Publications
145 results found
Spurin C, Armstrong RT, McClure J, et al., 2023, Dynamic mode decomposition for analysing multi-phase flow in porous media, Advances in Water Resources, Vol: 175, ISSN: 0309-1708
For multi-phase flow through multi-scale heterogeneous porous media, such as the pore space of rocks, the interaction between multiple immiscible fluids and an intricate network of pores, creates a wide range of dynamic flow phenomena. At larger scales i.e. scales relevant for practical applications such as carbon sequestration, this interplay of dynamic phenomena is often referred to as “complexity”. However, it is important to describe the persistent features of the flow in an adequate manner, to represent the “complexity” of the system. Dynamic Mode Decomposition (DMD) is a dimensionality reduction algorithm that computes a set of modes associated with fixed oscillatory behaviours. In this work, saturation data extracted from dynamic two-phase flow experiments are analysed with DMD. We show that DMD can reproduce the data. Furthermore, not all dynamic modes are required to reproduce key dynamic features; this highlights the important spatial and temporal scales for flow. We show that DMD was able to identify localized regions important to flow. Overall, DMD is proven as a useful diagnostic tool for complex 4D flow dynamics for multi-phase flow.
Liu Y, Berg S, Ju Y, et al., 2022, Systematic Investigation of Corner Flow Impact in Forced Imbibition, WATER RESOURCES RESEARCH, Vol: 58, ISSN: 0043-1397
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- Citations: 1
McClure JE, Fan M, Berg S, et al., 2022, Relative permeability as a stationary process: Energy fluctuations in immiscible displacement, PHYSICS OF FLUIDS, Vol: 34, ISSN: 1070-6631
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- Citations: 1
Spurin C, Rucker M, Moura M, et al., 2022, Red Noise in Steady-State Multiphase Flow in Porous Media, WATER RESOURCES RESEARCH, Vol: 58, ISSN: 0043-1397
Ekanem EM, Berg S, De S, et 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
Garfi G, John C, Rücker M, et 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>
Garfi G, John CM, Rucker M, et 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
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- Citations: 2
Sun C, McClure J, Berg S, et 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
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- Citations: 7
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>
Ekanem EM, Rücker M, Yesufu-Rufai S, et 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
McClure JE, Berg S, Armstrong RT, 2021, Thermodynamics of fluctuations based on time-and-space averages, PHYSICAL REVIEW E, Vol: 104, ISSN: 2470-0045
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- Citations: 6
Ruspini LC, oren PE, Berg S, et al., 2021, Multiscale Digital Rock Analysis for Complex Rocks, TRANSPORT IN POROUS MEDIA, Vol: 139, Pages: 301-325, ISSN: 0169-3913
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- Citations: 16
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
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- Citations: 12
Gao Y, Georgiadis A, Brussee N, et 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
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- Citations: 3
Rucker M, Georgiadis A, Armstrong RT, et 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
Armstrong RT, Sun C, Mostaghimi P, et al., 2021, Multiscale Characterization of Wettability in Porous Media, TRANSPORT IN POROUS MEDIA, Vol: 140, Pages: 215-240, ISSN: 0169-3913
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- Citations: 18
Lin Q, Bijeljic B, Foroughi S, et 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.
Spurin C, Bultreys T, Rücker M, et 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.
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
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- Citations: 11
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
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- Citations: 20
Yesufu-Rufai S, Georgiadis A, Berg S, et 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.
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: 11
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: 24
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: 1
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.
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