Imperial College London

DrTomBultreys

Faculty of EngineeringDepartment of Chemical Engineering

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t.bultreys

 
 
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Royal School of MinesSouth Kensington Campus

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Publications

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Year
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39 results found

Spurin C, Bultreys T, Rucker M, Garfi G, Schleputz CM, Novak V, Berg S, Blunt MJ, Krevor Set al., 2020, Real-Time Imaging Reveals Distinct Pore-Scale Dynamics During Transient and Equilibrium Subsurface Multiphase Flow, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397

Journal article

Heyndrickx M, Bultreys T, Goethals W, Van Hoorebeke L, Boone MNet al., 2020, Improving image quality in fast, time-resolved micro-CT by weighted back projection, SCIENTIFIC REPORTS, Vol: 10, ISSN: 2045-2322

Journal article

Mahmoodlu MG, Raoof A, Bultreys T, Van Stappen J, Cnudde Vet al., 2020, Large-scale pore network and continuum simulations of solute longitudinal dispersivity of a saturated sand column, ADVANCES IN WATER RESOURCES, Vol: 144, ISSN: 0309-1708

Journal article

Spurin C, Bultreys T, Ruecker M, Garfi G, Schlepütz CM, Novak V, Berg S, Blunt MJ, Krevor Set al., 2020, Real-time imaging reveals distinct pore scale dynamics during transient and equilibrium subsurface multiphase flow

Journal article

Mascini A, Cnudde V, Bultreys T, 2020, Event-based contact angle measurements inside porous media using time-resolved micro-computed tomography, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 572, Pages: 354-363, ISSN: 0021-9797

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

Zheng L, Rucker M, Bultreys T, Georgiadis A, Mooijer M, Bresme F, Trusler J, Muller Eet al., 2020, Surrogate models for studying the wettability of nanoscale natural rough surfaces using molecular dynamics, Energies, Vol: 13, ISSN: 1996-1073

A molecular modeling methodology is presented to analyze the wetting behavior of natural surfaces exhibiting roughness at the nanoscale. Using atomic force microscopy, the surface topology of a Ketton carbonate is measured with a nanometer resolution, and a mapped model is constructed with the aid of coarse-grained beads. A surrogate model is presented in which surfaces are represented by two-dimensional sinusoidal functions defined by both an amplitude and a wavelength. The wetting of the reconstructed surface by a fluid, obtained through equilibrium molecular dynamics simulations, is compared to that observed by the different realizations of the surrogate model. A least-squares fitting method is implemented to identify the apparent static contact angle, and the droplet curvature, relative to the effective plane of the solid surface. The apparent contact angle and curvature of the droplet are then used as wetting metrics. The nanoscale contact angle is seen to vary significantly with the surface roughness. In the particular case studied, a variation of over 65° is observed between the contact angle on a flat surface and on a highly spiked (Cassie–Baxter) limit. This work proposes a strategy for systematically studying the influence of nanoscale topography and, eventually, chemical heterogeneity on the wettability of surfaces.

Journal article

Ekanem EM, Berg S, De S, Fadili A, Bultreys T, Rucker M, Southwick J, Crawshaw J, Luckham PFet al., 2020, Signature of elastic turbulence of viscoelastic fluid flow in a single pore throat, Physical Review E: Statistical, Nonlinear, and Soft Matter Physics, Vol: 101, Pages: 042605 – 1-042605 – 14, ISSN: 1539-3755

When a viscoelastic fluid, such as an aqueous polymer solution, flows through a porous medium, the fluid undergoes a repetitive expansion and contraction as it passes from one pore to the next. Above a critical flow rate, the interaction between the viscoelastic nature of the polymer and the pore configuration results in spatial and temporal flow instabilities reminiscent of turbulentlike behavior, even though the Reynolds number Re≪1. To investigate whether this is caused by many repeated pore body–pore throat sequences, or simply a consequence of the converging (diverging) nature present in a single pore throat, we performed experiments using anionic hydrolyzed polyacrylamide (HPAM) in a microfluidic flow geometry representing a single pore throat. This allows the viscoelastic fluid to be characterized at increasing flow rates using microparticle image velocimetry in combination with pressure drop measurements. The key finding is that the effect, popularly known as “elastic turbulence,” occurs already in a single pore throat geometry. The critical Deborah number at which the transition in rheological flow behavior from pseudoplastic (shear thinning) to dilatant (shear thickening) strongly depends on the ionic strength, the type of cation in the anionic HPAM solution, and the nature of pore configuration. The transition towards the elastic turbulence regime was found to directly correlate with an increase in normal stresses. The topology parameter, Qf, computed from the velocity distribution, suggests that the “shear thickening” regime, where much of the elastic turbulence occurs in a single pore throat, is a consequence of viscoelastic normal stresses that cause a complex flow field. This flow field consists of extensional, shear, and rotational features around the constriction, as well as upstream and downstream of the constriction. Furthermore, this elastic turbulence regime, has high-pressure fluctuations, with a power-law decay ex

