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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154 results found

Berg S, Dijk H, Unsal E, Hofmann R, Zhao B, Raju Ahuja Vet al., 2024, Simultaneous determination of relative permeability and capillary pressure from an unsteady-state core flooding experiment?, Computers and Geotechnics, Vol: 168, ISSN: 0266-352X

For modelling studies of underground storage of carbon dioxide and hydrogen, it is important to have a consistent set of relative permeability and capillary pressure–saturation functions. For consistency reasons, it is an advantage to determine both in one single experiment using the same rock and fluid sample, however, experimental measurements typically have challenges. While unsteady-state type of flow experiments is in principle suited for deriving relative permeability and capillary pressure functions, we provide a methodology to optimize the experimental settings such that the simultaneous determination of these functions can succeed within an acceptable uncertainty range, which involve multi-rate flow experiments and in-situ saturation monitoring. We provide details of the inverse modelling methodology which is a self-contained Python code that includes both the 1D flow model and the optimization method for the assisted history match. This methodology can be used for interpreting experiments, but also to optimize the design of the experiment and to reach a desired/acceptable uncertainty range. The purpose of this work is to provide the concrete assessment of unsteady-state type of experiments with the purpose of simultaneously obtaining relative permeability and capillary pressure–saturation functions by means of a ground-truth example, to detail the methodology used and make the Python code with a self-contained 1D flow solver accelerated by the numba just-in-time compiler publicly available. The results underline that the simultaneous determination of relative permeability and capillary pressure–saturation functions are possible only in specially designed multi-rate experiments where several saturation profiles before breakthrough are captured and the capillary end-effect is fully resolved. These conditions are not necessarily met for the more general type of unsteady-state experiments typically used in the more general Special Core Analys

Journal article

Aghajanloo M, Yan L, Berg S, Voskov D, Farajzadeh Ret al., 2024, Impact of CO<inf>2</inf> hydrates on injectivity during CO<inf>2</inf> storage in depleted gas fields: A literature review, Gas Science and Engineering, Vol: 123, ISSN: 2949-9097

Carbon dioxide capture and storage in subsurface geological formations is a potential solution to limit anthropogenic CO2 emissions and combat global warming. Depleted gas fields offer significant CO2 storage volumes; however, injection of CO2 into these reservoirs poses some potential challenges for the injectivity, containment and well/facility integrity due to low temperatures caused by isenthalpic expansion of CO2. A key injectivity risk is due to possible formation of hydrates at the low expected temperatures. This study aims to address main causes of CO2 hydrate formation and its impact on permeability of porous media. This review highlights the current state of knowledge in the literature while emphasizing the need to bridge existing gaps in derisking CO2 injection into (depleted) low-pressure gas reservoirs. In summary, according to the existing literature, the potential for hydrate formation is assessed to be credible. Current industry solutions exist to manage this risk; however, they are costly and energy intensive. Future research will be needed to provide capabilities to manage this risk more efficiently.

Journal article

Maas JG, Springer N, Hebing A, Snippe J, Berg Set al., 2024, Viscous fingering in CCS - A general criterion for viscous fingering in porous media, International Journal of Greenhouse Gas Control, Vol: 132, ISSN: 1750-5836

For many practical applications such as the CO2 injection for carbon capture and sequestration (CCS) or gas injection for underground energy storage it is important to understand whether this displacement is stable or unstable. Viscous instability may occur in a porous medium when a fluid with higher mobility displaces a fluid with lower mobility, and is therefore an obvious question for CCS since the viscosity of injected CO2 is typically much less than the displaced brine. Historically, several different criteria have been developed to predict the onset of viscous fingering. That leaves significant uncertainty which criterion is now valid since for the criterion of shock front mobility ratio the CO2-brine displacement could be stable while the shock front total mobility ratio or the end point mobility ratio criterion suggests an unstable displacement. The root-cause of this level of ambiguity is that for multiphase displacement in porous media it is not sufficient to consider only fixed values for saturation upstream and downstream. Instead, the whole Buckley–Leverett saturation profile needs to be considered. In this work, we present a new approach to derive a general criterion for viscous fingering in porous media that removes the ambiguity around the question of displacement stability. This new criterion contains all earlier derived criteria as limiting cases, whether for porous media or for Hele-Shaw cells, with and without gravity, immiscible and miscible. It has been validated by Darcy scale numerical flow simulations in 2D. The new criterion is particularly useful for CCS and we discuss how, depending on exact pressure and temperature conditions, CCS can be viscous-unstable. Viscous-unstable displacement has implications for both laboratory-scale “core flooding” experiments where displacement stability influences the interpretation in terms of relative permeability, and also for the field scale for CCS where viscous-unstable displacement m

