Publications
154 results found
Lin Q, Bijeljic B, Berg S, et al., 2019, Minimal surfaces in porous media: Pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone, Physical Review E, Vol: 99, Pages: 063105-1-063105-13, ISSN: 1539-3755
High-resolution x-ray imaging was used in combination with differential pressure measurements to measurerelative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on asample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil toalter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flowrate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, x-raytomographic images were taken. The images were used to compute saturation, interfacial area, curvature, andcontact angle. From this information relative permeability and capillary pressure were determined as functionsof saturation. We compare our results with a previously published experiment under water-wet conditions. Theoil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, ofapproximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock.The capillary pressure was slightly negative and 10 times smaller in magnitude than for the water-wet rock,and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area wasalso largely constant in this saturation range. The measured static contact angles had an average of 80◦ with astandard deviation of 17◦. We observed that the oil-brine interfaces were not flat, as may be expected for a verylow mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. Theseinterfaces were approximately minimal surfaces, which implies well-connected phases. Saddle-shaped menisciswept through the pore space at a constant capillary pressure and with an almost fixed area, removing most ofthe oil.
Lin Q, Bijeljic B, Krevor SC, et al., 2019, A New Waterflood Initialization Protocol With Wettability Alteration for Pore-Scale Multiphase Flow Experiments, Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description, Vol: 60, Pages: 264-272, ISSN: 1529-9074
Rücker M, Bartels WB, Singh K, et al., 2019, The Effect of Mixed Wettability on Pore-Scale Flow Regimes Based on a Flooding Experiment in Ketton Limestone, Geophysical Research Letters, Vol: 46, Pages: 3225-3234, ISSN: 0094-8276
© 2019. The Authors. Darcy-scale multiphase flow in geological formations is significantly influenced by the wettability of the fluid-solid system. So far it has not been understood how wettability impacts the pore-scale flow regimes within rocks, which were in most cases regarded as an alteration from the base case of strongly water-wet conditions by adjustment of contact angles. In this study, we directly image the pore-scale flow regime in a carbonate altered to a mixed-wet condition by aging with crude oil to represent the natural configuration in an oil reservoir with fast synchrotron-based X-ray computed tomography. We find that the pore-scale flow regime is dominated by ganglion dynamics in which the pore space is intermittently filled with oil and brine. The frequency and size of these fluctuations are greater than in water-wet rock such that their impact on the overall flow and relative permeability cannot be neglected in modeling approaches.
Lin Q, Bijeljic B, Berg S, et al., 2019, Minimal surfaces in porous media: pore-scale imaging of multiphase flow in an altered-wettability Bentheimer sandstone, Publisher: EarthArXiv
We observed features of pore scale fluid distributions during oil-brine displacement in a mixed-wet sandstone rock sample. High-resolution X-ray imaging was used in combination with differential pressure measurements to measure relative permeability and capillary pressure simultaneously during a steady-state waterflood experiment on a sample of Bentheimer sandstone 51.6 mm long and 6.1 mm in diameter. After prolonged contact with crude oil to alter the surface wettability, a refined oil and formation brine were injected through the sample at a fixed total flow rate but in a sequence of increasing brine fractional flows. When the pressure across the system stabilized, X-ray tomographic images were taken. The images were used to compute saturation, interfacial area, curvature and contact angle. From this information relative permeability and capillary pressure were determined as functions of saturation. We compare our results with a previously published experiment with strongly water-wet conditions. The oil relative permeability was lower than in the water-wet case, although a smaller residual oil saturation, of approximately 0.11, was obtained, since the oil remained connected in layers in the altered wettability rock. The capillary pressure was slightly negative and ten times smaller in magnitude than a similar water-wet rock, and approximately constant over a wide range of intermediate saturation. The oil-brine interfacial area was also largely constant in this saturation range. The measured static contact angles had an average of $80^{\circ}$ with a standard deviation of $17^{\circ}$.We observed that the oil-brine interfaces were not flat, as may be expected for a very low mean curvature, but had two approximately equal, but opposite, curvatures in orthogonal directions. These interfaces were approximately minimal surfaces which allow efficient displacement and imply well-connected phases. Saddle-shaped menisci swept through the pore space at a constant capillary
Bartels WB, Mahani H, Berg S, et al., 2019, Literature review of low salinity waterflooding from a length and time scale perspective, Fuel, Vol: 236, Pages: 338-353, ISSN: 0016-2361