Journal article

Rücker M, Bartels W-B, Bultreys T, Boone M, Singh K, Garfi G, Scanziani A, Spurin C, Krevor S, Blunt MJ, Wilson O, Mahani H, Cnudde V, Luckham PF, Georgiadis A, Berg Set al., 2020, Workflow for upscaling wettability from the nano- to core-scales, International Symposium of the Society of Core Analysts

Conference paper

Rucker M, Bartels W-B, Garfi G, Shams M, Bultreys T, Boone M, Pieterse S, Maitland GC, Krevor S, Cnudde V, Mahani H, Berg S, Georgiadis A, Luckham PFet al., 2020, Relationship between wetting and capillary pressure in a crude oil/brine/rock system: From nano-scale to core-scale, Journal of Colloid and Interface Science, Vol: 562, Pages: 159-169, ISSN: 0021-9797

HypothesisThe wetting behaviour is a key property of a porous medium that controls hydraulic conductivity in multiphase flow. While many porous materials, such as hydrocarbon reservoir rocks, are initially wetted by the aqueous phase, surface active components within the non-wetting phase can alter the wetting state of the solid. Close to the saturation endpoints wetting phase fluid films of nanometre thickness impact the wetting alteration process. The properties of these films depend on the chemical characteristics of the system. Here we demonstrate that surface texture can be equally important and introduce a novel workflow to characterize the wetting state of a porous medium.ExperimentsWe investigated the formation of fluid films along a rock surface imaged with atomic force microscopy using ζ-potential measurements and a computational model for drainage. The results were compared to spontaneous imbibition test to link sub-pore-scale and core-scale wetting characteristics of the rock.FindingsThe results show a dependency between surface coverage by oil, which controls the wetting alteration, and the macroscopic wetting response. The surface-area coverage is dependent on the capillary pressure applied during primary drainage. Close to the saturation endpoint, where the change in saturation was minor, the oil-solid contact changed more than 80%.

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

Van Offenwert S, Cnudde V, Bultreys T, 2019, Pore-Scale Visualization and Quantification of Transient Solute Transport Using Fast Microcomputed Tomography, WATER RESOURCES RESEARCH, Vol: 55, Pages: 9279-9291, ISSN: 0043-1397

Journal article

Spurin C, Bultreys T, Bijeljic B, Blunt MJ, Krevor Set 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.

Journal article

Bultreys T, Singh K, Raeini A, Ruspini L, Øren P-E, Berg S, Rücker M, Bijeljic B, Blunt Met al., 2019, Verifying pore network models of imbibition in rocks using time-resolved synchrotron imaging

Working paper

Spurin C, Krevor S, Bultreys T, Blunt M, Bijeljic Bet al., 2019, Intermittent fluid connectivity during two-phase flow in a heterogeneous carbonate rock

Journal article

Spurin C, Bultreys T, Bijeljic B, Blunt MJ, Krevor Set 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.

Journal article

Bartels W, Rücker M, Boone M, Bultreys T, Mahani H, Berg S, Hassanizadeh SM, Cnudde Vet al., 2019, Imaging Spontaneous Imbibition in Full Darcy‐Scale Samples at Pore‐Scale Resolution by Fast X‐ray Tomography, Water Resources Research, ISSN: 0043-1397

Journal article

Scanziani A, Singh K, Bultreys T, Bijeljic B, Blunt MJet al., 2018, In situ characterization of immiscible three-phase flow at the pore scale for a water-wet carbonate rock, Advances in Water Resources, Vol: 121, Pages: 446-455, ISSN: 0309-1708