Journal article

Taberner C, Fadili A, Berg S, Marcelis F, Gao Y, Bouwmeester R, De Boever W, Boone M, Dewanckele J, Sorop T, van der Horst Jet al., 2023, Mapping and quantification of rock properties in heterogeneous carbonates. Ready for upscaling purposes, Pages: 316-320, ISSN: 1052-3812

A hybrid workflow based on multiscale 3D imaging of cores, combined with limited experimental data sets (phi-K, PcMICP) has been developed to determine the distribution of porosity and permeability as input for a 3D numerical model at mm scale grid resolution. Porosity and permeability data were obtained from 1.5” plugs selected outside of the standard 1 ft intervals to better capture heterogeneity. Porosity-permeability distribution were derived from digital images based on CT numbers and used as a constraint to build a digital twin of long plugs (around 30 cm length). The prediction capability of the digital twin was tested against an experimental tracer test as a validation of porosity and permeability spatial distribution in the numerical model. The workflow is applicable to a whole core diameter and meter length. The goal is to develop a more advanced workflow for 2-phase flow in heterogeneous systems, and the upscaling of effective dynamic properties, such as relative permeabilities for use in a dynamic field simulator.

Conference paper

An S, Wenck N, Manoorkar S, Berg S, Taberner C, Pini R, Krevor Set al., 2023, Inverse Modeling of Core Flood Experiments for Predictive Models of Sandstone and Carbonate Rocks, Water Resources Research, Vol: 59, ISSN: 0043-1397

Field-scale observations suggest that rock heterogeneities control subsurface fluid flow, and these must be characterized for accurate predictions of fluid migration, such as during CO2 sequestration. Recent efforts characterizing multiphase flow in heterogeneous rocks have focused on simulation-based inversion of laboratory observations with X-ray imaging. However, models produced in this way have been limited in their predictive ability for heterogeneous rocks. We address the main challenges in this approach through an algorithm that combines new developments: a 3-parameter capillary pressure model, spatial heterogeneity in absolute permeability, improved image processing to capture more experimental data in the calibration, and the constraint of history match iterations based on marginal error improvement. We demonstrate the improvements on two sandstones and three carbonate rocks, with varying heterogeneity, some of which could not be previously modeled. The algorithm results in physically representative models of the rock cores, reducing non-systematic error to a level comparable to the experimental uncertainty.

Journal article

Lindsay C, Braun E, Berg S, Krevor S, Pols R, Hill Jet al., 2023, Core analysis in a changing world – how technology is radically benefiting the methodology to acquire, the ability to visualize and the ultimate value of core data, Vol: 527, Pages: 43-58, ISSN: 0305-8719

Core analysts principally study the storage, flow and saturation properties of porous rocks and sed-iments. Some of the derived parameters are specific to hydrocarbon production but many have commonality with other subsurface disciplines such as hydrology and soil science. Traditional core analysis involves direct physical experimentation on core plugs to derive a range of parameters used as calibration for conventional well logs, and to predict hydrocarbon reserves and recovery. The mechanisms and processes for obtaining such data have evolved significantly during the last century, from the manual instruments of the mid-twentieth century to the accredited digital data collection and recording of the 1990s onwards. X-ray micro-and nano-scale computed tomography (CT) imaging led to the development of the digital rock physics subdiscipline in the early 2000s. This has subsequently allowed direct visualization of fluid flow at the pore scale, imaging the wetting phase and multiphase fluid mobility. Multiscale imaging workflows are being developed to overcome issues around heterogeneous rock and the limited field of view associated with the high-est resolution X-ray CT images. Hybrid workflows, which combine digital rock physics with traditional core analysis, are becoming increasingly common to meet the challenges associated with some of the most difficult to constrain properties, such as relative permeability. At a larger scale, the recent development of multisensor core logging (MSCL) tools has allowed the cost-effective acquisition of essentially continuous high-resolution 1D, 2D and 3D datasets from both slabbed and unslabbed whole core. Often aided by artificial intelligence to manage and interpret these large physical and chemical datasets, both new and legacy core can be rapidly screened to allow representative subsampling for detailed laboratory experimentation. The context and data provided by the MSCL then allows effective upscaling of these time-and cost-int