In recent years, research activity on the recovery technique known as low salinity waterflooding has sharply increased. The main motivation for field application of low salinity waterflooding is the improvement of oil recovery by acceleration of production (‘oil faster’) compared to conventional high salinity brine injection. Up to now, most research has focused on the core scale by conducting coreflooding and spontaneous imbibition experiments. These tests serve as the main proof that low salinity waterflooding can lead to additional oil recovery. Usually, it is argued that if the flooding experiments show a positive shift in relative permeability curves, field application is justified provided the economic considerations are also favorable. In addition, together with field pilots, these tests resulted in several suggested trends and underlying mechanisms related to low salinity water injections that potentially explain the additional recovery. While for field application one can rely on the core scale laboratory tests which can provide the brine composition dependent saturation functions such as relative permeability, they are costly, time consuming and challenging. It is desirable to develop predictive capability such that new candidates can be screened effectively or prioritized. This has not been yet achieved and would require under-pinning the underlying mechanism(s) of the low salinity response. Recently, research has intensified on smaller length scales i.e. the sub-pore scale. This coincides with a shift in thinking. In field and core scale tests the main goal was to correlate bulk properties of rock and fluids to the amount of oil recovered. Yet in the tests on the sub-pore scale the focus is on ruling out irrelevant mechanisms and understanding the physics of the processes leading to a response to low salinity water. Ultimately this should lead to predictive capability that allows to pre-select potential field candidates based on easily obtain
Eguagie E, Berg S, Crawshaw J, et al., 2019, Flexible coiled polymer dynamics in a single pore throat with effects of flow resistance and normal stresses
© 2019 European Association of Geoscientists and Engineers, EAGE. All Rights Reserved. We investigate the challenges involved in the use of polymer flooding as a chemical enhanced oil recovery (cEOR) technique for improving mobility ratio and enhancing macroscopic sweep efficiency. Flexible coiled polymers in porous media undergo stretching in a spatially heterogeneous structure. Due to the viscoelasticity of these polymers, they stretch continuously depending on their previous deformation until their elastic limit is reached and relaxation occurs. Previous research has proposed that at a certain critical flow rate, the relaxation of polymers cause an increase in viscosity and in turn a better mobility for enhancing microscopic sweep in porous media. However, others have reported that the increased viscosity in porous media is not so much related to the elasticity but more on the normal stresses that occur when polymers are sheared in porous media flow. One similar fact is that as increased viscosity is observed an enhanced pressured drop occurs and the flow becomes highly unstable even at laminar flow regime. This unstable flow is termed the elastic instability or turbulence but the details of this kind of turbulence, its consequences and applicability on the impact of oil recovery is not understood. In this work, we experimentally investigate the flow behaviors of flexible coiled polymers of hydrolyzed polyacrylamide (HPAM) based on a single pore throat geometry using a microfluidic device. The aim is to adequately parameterize the effects of the normal stress difference in shear and extension as a function of the geometry and intrinsic characteristics of the polymer solutions at different Deborah (De) numbers. Hence, we carry out pressure drop and particle image velocimetry experiments and results showed a critical De at which polymer viscosity increases as well as the normal stress difference. It was also observed that the flow resistance might be a functio
Eguagie E, Berg S, Crawshaw J, et al., 2019, Flexible coiled polymer dynamics in a single pore throat with effects of flow resistance and normal stresses
We investigate the challenges involved in the use of polymer flooding as a chemical enhanced oil recovery (cEOR) technique for improving mobility ratio and enhancing macroscopic sweep efficiency. Flexible coiled polymers in porous media undergo stretching in a spatially heterogeneous structure. Due to the viscoelasticity of these polymers, they stretch continuously depending on their previous deformation until their elastic limit is reached and relaxation occurs. Previous research has proposed that at a certain critical flow rate, the relaxation of polymers cause an increase in viscosity and in turn a better mobility for enhancing microscopic sweep in porous media. However, others have reported that the increased viscosity in porous media is not so much related to the elasticity but more on the normal stresses that occur when polymers are sheared in porous media flow. One similar fact is that as increased viscosity is observed an enhanced pressured drop occurs and the flow becomes highly unstable even at laminar flow regime. This unstable flow is termed the elastic instability or turbulence but the details of this kind of turbulence, its consequences and applicability on the impact of oil recovery is not understood. In this work, we experimentally investigate the flow behaviors of flexible coiled polymers of hydrolyzed polyacrylamide (HPAM) based on a single pore throat geometry using a microfluidic device. The aim is to adequately parameterize the effects of the normal stress difference in shear and extension as a function of the geometry and intrinsic characteristics of the polymer solutions at different Deborah (De) numbers. Hence, we carry out pressure drop and particle image velocimetry experiments and results showed a critical De at which polymer viscosity increases as well as the normal stress difference. It was also observed that the flow resistance might be a function of both the elasticity and the normal stresses in shear flow, however, extensional stresse
