores due to the competition between both flowing fluids. This competition moves to smaller pores when the flow rate of the nonwetting phase increases. Intermittency occurs in poorly connected pores or in regions where the nonwetting phase itself is poorly connected. Intermittent pathways lead to the interrupted transport of the fluids; this means they are important in determining continuum scale flow properties, such as relative permeability. The impact of intermittency on flow properties is significant because it occurs at key locations, whereby the nonwetting phase is otherwise disconnected.
Blunt MJ, Lin Q, Akai T, et al., 2019, A thermodynamically consistent characterization of wettability in porous media using high-resolution imaging, Journal of Colloid and Interface Science, Vol: 552, Pages: 59-65, ISSN: 0021-9797
Conservation of energy is used to derive a thermodynamically-consistent contact angle, θt, when fluid phase 1 displaces phase 2 in a porous medium. Assuming no change in Helmholtz free energy between two local equilibrium states we find that Δa1scosθt=κϕΔS1+Δa12, where a is the interfacial area per unit volume, ϕ is the porosity, S is the saturation and κ the curvature of the fluid-fluid interface. The subscript s denotes the solid, and we consider changes, Δ, in saturation and area. With the advent of high-resolution time-resolved three-dimensional X-ray imaging, all the terms in this expression can be measured directly. We analyse imaging datasets for displacement of oil by water in a water-wet and a mixed-wet sandstone. For the water-wet sample, the curvature is positive and oil bulges into the brine with almost spherical interfaces. In the mixed-wet case, larger interfacial areas are found, as the oil resides in layers. The mean curvature is close to zero, but the interface tends to bulge into brine in one direction, while brine bulges into oil in the other. We compare θt with the values measured geometrically in situ on the pore-scale images, θg. The thermodynamic angle θt provides a robust and consistent characterization of wettability. For the water-wet case the calculated value of θt gives an accurate prediction of multiphase flow properties using pore-scale modelling.
Akai T, Lin Q, Alhosani A, et al., 2019, Quantification of uncertainty and best practice in computing interfacial curvature from complex pore space images., Materials (Basel), Vol: 12, Pages: 1-21, ISSN: 1996-1944
Recent advances in high-resolution three-dimensional X-ray CT imaging have made it possible to visualize fluid configurations during multiphase displacement at the pore-scale. However, there is an inherited difficulty in image-based curvature measurements: the use of voxelized image data may introduce significant error, which has not-to date-been quantified. To find the best method to compute curvature from micro-CT images and quantify the likely error, we performed drainage and imbibition direct numerical simulations for an oil/water system on a bead pack and a Bentheimer sandstone. From the simulations, local fluid configurations and fluid pressures were obtained. We then investigated methods to compute curvature on the oil/water interface. The interface was defined in two ways; in one case the simulated interface with a sub-resolution smoothness was used, while the other was a smoothed interface extracted from synthetic segmented data based on the simulated phase distribution. The curvature computed on these surfaces was compared with that obtained from the simulated capillary pressure, which does not depend on the explicit consideration of the shape of the interface. As distinguished from previous studies which compared an average or peak curvature with the value derived from the measured macroscopic capillary pressure, our approach can also be used to study the pore-by-pore variation. This paper suggests the best method to compute curvature on images with a quantification of likely errors: local capillary pressures for each pore can be estimated to within 30% if the average radius of curvature is more than 6 times the image resolution, while the average capillary pressure can also be estimated to within 11% if the average radius of curvature is more than 10 times the image resolution.
Gao Y, Qaseminejad Raeini A, Blunt MJ, et al., 2019, Pore occupancy, relative permeability and flow intermittency measurements using X-ray micro-tomography in a complex carbonate, Advances in Water Resources, Vol: 129, Pages: 56-69, ISSN: 0309-1708
We imaged the steady-state flow of brine and decane (oil) at different fractional flows during dual injection in a micro-porous limestone, Estaillades, using X-ray micro-tomography. We applied differential imaging to: (a) distinguish micro-porous regions from macro-pores, and (b) determine fluid pore occupancy in both regions, and relative permeability at a capillary number, Ca = 7.3 × 10 −6 . The sample porosity was approximately 28%, with 7% in macro-pores and 21% in pores that could not be directly resolved (micro-porosity). Fluid occupancy in micro-porosity was classified into three sub-phases: micro-pore space with oil, micro-pore space with brine, and micro-pores partially filled with oil and brine. Our method indicated an initially higher oil recovery from micro-porosity, consistent with waterflooding in a water-wet rock. The fractional flow and relative permeabilities of the two fluids were obtained from measurements of the pressure differential across the sample and the saturation calculated from the images. The brine saturation and relative permeabilities are impacted by the presence of water-wet micro-porosity which provides additional connectivity to the phases. Furthermore, we find that in addition to brine and decane, a fraction of the macroscopic pore space contains an intermittent phase, which is occupied either by brine or decane during the hour-long scan time. Pore and throat occupancy of oil, brine and intermittent phase were obtained from images at different fractional flows using the generalized pore network extracted from the image of macro-pores. The intermittent phase, where the occupancy fluctuated between oil-filled and brine-filled, was predominantly located in the small and intermediate size pores and throats. Overall, we establish a new experimental methodology to: (i) quantify initial and recovered oil in micro-pores, (ii) characterise intermittent flow, and (iii) measure steady-state relative permeability in carbonates, whi
Lin Q, Bijeljic B, Berg S, et al., 2019, Minimal surfaces in porous media: Pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone, Physical Review E, Vol: 99, Pages: 063105-1-063105-13, ISSN: 1539-3755
High-resolution x-ray imaging was used in combination with differential pressure measurements to measurerelative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on asample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil toalter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flowrate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, x-raytomographic images were taken. The images were used to compute saturation, interfacial area, curvature, andcontact angle. From this information relative permeability and capillary pressure were determined as functionsof saturation. We compare our results with a previously published experiment under water-wet conditions. Theoil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, ofapproximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock.The capillary pressure was slightly negative and 10 times smaller in magnitude than for the water-wet rock,and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area wasalso largely constant in this saturation range. The measured static contact angles had an average of 80◦ with astandard deviation of 17◦. We observed that the oil-brine interfaces were not flat, as may be expected for a verylow mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. Theseinterfaces were approximately minimal surfaces, which implies well-connected phases. Saddle-shaped menisciswept through the pore space at a constant capillary pressure and with an almost fixed area, removing most ofthe oil.
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.