Imperial College London

DrBrankoBijeljic

Faculty of EngineeringDepartment of Earth Science & Engineering

Principal Research Fellow
 
 
 
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Contact

 

+44 (0)20 7594 6420b.bijeljic

 
 
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Location

 

2.53Royal School of MinesSouth Kensington Campus

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Summary

 

Publications

Publication Type
Year
to

159 results found

Lin Q, Bijeljic B, Raeini AQ, Rieke H, Blunt MJet al., 2021, Drainage capillary pressure distribution and fluid displacement in a heterogeneous laminated sandstone, Geophysical Research Letters, Vol: 48, Pages: 1-11, ISSN: 0094-8276

We applied three-dimensional X-ray microtomography to image a capillary drainage process (0–1,000 kPa) in a cm-scale heterogeneous laminated sandstone containing three distinct regions with different pore sizes to study the capillary pressure. We used differential imaging to distinguish solid, macropore, and five levels of subresolution pore phases associated with each region. The brine saturation distribution was computed based on average CT values. The nonwetting phase displaced the wetting phase in order of pore size and connectivity. The drainage capillary pressure in the highly heterogeneous rock was dependent on the capillary pressures in the individual regions as well as distance to the boundary between regions. The complex capillary pressure distribution has important implications for accurate water saturation estimation, gas and/or oil migration and the capillary rise of water in heterogeneous aquifers.

Journal article

Shams M, Singh K, Bijeljic B, Blunt MJet al., 2021, Direct numerical simulation of pore-scale trapping events during capillary-dominated two-phase flow in porous media, Transport in Porous Media, Vol: 138, Pages: 443-458, ISSN: 0169-3913

This study focuses on direct numerical simulation of imbibition, displacement of the non-wetting phase by the wetting phase, through water-wet carbonate rocks. We simulate multiphase flow in a limestone and compare our results with high-resolution synchrotron X-ray images of displacement previously published in the literature by Singh et al. (Sci Rep 7:5192, 2017). We use the results to interpret the observed displacement events that cannot be described using conventional metrics such as pore-to-throat aspect ratio. We show that the complex geometry of porous media can dictate a curvature balance that prevents snap-off from happening in spite of favourable large aspect ratios. We also show that pinned fluid-fluid-solid contact lines can lead to snap-off of small ganglia on pore walls; we propose that this pinning is caused by sub-resolution roughness on scales of less than a micron. Our numerical results show that even in water-wet porous media, we need to allow pinned contacts in place to reproduce experimental results.

Journal article

Lin Q, Bijeljic B, Foroughi S, Berg S, Blunt MJet al., 2021, Pore-scale imaging of displacement patterns in an altered-wettability carbonate, Chemical Engineering Science, Vol: 235, Pages: 1-12, ISSN: 0009-2509

High-resolution X-ray imaging combined with a steady-state flow experiment is used to demonstrate how pore-scale displacement affects macroscopic properties in an altered-wettability microporous carbonate, where porosity and fluid saturation can be directly obtained from the grey-scale micro-CT images. The resolvable macro pores are largely oil-wet with an average thermodynamic contact angle of 120°. The pore-by-pore analysis shows locally either oil or brine almost fully occupied the macro pores, with some oil displacement in the micro-porosity. We observed a typical oil-wet behaviour consistent with the contact angle measurement. The brine tended to occupy the larger macro pores, leading to a higher brine relative permeability, lower residual oil saturation, than under water-wet conditions and in a mixed-wet sandstone. The capillary pressure was negative and seven times larger in the carbonate than the sandstone, despite having a similar average pore size. These different displacement patterns are principally determined by the difference in wettability.

Journal article

Foroughi S, Bijeljic B, Blunt MJ, 2021, Pore-by-pore modelling, validation and prediction of waterflooding in oil-wet rocks using dynamic synchrotron data, Transport in Porous Media, Vol: 138, Pages: 285-308, ISSN: 0169-3913

We predict waterflood displacement on a pore-by-pore basis using pore network modelling. The pore structure is captured by a high-resolution image. We then use an energy balance applied to images of the displacement to assign an average contact angle, and then modify the local pore-scale contact angles in the model about this mean to match the observed displacement sequence. Two waterflooding experiments on oil-wet rocks are analysed where the displacement sequence was imaged using time-resolved synchrotron imaging. In both cases the capillary pressure in the model matches the experimentally obtained values derived from the measured interfacial curvature. We then predict relative permeability for the full saturation range. Using the optimised contact angles distributed randomly in space has little effect on the predicted capillary pressures and relative permeabilities, indicating that spatial correlation in wettability is not significant in these oil-wet samples. The calibrated model can be used to predict properties outside the range of conditions considered in the experiment.

Journal article

Alhosani A, Bijeljic B, Blunt MJ, 2021, Pore-scale imaging and analysis of wettability order, trapping and displacement in three-phase flow in porous media with various wettabilities, Transport in Porous Media, ISSN: 0169-3913

Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤ 1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas

Journal article

Zhang Y, Bijeljic B, Gao Y, Lin Q, Blunt MJet 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.

Journal article

Oliveira R, Bijeljic B, Blunt MJ, Colbourne A, Sederman AJ, Mantle MD, Gladden LFet 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.

Journal article

Alhosani A, Lin Q, Scanziani A, Andrews E, Zhang K, Bijeljic B, Blunt MJet 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.

Journal article

Blunt MJ, Alhosani A, Lin Q, Scanziani A, Bijeljic Bet 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

Journal article

Lin Q, Akai T, Blunt MJ, Bijeljic B, Iwama H, Takabayashi K, Onaka Y, Yonebayashi Het 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.

Journal article

Gao Y, Raeini AQ, Blunt MJ, Bijeljic Bet 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

Journal article

Alhosani A, Scanziani A, Lin Q, Selem A, Pan Z, Blunt MJ, Bijeljic Bet 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.

Journal article

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.

Journal article

Gao Y, Raeini AQ, Selem AM, Bondino I, Blunt MJ, Bijeljic Bet 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

Journal article

Akai T, Lin Q, Bijeljic B, Blunt MJet 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.

Journal article

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

Journal article

Scanziani A, Alhosani A, Lin Q, Spurin C, Garfi G, Blunt MJ, Bijeljic Bet 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.

Journal article

Alhosani A, Scanziani A, Lin Q, Foroughi S, Alhammadi AM, Blunt MJ, Bijeljic Bet 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

Journal article

Scanziani A, Lin Q, Alhosani A, Blunt MJ, Bijeljic Bet 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.

Journal article

Foroughi S, Bijeljic B, Lin Q, Raeini AQ, Blunt MJet 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.

Journal article

Bultreys T, Singh K, Raeini AQ, Ruspini LC, Øren P, Berg S, Rücker M, Bijeljic B, Blunt MJet 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.

Journal article

Alhosani A, Scanziani A, Lin Q, Raeini A, Bijeljic B, Blunt Met 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.

Journal article

Alhammadi AM, Gao Y, Akai T, Blunt MJ, Bijeljic Bet 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.

Journal article

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.

Journal article

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.

Conference paper

Scanziani A, Singh K, Menke H, Bijeljic B, Blunt MJet 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.

Journal article

Gao Y, Lin Q, Bijeljic B, Blunt MJet 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.

Journal article

Akai T, Alhammadi AM, Blunt MJ, Bijeljic Bet 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.

Journal article

Alhosani A, Scanziani A, Lin Q, Pan Z, Bijeljic B, Blunt MJet 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.

Journal article

Raeini AQ, Yang J, Bondino I, Bultreys T, Blunt MJ, Bijeljic Bet 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.

Journal article

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