Publications
154 results found
Unsal E, Berg S, Ruecker M, 2020, What happens in porous media during oil-phase emulsification?, Shell TechXplorer Digest, Vol: 2020
<jats:p>Shell scientists are making the most of advancing imaging technology to reveal what happens in a 3D porous medium during emulsification.</jats:p>
Spurin C, Bultreys T, Rucker M, et al., 2020, Real-Time Imaging Reveals Distinct Pore-Scale Dynamics During Transient and Equilibrium Subsurface Multiphase Flow, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
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- Citations: 18
Spurin C, Rücker M, Bultreys T, et al., 2020, The development of intermittent multiphase fluid flow pathways through a porous rock
Sun C, McClure JE, Mostaghimi P, et al., 2020, Characterization of wetting using topological principles, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 578, Pages: 106-115, ISSN: 0021-9797
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- Citations: 30
Yesufu-Rufai S, Rucker M, Berg S, et al., 2020, Assessing the wetting state of minerals in complex sandstone rock in-situ by Atomic Force Microscopy (AFM), Fuel, Vol: 273, Pages: 1-11, ISSN: 0016-2361
Low salinity waterflooding is a low-cost method of enhancing oil recovery although, no consistent concept has been established explaining why some oil-fields show an increase in oil production when the salinity of the injected brine is reduced, while others do not. Various studies were conducted investigating the underlying mechanisms of the ‘low salinity effect’ using different crude oil, brine and rock compositions. Core floods of sandstone rock and analyses of molecular interactions using model systems indicate that clay content may play a dominant role. However, the spatial configuration of the sheet-like clay particles, which may vary from rock to rock, complicate comparisons of these model scenarios with reality.In the present study, we report the development of a pre-screening method using Atomic Force Microscopy (AFM) to assess rock-fluid interactions, which has previously only been used either on artificial model systems or minerals from crushed rock, by exploring the capability to operate in-situ in complex rock without crushing. The orientation of clay particles within a pore of an outcrop sandstone, Bandera Brown, was investigated with AFM and these particles were further assessed for changes in adhesion in brines of differing salinity. The results show a decrease in adhesions between CH3-functionalised AFM tips and the rock surface in low salinity brine, predominantly at the clay edges. This demonstrates that the edges of the clay particles, which may pin the oil phase after wettability alteration and therewith prevent oil from getting produced, lose this capacity when exposed to low salinity brine.
Spurin C, Bultreys T, Ruecker M, et al., 2020, Real-time imaging reveals distinct pore scale dynamics during transient and equilibrium subsurface multiphase flow
Xiong R, Zhang Y, Zhou W, et al., 2020, Chemical activation of carbon materials for supercapacitors: Elucidating the effect of spatial characteristics of the precursors, COLLOIDS AND SURFACES A-PHYSICOCHEMICAL AND ENGINEERING ASPECTS, Vol: 597, ISSN: 0927-7757
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- Citations: 2
Yesufu-Rufai S, Marcelis F, Georgiadis A, et al., 2020, Atomic Force Microscopy (AFM) study of redox conditions in sandstones: Impact on wettability modification and mineral morphology, Colloids and Surfaces A: Physicochemical and Engineering Aspects, Vol: 597, Pages: 1-10, ISSN: 0927-7757
Laboratory core flood experiments performed to establish chemical enhanced oil recovery (cEOR) procedures often make use of rock samples that deviate from prevailing conditions within the reservoir. These samples have usually been preserved in an uncontrolled oxidising environment in contrast to reducing reservoir conditions, a discrepancy that affects rock wettability and thus oil recovery. The use of a reducing fluid is a predominant method, particularly regarding iron-bearing minerals, for restoring these samples to representative redox states.In this study, the adhesion of polar (NH2 and COOH) and non-polar (CH3) crude oil components to the pore surfaces of Bandera Brown, an outcrop of similar mineralogy to reservoir sandstones, was investigated using Atomic Force Microscopy to determine the potential of a reducing fluid of Sodium Dithionite in seawater to alter surface wettability. This novel workflow for the observation of redox condition effects illuminates the nanoscopic interaction forces at the rock/fluid interface responsible this phenomenon.The results obtained show that adhesion forces between the oil components and the Bandera Brown surface after treatment with the reducing fluid decreased in the order: NH2 (∼70 %) >COOH (∼36 %) >CH3 (∼3 %), due to diminishing affinity of the surface for the polar functional groups when the oxidation state of iron was altered from iron III to iron II. The morphology of Bandera Brown is noted to be affected as well with some dissolution of the mineral composition within cemented pores observed.The results demonstrate that redox state is indeed important for the assessment of wetting properties of surfaces as measurements performed in oxidising environments may not be representative of reservoir reducing conditions. Also, complete reduction of iron oxides on the mineral surfaces seems unlikely without altering the prevailing pore structure. These findings have relevance not only in EOR cases but can fin
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.