Alpak FO, Berg S, Zacharoudiou I, 2018, Prediction of fluid topology and relative permeability in imbibition in sandstone rock by direct numerical simulation, ADVANCES IN WATER RESOURCES, Vol: 122, Pages: 49-59, ISSN: 0309-1708
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- Citations: 40
Hertel SA, Rydzy M, Anger B, et al., 2018, Upscaling of digital rock porosities by correlation with whole-core CT-Scan histograms, Pages: 694-702, ISSN: 1529-9074
Digital rock technologies were developed to augment traditional core analysis and led to a much improved understanding of the microstructure of many rock core types. However, to produce an upscaled description of the reservoir, one must consolidate the measurements in scale over six orders of magnitude. Here, we show that a whole- core CT scan may serve as the natural link between the length scales of digital rocks and modem logging tools. While the CT scan contains a fingerprint of the structure of the reservoir, the digital rock models show the microscopic composition of each CT-scan voxel. For upscaling purposes, we established a quadratic correlation between the gray values in a CT scan and the porosities measured on core plugs. This correlation allowed us to generate a synthetic porosity log of millimeter resolution. After that, the length scalc was increased using moving averages in the vertical direction. We investigated a thin-bed reservoir with layers of halite-filled sandstone alternating with layers free of halite at variable layer thicknesses. In this reservoir, the resulting synthetic porosity log compared well with the NMR log porosity within the uncertainty band over a total depth interval of 53.6 meters. We propose that field decisions could be accelerated if the quadratic correlation parameters can be generalized for these types of sediment. In this case, one may generate synthetic porosity logs as soon as the CT scan is available, which is typically the first step in standard corc analysis.
Frank F, Liu C, Alpak FO, et al., 2018, Direct Numerical Simulation of Flow on Pore-Scale Images Using the Phase-Field Method, SPE JOURNAL, Vol: 23, Pages: 1833-1850, ISSN: 1086-055X
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- Citations: 23
Hertel SA, Rydzy M, Anger B, et al., 2018, Upscaling of Digital Rock Porosities by Correlation With Whole-Core CT-Scan Histograms, SPWLA Annual Logging Symposium, Publisher: SOC PETROPHYSICISTS & WELL LOG ANALYSTS-SPWLA, Pages: 694-702, ISSN: 1529-9074
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- Citations: 6
McClure JE, Armstrong RT, Berrill MA, et al., 2018, Geometric state function for two-fluid flow in porous media, PHYSICAL REVIEW FLUIDS, Vol: 3, ISSN: 2469-990X
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- Citations: 76
Berg S, Saxena N, Shaik M, et al., 2018, Generation of ground truth images to validate micro-CT image-processing pipelines, Leading Edge, Vol: 37, Pages: 412-420, ISSN: 1070-485X
Digital rock technology and pore-scale physics have become increasingly relevant topics in a wide range of porous media with important applications in subsurface engineering. This technology relies heavily on images of pore space and pore-level fluid distribution determined by X-ray microcomputed tomography (micro-CT). Digital images of pore space (or pore-scale fluid distribution) are typically obtained as gray-level images that first need to be processed and segmented to obtain the binary images that uniquely represent rock and pore (including fluid phases). This processing step is not trivial. Rock complexity, image quality, noise, and other artifacts prohibit the use of a standard processing workflow. Instead, an array of strategies of increasing sophistication has been developed. Typical processing pipelines consist of filtering, segmentation, and postprocessing steps. For each step, various choices and different options exist. This makes selection and validation of an optimum processing pipeline difficult. Using Darcy-scale quantities as a benchmark is not a good option because of rock heterogeneity and different scales of observation. Here, we present a conceptual workflow where noisy images are derived from a ground truth by systematically including typical image artifacts and noise. Artifacts and noise are not simply added to the images. Instead, tomographic forward projection and reconstruction steps are used to incorporate the artifacts in a physically correct way. A proof of concept of this workflow is demonstrated by comparing seven different image-segmentation pipelines ranging from absolute thresholding to a machine-learning approach (Trainable Weka Segmentation). The Trainable Weka Segmentation showed the best performance of the tested methods.