Journal article

Pak T, Archilha NL, Berg S, Butler IBet al., 2023, Design considerations for dynamic fluid flow in porous media experiments using X-ray computed micro tomography – A review, Tomography of Materials and Structures, Vol: 3, Pages: 100017-100017, ISSN: 2949-673X

Journal article

Al-Zubaidi F, Mostaghimi P, Niu Y, Armstrong RT, Mohammadi G, McClure JE, Berg Set al., 2023, Effective permeability of an immiscible fluid in porous media determined from its geometric state, PHYSICAL REVIEW FLUIDS, Vol: 8, ISSN: 2469-990X

Journal article

Gao Y, Sorop T, Brussee N, Linde HVD, Coorn A, Appel M, Berg Set al., 2023, Advanced Digital-SCAL Measurements of Gas Trapped in Sandstone1, Petrophysics, Vol: 64, Pages: 368-383, ISSN: 1529-9074

Trapped gas saturation (Sgr) plays an important role in more (pre-equilibrated) brine injected and even after the subsurface engineering, such as carbon capture and storage, brine injection was stopped, resulting in very low Sgrvalues H2 storage efficiency as well as the production of natural (possibly even zero) at the pore-scale level. Furthermore, gas. Unfortunately, Sgr is notoriously difficult to measure we were able to clearly observe the initial trapping of gas in the laboratory or field. The conventional method of by the snap-off effect, followed by a further shrinkage measurement—low-rate unsteady-state coreflooding—of the gas clusters that had no connected pathway to the is often impacted by gas dissolution effects, resulting in outside. Our experimental insights suggest that the effect large uncertainties of the measured Sgr. Moreover, it is not is related to the effective phase behavior of gas inside the understood why this effect occurs, even for brines carefully porous medium, which due to the geometric confinement, pre-equilibrated with gas. To address this question, we could be different from the phase behavior of bulk fluids. used high-resolution X-ray computed tomography (microThe underlying mechanism is likely linked to ripening CT) imaging techniques to directly visualize the poredynamics, which involves a coupling between phase scale processes during gas trapping. Consistent with equilibrium and dissolution/partitioning of components, previous studies, we find that for pre-equilibrated brine, diffusive transport, and capillarity in the geometric the remaining gas saturation continually decreased with confinement of the pore space.

Journal article

Spurin C, Armstrong RT, McClure J, Berg Set al., 2023, Dynamic mode decomposition for analysing multi-phase flow in porous media, ADVANCES IN WATER RESOURCES, Vol: 175, ISSN: 0309-1708

Journal article

Liu Y, Berg S, Ju Y, Wei W, Kou J, Cai Jet al., 2022, Systematic Investigation of Corner Flow Impact in Forced Imbibition, WATER RESOURCES RESEARCH, Vol: 58, ISSN: 0043-1397

Journal article

McClure JE, Fan M, Berg S, Armstrong RTT, Berg CF, Li Z, Ramstad Tet al., 2022, Relative permeability as a stationary process: Energy fluctuations in immiscible displacement, PHYSICS OF FLUIDS, Vol: 34, ISSN: 1070-6631

Journal article

Spurin C, Rucker M, Moura M, Bultreys T, Garfi G, Berg S, Blunt MJ, Krevor Set al., 2022, Red Noise in Steady-State Multiphase Flow in Porous Media, WATER RESOURCES RESEARCH, Vol: 58, ISSN: 0043-1397

Journal article

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., 2022, 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

Garfi G, John C, Rücker M, Lin Q, Spurin C, Berg S, Krevor Set al., 2022, Determination of the spatial distribution of wetting in the pore networks of rocks

<jats:p>The macroscopic movement of subsurface fluids involved in CO2 storage, groundwater, and petroleum engineering applications is controlled by interfacial forces in the pores of rocks, micrometre to millimetre in length scale. Recent advances in physics based models of these systems has arisen from approaches simulating flow through a digital representation of the complex pore structure. However, further progress is limited by a lack of approaches to characterising the spatial distribution of the wetting state within the pore structure. In this work, we show how observations of the fluid coverage of mineral surfaces within the pores of rocks can be used as the basis for a quantitative 3D characterisation of heterogeneous wetting states throughout rock pore structures. We demonstrate the approach with water-oil fluid pairs on rocks with distinct lithologies (sandstone and carbonate) and wetting states (hydrophilic, intermediate wetting, or heterogeneously wetting). The resulting 3D maps can be used as a deterministic input to pore scale modelling workflows and applied to all multiphase flow problems in porous media ranging from soil science to fuel cells.</jats:p>

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

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

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

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

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, 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

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