Imperial College London

DrSteffenBerg

Faculty of EngineeringDepartment of Earth Science & Engineering

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1M10cACE ExtensionSouth Kensington Campus

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Publications

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141 results found

Ekanem EM, Berg S, De S, Fadili A, Luckham Pet al., 2022, Towards predicting the onset of elastic turbulence in complex geometries, Transport in Porous Media, Vol: 143, ISSN: 0169-3913

Flow of complex fluids in porous structures is pertinent in many biological and industrial processes. For these applications, elastic turbulence, a viscoelastic instability occurring at low Re—arising from a non-trivial coupling of fluid rheology and flow geometry—is a common and relevant effect because of significant over-proportional increase in pressure drop and spatio-temporal distortion of the flow field. Therefore, significant efforts have been made to predict the onset of elastic turbulence in flow geometries with constrictions. The onset of flow perturbations to fluid streamlines is not adequately captured by Deborah and Weissenberg numbers. The introduction of more complex dimensionless numbers such as the M-criterion, which was meant as a simple and pragmatic method to predict the onset of elastic instabilities as an order-of-magnitude estimate, has been successful for simpler geometries. However, for more complex geometries which are encountered in many relevant applications, sometimes discrepancies between experimental observation and M-criteria prediction have been encountered. So far these discrepancies have been mainly attributed to the emergence from disorder. In this experimental study, we employ a single channel with multiple constrictions at varying distance and aspect ratios. We show that adjacent constrictions can interact via non-laminar flow field instabilities caused by a combination of individual geometry and viscoelastic rheology depending (besides other factors) explicitly on the distance between adjacent constrictions. This provides intuitive insight on a more conceptual level why the M-criteria predictions are not more precise. Our findings suggest that coupling of rheological effects and fluid geometry is more complex and implicit and controlled by more length scales than are currently employed. For translating bulk fluid, rheology determined by classical rheometry into the effective behaviour in complex porous geometries re

Journal article

Garfi G, John CM, Rucker M, Lin Q, Spurin C, Berg S, Krevor Set al., 2022, Determination of the spatial distribution of wetting in the pore networks of rocks, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 613, Pages: 786-795, ISSN: 0021-9797

Journal article

Sun C, McClure J, Berg S, Mostaghimi P, Armstrong RTet al., 2021, Universal description of wetting on multiscale surfaces using integral geometry, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 608, Pages: 2330-2338, ISSN: 0021-9797

Journal article

Berg S, Unsal E, 2021, THE CERTAINTY IN UNCERTAINTY: Quantifying coreflood data errors, Shell TechXplorer Digest 2021, Vol: 2021

<jats:p>Multiphase flow in porous media systems is a critical element of many processes in the energy industry. The characteristics of the simultaneous flow of the immiscible phases can be quantified using relative permeability relations. In geoscience applications, these relations are determined in coreflooding studies that often comprise coreflood tests of oil–water mixtures performed on centimetre-scale rock samples. The outcomes of these are subject to uncertainty, which ultimately influences how accurately the parameters from small-scale tests translate to the upscaled estimations. To assess this uncertainty, Shell researchers have developed an inverse modelling workflow for the uncertainty analysis of relative permeability functions derived from coreflood tests. The results suggest that, even at a small scale, the uncertainty can be significant.</jats:p>

Journal article

Ekanem EM, Rücker M, Yesufu-Rufai S, Spurin C, Ooi N, Georgiadis A, Berg S, Luckham PFet al., 2021, Novel adsorption mechanisms identified for polymer retention in carbonate rocks, JCIS Open, Vol: 4, Pages: 100026-100026, ISSN: 2666-934X

HypothesisHigh molecular weight polymers are widely used in oilfield applications, such as in chemical enhanced oil recovery (cEOR) technique for hydrocarbon recovery. However, during flow in a porous rock, polymer retention is usually a major challenge, as it may result in the decrease of polymer concentration or lead to plugging of pores with significant permeability reduction and injectivity loss. Hence, an understanding of the retention mechanisms will have a profound effect in optimizing the process of polymer flooding, in particular, for carbonate rocks, which hold more than half of the world's oil reserves. Therefore, in this study, the retention of hydrolysed polyacrylamide (HPAM) polymer, a commonly used chemical for EOR, is investigated during flow in Estaillades carbonate rock.ExperimentsA novel approach of investigating HPAM retention in Estaillades carbonate rock was carried out using Atomic force microscopy (AFM). Since Estaillades carbonate rock is ∼98% calcite, HPAM retention was first characterised on a cleaved flat calcite mineral surface after immersing in HPAM solution. Afterwards, HPAM was flooded in Estaillades carbonate to observe the effect of flow dynamics on the retention mechanisms.FindingsWe find that the dominant mechanism for retention of HPAM on calcite after fluid immersion is polymer adsorption, which we believe is driven by the electrostatic interaction between the calcite surface and the solution. The thickness of the adsorbed layer on calcite is beyond 3 ​nm suggesting it is not adsorbed only flat on the surface. Different types of adsorbed layers were formed representing trains, and the more extended loops or tails with the largest polymer layer thickness about 35 ​nm, representing the longer loops or tails. Layers of this thickness will begin to impair the permeability of the rock. However, in Estaillades, thicker adsorbed layers are observed in different regions of the rock surface ranging between 50 and 350 ​nm. We suggest