Alpak FO, Gray F, Saxena N, et al., 2018, A distributed parallel multiple-relaxation-time lattice Boltzmann method on general-purpose graphics processing units for the rapid and scalable computation of absolute permeability from high-resolution 3D micro-CT images, COMPUTATIONAL GEOSCIENCES, Vol: 22, Pages: 815-832, ISSN: 1420-0597
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- Citations: 30
Edery Y, Weitz D, Berg S, 2018, Surfactant Variations in Porous Media Localize Capillary Instabilities during Haines Jumps, PHYSICAL REVIEW LETTERS, Vol: 120, ISSN: 0031-9007
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- Citations: 28
Saxena N, Hofmann R, Alpak FO, et al., 2017, References and benchmarks for pore-scale flow simulated using micro-CT images of porous media and digital rocks, ADVANCES IN WATER RESOURCES, Vol: 109, Pages: 211-235, ISSN: 0309-1708
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- Citations: 83
Bartels W-B, Mahani H, Berg S, et al., 2017, Oil Configuration Under High-Salinity and Low-Salinity Conditions at Pore Scale: A Parametric Investigation by Use of a Single-Channel Micromodel, SPE JOURNAL, Vol: 22, Pages: 1362-1373, ISSN: 1086-055X
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- Citations: 87
Mahani H, Menezes R, Berg S, et al., 2017, Insights into the Impact of Temperature on the Wettability Alteration by Low Salinity in Carbonate Rocks, ENERGY & FUELS, Vol: 31, Pages: 7839-7853, ISSN: 0887-0624
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- Citations: 112
Schlueter S, Berg S, Li T, et al., 2017, Time scales of relaxation dynamics during transient conditions in two-phase flow, WATER RESOURCES RESEARCH, Vol: 53, Pages: 4709-4724, ISSN: 0043-1397
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- Citations: 44
Liu Z, Herring A, Arns C, et al., 2017, Pore-Scale Characterization of Two-Phase Flow Using Integral Geometry, TRANSPORT IN POROUS MEDIA, Vol: 118, Pages: 99-117, ISSN: 0169-3913
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- Citations: 65
Berg S, van Wunnik J, 2017, Shear rate determination from pore-scale flow fields, Transport in Porous Media, Vol: 117, Pages: 229-246, ISSN: 0169-3913
Aqueous solutions with polymer additives often used to improve the macroscopic sweep efficiency in oil recovery typically exhibit non-Newtonian rheology. In order to predict the Darcy-scale effective viscosity eff required for practical applications often, semi-empirical correlations such as the Cannella or Blake–Kozeny correlation are employed. These correlations employ an empirical constant (“C-factor”) that varies over three orders of magnitude with explicit dependency on porosity, permeability, fluid rheology and other parameters. The exact reasons for this dependency are not very well understood. The semi-empirical correlations are derived under the assumption that the porous media can be approximated by a capillary bundle for which exact analytical solutions exist. The effective viscosity eff( Darcy) as a function of flow velocity is then approximated by a cross-sectional average of the local flow field resulting in a linear relationship between shear rate and flow velocity. Only with such a linear relationship, the effective viscosity can be expressed as a function of an average flow rate instead of an average shear rate. The local flow field, however, does in general not exhibit such a linear relationship. Particularly for capillary tubes, the velocity is maximum at the center, while the shear rate is maximum at the tube wall indicating that shear rate and flow velocity are rather anti-correlated. The local flow field for a sphere pack is somewhat more compatible with a linear relationship. However, as hydrodynamic flow simulations (using Newtonian fluids for simplicity) performed directly on pore-scale resolved digital images suggest, flow fields for sandstone rock fall between the two limiting cases of capillary tubes and sphere packs and do in general not exhibit a linear relationship between shear rate and flow velocity. This indicates that some of the shortcomings of the semi-empirical correlations originate from the approximat
Armstrong RT, McClure JE, Berill MA, et al., 2017, Flow Regimes During Immiscible Displacement, PETROPHYSICS, Vol: 58, Pages: 10-18, ISSN: 1529-9074