X-ray micro-tomography is used to image the pore-scale configurations of fluid in a rock saturated with three phases - brine, oil and gas - mimicking a subsurface reservoir, at high pressure and temperature. We determine pore occupancy during a displacement sequence that involves waterflooding, gas injection and water re-injection. In the water-wet sample considered, brine occupied the smallest pores, gas the biggest, while oil occupied pores of intermediate size and is displaced by both water and gas. Double displacement events have been observed, where gas displaces oil that displaces water or vice versa. The thickness of water and oil layers have been quantified, as have the contact angles between gas and oil, and oil and water. These results are used to explain the nature of trapping in three-phase flow, specifically how oil preferentially traps gas in the presence of water.

Journal article

Munawar MJ, Lin C, Cnudde V, Bultreys T, Dong C, Zhang X, De Boever W, Zahid MA, Wu Yet al., 2018, Petrographic characterization to build an accurate rock model using micro-CT: Case study on low-permeable to tight turbidite sandstone from Eocene Shahejie Formation, MICRON, Vol: 109, Pages: 22-33, ISSN: 0968-4328

Journal article

Bultreys T, Lin Q, Gao Y, Raeini AQ, AlRatrout A, Bijeljic B, Blunt MJet al., 2018, Validation of model predictions of pore-scale fluid distributions during two-phase flow, Physical Review E, Vol: 97, ISSN: 2470-0045

Pore-scale two-phase flow modeling is an important technology to study a rock's relative permeability behavior. To investigate if these models are predictive, the calculated pore-scale fluid distributions which determine the relative permeability need to be validated. In this work, we introduce a methodology to quantitatively compare models to experimental fluid distributions in flow experiments visualized with microcomputed tomography. First, we analyzed five repeated drainage-imbibition experiments on a single sample. In these experiments, the exact fluid distributions were not fully repeatable on a pore-by-pore basis, while the global properties of the fluid distribution were. Then two fractional flow experiments were used to validate a quasistatic pore network model. The model correctly predicted the fluid present in more than 75% of pores and throats in drainage and imbibition. To quantify what this means for the relevant global properties of the fluid distribution, we compare the main flow paths and the connectivity across the different pore sizes in the modeled and experimental fluid distributions. These essential topology characteristics matched well for drainage simulations, but not for imbibition. This suggests that the pore-filling rules in the network model we used need to be improved to make reliable predictions of imbibition. The presented analysis illustrates the potential of our methodology to systematically and robustly test two-phase flow models to aid in model development and calibration.

Journal article

Heyndrickx M, Boone M, De Schryver T, Bultreys T, Goethals W, Verstraete G, Vanhoorne V, Van Hoorebeke Let al., 2018, Piecewise linear fitting in dynamic micro-CT, MATERIALS CHARACTERIZATION, Vol: 139, Pages: 259-268, ISSN: 1044-5803

Journal article

Van Stappen JF, Meftah R, Boone MA, Bultreys T, De Kock T, Blykers BK, Senger K, Olaussen S, Cnudde Vet al., 2018, In Situ Triaxial Testing To Determine Fracture Permeability and Aperture Distribution for CO<sub>2</sub> Sequestration in Svalbard, Norway, ENVIRONMENTAL SCIENCE & TECHNOLOGY, Vol: 52, Pages: 4546-4554, ISSN: 0013-936X

Journal article

Scanziani A, Singh K, Bultreys T, Bijeljic B, Blunt MJet al., 2018, In situ pore-scale visualization of immiscible three-phase flow at high pressure and temperature

© 2018 Society of Petroleum Engineers. All rights reserved. We have used X-ray micro tomography techniques to obtain high quality three-dimensional images of the pore space of a water-wet Ketton carbonate sample and the fluids within it, after the injection of three phases (brine, oil and gas) in a sequence involving oil injection into a fully water-saturated pore space, waterflooding, gas injection and secondary waterflooding. The rock was imaged dry initially, and then again after each injection step, to obtain the saturation of the phases, oil recovery and gas trapping capacity. A maximum ball pore network extraction algorithm was applied on the dry images and used to obtain statistics of pore occupancy. The results are in line with the theories of a uniform water-wet system and with the published outcomes of pore-network simulators: the pore and throat centres of smallest and largest pores are respectively occupied by brine and gas, while the oil resides in the cavities with intermediate size. High resolution images were used to study double displacement and the nature of trapping; the thickness of oil layers were also measured from the images. The results can improve the predicitvity of three-phase flow simulators and improve the efficiency of CO2 storage and utilization.