Journal article

McClure JE, Berg S, Armstrong RT, 2021, Thermodynamics of fluctuations based on time-and-space averages, PHYSICAL REVIEW E, Vol: 104, ISSN: 2470-0045

Journal article

Ruspini LC, oren PE, Berg S, Masalmeh S, Bultreys T, Taberner C, Sorop T, Marcelis F, Appel M, Freeman J, Wilson OBet al., 2021, Multiscale Digital Rock Analysis for Complex Rocks, TRANSPORT IN POROUS MEDIA, Vol: 139, Pages: 301-325, ISSN: 0169-3913

Journal article

McClure JE, Berg S, Armstrong RT, 2021, Capillary fluctuations and energy dynamics for flow in porous media, PHYSICS OF FLUIDS, Vol: 33, ISSN: 1070-6631

Journal article

Gao Y, Georgiadis A, Brussee N, Ab C, van Der Linde H, Dietderich J, Alpak FO, Eriksen D, Mooijer-van Den Heuvel M, Appel M, Sorop T, Wilson OB, Berg Set al., 2021, Capillarity and phase-mobility of a hydrocarbon gas-liquid system, OIL & GAS SCIENCE AND TECHNOLOGY-REVUE D IFP ENERGIES NOUVELLES, Vol: 76, ISSN: 1294-4475

Journal article

Rucker M, Georgiadis A, Armstrong RT, Ott H, Brussee N, van der Linde H, Simon L, Enzmann F, Kersten M, Berg Set al., 2021, The origin of non-thermal fluctuations in multiphase flow in porous media, Frontiers in Water, Vol: 3, Pages: 1-25, ISSN: 2624-9375

Core flooding experiments to determine multiphase flow in properties of rock such as relative permeability can show significant fluctuations in terms of pressure, saturation, and electrical conductivity. That is typically not considered in the Darcy scale interpretation but treated as noise. However, in recent years, flow regimes that exhibit spatio-temporal variations in pore scale occupancy related to fluid phase pressure changes have been identified. They are associated with topological changes in the fluid configurations caused by pore-scale instabilities such as snap-off. The common understanding of Darcy-scale flow regimes is that pore-scale phenomena and their signature should have averaged out at the scale of representative elementary volumes (REV) and above. In this work, it is demonstrated that pressure fluctuations observed in centimeter-scale experiments commonly considered Darcy-scale at fractional flow conditions, where wetting and non-wetting phases are co-injected into porous rock at small (<10−6) capillary numbers are ultimately caused by pore-scale processes, but there is also a Darcy-scale fractional flow theory aspect. We compare fluctuations in fractional flow experiments conducted on samples of few centimeters size with respective experiments and in-situ micro-CT imaging at pore-scale resolution using synchrotron-based X-ray computed micro-tomography. On that basis we can establish a systematic causality from pore to Darcy scale. At the pore scale, dynamic imaging allows to directly observe the associated breakup and coalescence processes of non-wetting phase clusters, which follow “trajectories” in a “phase diagram” defined by fractional flow and capillary number and can be used to categorize flow regimes. Connected pathway flow would be represented by a fixed point, whereas processes such as ganglion dynamics follow trajectories but are still overall capillary-dominated. That suggests that the origin of the pr

Journal article

Armstrong RT, Sun C, Mostaghimi P, Berg S, Ruecker M, Luckham P, Georgiadis A, McClure JEet al., 2021, Multiscale Characterization of Wettability in Porous Media, TRANSPORT IN POROUS MEDIA, Vol: 140, Pages: 215-240, ISSN: 0169-3913