McClure JE, Ramstad T, Li Z, et al., 2020, Modeling Geometric State for Fluids in Porous Media: Evolution of the Euler Characteristic, TRANSPORT IN POROUS MEDIA, Vol: 133, Pages: 229-250, ISSN: 0169-3913
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- Citations: 26
Garfi G, John CM, Lin Q, et al., 2020, Fluid Surface Coverage Showing the Controls of Rock Mineralogy on the Wetting State, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276
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- Citations: 25
Ekanem EM, Berg S, De S, et 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
Berg S, Gao Y, Georgiadis A, et al., 2020, Determination of critical gas saturation by micro-CT, Pages: 133-150, ISSN: 1529-9074
The critical gas saturation was directly determined using micro-CT flow experiments and associated image analysis. The critical gas saturation is the minimum saturation above which gas becomes mobile and can be produced. Knowing this parameter is particularly important for the production of an oil field that during its lifetime falls below the bubblepoint, which will reduce the oil production dramatically. Experiments to determine the critical gas saturation are notoriously difficult to conduct with conventional coreflooding experiments at the Darcy scale. The difficulties are primarily related to two effects: The development of gas bubbles is a nucleation process which is governed by growth kinetics that, in turn, is related to the extent of pressure drawdown below the bubblepoint. At the Darcy scale, the critical gas saturation at which the formed gas bubbles connect to a percolating path, is typically probed via a flow experiment, during which a pressure gradient is applied. This leads not only to different nucleation conditions along the core but also gives no direct access to the size and growth rate of gas bubbles before the percolation. In combination, these two effects imply that the critical gas saturation observed in such experiments is dependent on permeability and flow rate, and that the critical gas saturation relevant for the (equilibrium) reservoir conditions has to be estimated by an extrapolation. Modern digital-rock-related experimentation and modeling provides a more elegant way to determine the critical gas saturation. We report pressure-depletion experiments in minicores imaged by X-ray computed microtomography (micro-CT) that allowed the direct determination of the connectivity of the gas phase. As such, these experiments enabled the detection of the critical gas saturation via the percolation threshold of the gas bubbles. Furthermore, the associated gas- and oil relative permeabilities can be obtained from single-phase flow simulations of the
Berg S, Gao Y, Georgiadis A, et al., 2020, Determination of Critical Gas Saturation by Micro-CT, PETROPHYSICS, Vol: 61, Pages: 133-150, ISSN: 1529-9074
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- Citations: 10
Rücker M, Bartels W-B, Bultreys T, et al., 2020, Workflow for upscaling wettability from the nano- to core-scales, International Symposium of the Society of Core Analysts
Sun C, McClure JE, Mostaghimi P, et al., 2020, Probing Effective Wetting in Subsurface Systems, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276
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- Citations: 34
Rucker M, Bartels W-B, Garfi G, et 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%.