Conference paper

Scanziani A, Singh K, Bultreys T, Bijeljic B, Blunt MJet al., 2018, In situ pore-scale visualization of immiscible three-phase flow at high pressure and temperature

© 2018 Society of Petroleum Engineers. All rights reserved. We have used X-ray micro tomography techniques to obtain high quality three-dimensional images of the pore space of a water-wet Ketton carbonate sample and the fluids within it, after the injection of three phases (brine, oil and gas) in a sequence involving oil injection into a fully water-saturated pore space, waterflooding, gas injection and secondary waterflooding. The rock was imaged dry initially, and then again after each injection step, to obtain the saturation of the phases, oil recovery and gas trapping capacity. A maximum ball pore network extraction algorithm was applied on the dry images and used to obtain statistics of pore occupancy. The results are in line with the theories of a uniform water-wet system and with the published outcomes of pore-network simulators: the pore and throat centres of smallest and largest pores are respectively occupied by brine and gas, while the oil resides in the cavities with intermediate size. High resolution images were used to study double displacement and the nature of trapping; the thickness of oil layers were also measured from the images. The results can improve the predicitvity of three-phase flow simulators and improve the efficiency of CO2 storage and utilization.

Conference paper

Scanziani A, Singh K, Bultreys T, Bijeljic B, Blunt MJet al., 2018, In situ pore-scale visualization of immiscible three-phase flow at high pressure and temperature

We have used X-ray micro tomography techniques to obtain high quality three-dimensional images of the pore space of a water-wet Ketton carbonate sample and the fluids within it, after the injection of three phases (brine, oil and gas) in a sequence involving oil injection into a fully water-saturated pore space, waterflooding, gas injection and secondary waterflooding. The rock was imaged dry initially, and then again after each injection step, to obtain the saturation of the phases, oil recovery and gas trapping capacity. A maximum ball pore network extraction algorithm was applied on the dry images and used to obtain statistics of pore occupancy. The results are in line with the theories of a uniform water-wet system and with the published outcomes of pore-network simulators: the pore and throat centres of smallest and largest pores are respectively occupied by brine and gas, while the oil resides in the cavities with intermediate size. High resolution images were used to study double displacement and the nature of trapping; the thickness of oil layers were also measured from the images. The results can improve the predicitvity of three-phase flow simulators and improve the efficiency of CO2 storage and utilization.

Conference paper

Rücker M, Bartels WB, Boone MA, Bultreys T, Mahani H, Berg Set al., 2017, Pore-scale processes in amott spontaneous imbibition tests

We observed the redistribution of the oil phase in the pore space of the rock in real-time in water-wet and mixed-wet (by ageing in crude oil) carbonate samples. During the imbibition of the water phase both, pore filling events with connection to the surrounding brine as well as snap-off events connected through water films only were detected. The distribution of the oil in different pore sizes as well as the different event types help to identify the wettability state of the system and understand how pore scale processes lead to the oil production at the larger scale.

Conference paper

Bultreys T, Van Stappen J, De Kock T, De Boever W, Boone MA, Van Hoorebeke L, Cnudde Vet al., 2016, Investigating the relative permeability behavior of microporosity-rich carbonates and tight sandstones with multiscale pore network models, JOURNAL OF GEOPHYSICAL RESEARCH-SOLID EARTH, Vol: 121, Pages: 7929-7945, ISSN: 2169-9313

Journal article

Bultreys T, Boone MA, Boone MN, De Schryver T, Masschaele B, Van Hoorebeke L, Cnudde Vet al., 2016, Fast laboratory-based micro-computed tomography for pore-scale research: Illustrative experiments and perspectives on the future, ADVANCES IN WATER RESOURCES, Vol: 95, Pages: 341-351, ISSN: 0309-1708

Journal article

Bultreys T, Van Hoorebeke L, Cnudde V, 2016, Simulating secondary waterflooding in heterogeneous rocks with variable wettability using an image-based, multiscale pore network model, WATER RESOURCES RESEARCH, Vol: 52, Pages: 6833-6850, ISSN: 0043-1397

Journal article

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