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

Spurin C, Bultreys T, Rücker M, Garfi G, Schlepütz CM, Novak V, Berg S, Blunt MJ, Krevor Set al., 2021, The development of intermittent multiphase fluid flow pathways through a porous rock, Advances in Water Resources, Vol: 150, Pages: 1-7, ISSN: 0309-1708

storage and natural gas production. However, due to experimental limitations, it has not been possible to identify why intermittency occurs at subsurface conditions and what the implications are for upscaled flow properties such as relative permeability. We address these questions with observations of nitrogen and brine flowing at steady-state through a carbonate rock. We overcome previous imaging limitations with high-speed (1s resolution), synchrotron-based X-ray micro-computed tomography combined with pressure measurements recorded while controlling fluid flux. We observe that intermittent fluid transport allows the non-wetting phase to flow through a more ramified network of pores, which would not be possible with connected pathway flow alone for the same flow rate. The volume of fluid intermittently fluctuating increases with capillary number, with the corresponding expansion of the flow network minimising the role of inertial forces in controlling flow even as the flow rate increases. Intermittent pathway flow sits energetically between laminar and turbulent through connected pathways. While a more ramified flow network favours lowered relative permeability, intermittency is more dissipative than laminar flow through connected pathways, and the relative permeability remains unchanged for low capillary numbers where the pore geometry controls the location of intermittency. However, as the capillary number increases further, the role of pore structure in controlling intermittency decreases which corresponds to an increase in relative permeability. These observations can serve as the basis of a model for the causal links between intermittent fluid flow, fluid distribution throughout the pore space, and the upscaled manifestation in relative permeability.

Journal article

Berg S, Unsal E, Dijk H, 2021, Sensitivity and Uncertainty Analysis for Parameterization of Multiphase Flow Models, TRANSPORT IN POROUS MEDIA, Vol: 140, Pages: 27-57, ISSN: 0169-3913

Journal article

Berg S, Unsal E, Dijk H, 2021, Non-uniqueness and uncertainty quantification of relative permeability measurements by inverse modelling, COMPUTERS AND GEOTECHNICS, Vol: 132, ISSN: 0266-352X

Journal article

Yesufu-Rufai S, Georgiadis A, Berg S, Marcelis F, Rucker M, Van Wunnik J, Luckham Pet al., 2021, NANOSCALE ASSESSMENT OF SANDSTONE WETTABILITY DURING REDOX TREATMENT BY ATOMIC FORCE MICROSCOPY (AFM), Pages: 1117-1121

A key step in de-risking chemical enhanced oil recovery (cEOR) projects is to assess the incremental recovery for the field of interest in customised laboratory experiments that mimic conditions within target reservoirs. Any deviation from these conditions, as is oftentimes the case, leads to discrepancies which call the reliability of laboratory results into question, thereby affecting the economics of the cEOR projects. Concerning iron-bearing formations, one approach is to treat samples with a reducing fluid in order to mimic native reservoir redox conditions. In this study, investigations into the effect of a solution of the reducing agent, Sodium Dithionite, in brine on surface wettability were performed using Atomic Force Microscopy (AFM) to quantify interactions between model crude oil components and an iron-bearing sandstone under varying redox conditions. Results show that the adhesion of the oil components to the sandstone surface decreased in the order -NH2 (~70%) > -COOH (~36%) > -CH3 (~3%) on introduction of the reducing fluid, potentially providing a basis for deployment in core floods to ascertain the suitability of cEOR procedures.

Conference paper

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>

Journal article

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

Sun C, McClure JE, Mostaghimi P, Herring AL, Meisenheimer DE, Wildenschild D, Berg S, Armstrong RTet al., 2020, Characterization of wetting using topological principles, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 578, Pages: 106-115, ISSN: 0021-9797

Journal article

Yesufu-Rufai S, Rucker M, Berg S, Lowe SF, Marcelis F, Georgiadis A, Luckham Pet 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.

Journal article

Xiong R, Zhang Y, Zhou W, Xia K, Sun Q, Chen G, Han B, Gao Q, Zhou Cet 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

Journal article

Yesufu-Rufai S, Marcelis F, Georgiadis A, Berg S, Rucker M, van Wunnik J, Luckham Pet 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

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

McClure JE, Ramstad T, Li Z, Armstrong RT, Berg Set 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

Journal article

Garfi G, John CM, Lin Q, Berg S, Krevor Set al., 2020, Fluid Surface Coverage Showing the Controls of Rock Mineralogy on the Wetting State, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276

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

Berg S, Gao Y, Georgiadis A, Brussee N, Coorn A, van der Linde H, Dietderich J, Alpak FO, Eriksen D, Mooijer-van den Heuvel M, Southwick J, Appel M, Wilson OBet al., 2020, Determination of Critical Gas Saturation by Micro-CT, PETROPHYSICS, Vol: 61, Pages: 133-150, ISSN: 1529-9074

Journal article

Berg S, Gao Y, Georgiadis A, Brussee N, Coorn A, van der Linde H, Dietderich J, Alpak FO, Eriksen D, Mooijer-Van den Heuvel M, Southwick J, Appel M, Wilson OBet 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

Conference paper

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

Sun C, McClure JE, Mostaghimi P, Herring AL, Berg S, Armstrong RTet al., 2020, Probing Effective Wetting in Subsurface Systems, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276

Journal article

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