Mahani H, Keya AL, Berg S, et al., 2017, Electrokinetics of Carbonate/Brine Interface in Low-Salinity Waterflooding: Effect of Brine Salinity, Composition, Rock Type, and pH on ζ-Potential and a Surface-Complexation Model, SPE JOURNAL, Vol: 22, Pages: 53-68, ISSN: 1086-055X
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- Citations: 18
Bartels W-B, Rucker M, Berg S, et al., 2017, Fast X-Ray Micro-CT Study of the Impact of Brine Salinity on the Pore-Scale Fluid Distribution During Waterflooding, PETROPHYSICS, Vol: 58, Pages: 36-47, ISSN: 1529-9074
Rücker M, Bartels WB, Boone MA, et al., 2017, Pore-scale processes in amott spontaneous imbibition tests
We observed the redistribution of the oil phase in the pore space of the rock in real-time in water-wet and mixed-wet (by ageing in crude oil) carbonate samples. During the imbibition of the water phase both, pore filling events with connection to the surrounding brine as well as snap-off events connected through water films only were detected. The distribution of the oil in different pore sizes as well as the different event types help to identify the wettability state of the system and understand how pore scale processes lead to the oil production at the larger scale.
Dickinson LR, Suijkerbuijk BMJM, Berg S, et al., 2016, Atomic Force Spectroscopy Using Colloidal Tips Functionalized with Dried Crude Oil: A Versatile Tool to Investigate Oil-Mineral Interactions, ENERGY & FUELS, Vol: 30, Pages: 9193-9202, ISSN: 0887-0624
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- Citations: 20
Armstrong RT, McClure JE, Berrill MA, et al., 2016, Beyond Darcy's law: The role of phase topology and ganglion dynamics for two-fluid flow, PHYSICAL REVIEW E, Vol: 94, ISSN: 2470-0045
Armstrong RT, Berg S, Dinariev O, et al., 2016, Modeling of Pore-Scale Two-Phase Phenomena Using Density Functional Hydrodynamics, TRANSPORT IN POROUS MEDIA, Vol: 112, Pages: 577-607, ISSN: 0169-3913
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- Citations: 37
Schlueter S, Berg S, Rucker M, et al., 2016, Pore-scale displacement mechanisms as a source of hysteresis for two-phase flow in porous media, WATER RESOURCES RESEARCH, Vol: 52, Pages: 2194-2205, ISSN: 0043-1397
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- Citations: 127
Berg S, Rücker M, Ott H, et al., 2016, Connected pathway relative permeability from pore-scale imaging of imbibition, Advances in Water Resources, Vol: 90, Pages: 24-35, ISSN: 1872-9657
Pore-scale images obtained from a synchrotron-based X-ray computed micro-tomography (µCT) imbibition experiment in sandstone rock were used to conduct Navier–Stokes flow simulations on the connected pathways of water and oil phases. The resulting relative permeability was compared with steady-state Darcy-scale imbibition experiments on 5 cm large twin samples from the same outcrop sandstone material. While the relative permeability curves display a large degree of similarity, the endpoint saturations for the µCT data are 10% in saturation units higher than the experimental data. However, the two datasets match well when normalizing to the mobile saturation range. The agreement is particularly good at low water saturations, where the oil is predominantly connected. Apart from different saturation endpoints, in this particular experiment where connected pathway flow dominates, the discrepancies between pore-scale connected pathway flow simulations and Darcy-scale steady-state data are minor overall and have very little impact on fractional flow. The results also indicate that if the pore-scale fluid distributions are available and the amount of disconnected non-wetting phase is low, quasi-static flow simulations may be sufficient to compute relative permeability. When pore-scale fluid distributions are not available, fluid distributions can be obtained from a morphological approach, which approximates capillary-dominated displacement. The relative permeability obtained from the morphological approach compare well to drainage steady state whereas major discrepancies to the imbibition steady-state experimental data are observed. The morphological approach does not represent the imbibition process very well and experimental data for the spatial arrangement of the phases are required. Presumably for modeling imbibition relative permeability an approach is needed that captures moving liquid-liquid interfaces, which requires viscous and capillary forces si
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