Li X, Berg S, Castellanos-Diaz O, et al., 2020, Solvent-dependent recovery characteristic and asphaltene deposition during solvent extraction of heavy oil, FUEL, Vol: 263, ISSN: 0016-2361
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- Citations: 13
Sun C, McClure JE, Mostaghimi P, et al., 2020, Linking continuum-scale state of wetting to pore-scale contact angles in porous media, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 561, Pages: 173-180, ISSN: 0021-9797
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- Citations: 29
Snippe J, Berg S, Ganga K, et al., 2020, Experimental and numerical investigation of wormholing during CO<sub>2</sub> storage and water alternating gas injection, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 94, ISSN: 1750-5836
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- Citations: 18
Liu C, Frank F, Thiele C, et al., 2020, An efficient numerical algorithm for solving viscosity contrast Cahn-Hilliard-Navier-Stokes system in porous media, JOURNAL OF COMPUTATIONAL PHYSICS, Vol: 400, ISSN: 0021-9991
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- Citations: 18
Dickinson WW, Aravind SSJ, Higgins SR, et al., 2020, Using atomic force spectroscopy to study oil/mineral interactions at reservoir temperatures and pressures, FUEL, Vol: 259, ISSN: 0016-2361
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- Citations: 9
Garfi G, Lin Q, Berg S, et al., 2019, Fluid surface coverage showing the controls of rock mineralogy on the wetting state
Garfi G, John CM, Berg S, et al., 2019, The sensitivity of estimates of multiphase fluid and solid properties of porous rocks to image processing, Transport in Porous Media, Vol: 131, Pages: 985-1005, ISSN: 0169-3913
X-ray microcomputed tomography (X-ray μ-CT) is a rapidly advancing technology that has been successfully employed to study flow phenomena in porous media. It offers an alternative approach to core scale experiments for the estimation of traditional petrophysical properties such as porosity and single-phase flow permeability. It can also be used to investigate properties that control multiphase flow such as rock wettability or mineral topology. In most applications, analyses are performed on segmented images obtained employing a specific processing pipeline on the greyscale images. The workflow leading to a segmented image is not straightforward or unique and, for most of the properties of interest, a ground truth is not available. For this reason, it is crucial to understand how image processing choices control properties estimation. In this work, we assess the sensitivity of porosity, permeability, specific surface area, in situ contact angle measurements, fluid–fluid interfacial curvature measurements and mineral composition to processing choices. We compare the results obtained upon the employment of two processing pipelines: non-local means filtering followed by watershed segmentation; segmentation by a manually trained random forest classifier. Single-phase flow permeability, in situ contact angle measurements and mineral-to-pore total surface area are the most sensitive properties, as a result of the sensitivity to processing of the phase boundary identification task. Porosity, interfacial fluid–fluid curvature and specific mineral descriptors are robust to processing. The sensitivity of the property estimates increases with the complexity of its definition and its relationship to boundary shape.
Bultreys T, Singh K, Raeini A, et al., 2019, Verifying pore network models of imbibition in rocks using time-resolved synchrotron imaging
Garfi G, John C, Berg S, et al., 2019, The sensitivity of estimates of multiphase fluid and solid properties of porous rocks to image processing
Armstrong RT, McClure JE, Robins V, et al., 2019, Porous Media Characterization Using Minkowski Functionals: Theories, Applications and Future Directions, TRANSPORT IN POROUS MEDIA, Vol: 130, Pages: 305-335, ISSN: 0169-3913
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- Citations: 107
Alpak FO, Zacharoudiou I, Berg S, et al., 2019, Direct simulation of pore-scale two-phase visco-capillary flow on large digital rock images using a phase-field lattice Boltzmann method on general-purpose graphics processing units, COMPUTATIONAL GEOSCIENCES, Vol: 23, Pages: 849-880, ISSN: 1420-0597
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- Citations: 34
Bartels W, Rücker M, Boone M, et 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
Unsal E, Rucker M, Berg S, et al., 2019, Imaging of compositional gradients during in situ emulsification using X-ray micro-tomography, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 550, Pages: 159-169, ISSN: 0021-9797
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- Citations: 27
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