Publications
154 results found
Bartels WB, Mahani H, Berg S, et al., 2016, Low salinity flooding LSF in sandstones at pore scale: Micro-model development and investigation
Low salinity waterflooding (LSF) is receiving increased interest as a promising method to improve oil recovery efficiency. Most of the literature agrees that on the Darcy scale, LSF can be regarded as a wettability modification process leading to a more water-wet state, although no general consensus on the microscopic mechanisms has been reached. While wettability alteration may be a valid causal mechanism also on the pore scale, it is currently unclear how oil that detaches from mineral surfaces within individual pores connects to an oil bank or finds its way to a producer. In order to establish a link between the pore scale and the Darcy scale description, the flow dynamic at the scale of (networks of) multiple pores should be investigated. One of the main challenges in addressing phenomena on this intermediate "pore network" scale is to design a model system representative for natural rock. The model system should allow for a systematic investigation of influencing parameters with pore-scale resolution whilst simultaneously being large enough to capture larger length scale effects like saturation changes and the mobilization and connection of oil ganglia. In this paper, we use micro-models functionalized with active clay minerals as model system to study the low salinity effect (LSE) on the pore scale. A new method was devised to deposit clays in the micro-model. Clay suspensions were made by mixing natural clays (Montmorillonite) with isopropyl alcohol (IPA) and injected into optically transparent 2D glass micro-models. By drying the micro-model, the clay particles are deposited and stick naturally to the glass surfaces and remain attached even under flow of high salinity (HS) and low salinity (LS) brines. In a parametric study the dependence of the LSE on the type of oil (crude oil versus n-decane), the presence of clay particles and ageing was investigated. Our results show that the system is responsive to LS brine as the effective contact angle of c
Hilfer R, Armstrong RT, Berg S, et al., 2015, Capillary saturation and desaturation, PHYSICAL REVIEW E, Vol: 92, ISSN: 1539-3755
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- Citations: 35
Ruecker M, Berg S, Armstrong RT, et al., 2015, From connected pathway flow to ganglion dynamics, GEOPHYSICAL RESEARCH LETTERS, Vol: 42, Pages: 3888-3894, ISSN: 0094-8276
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- Citations: 181
Schmatz J, Urai JL, Berg S, et al., 2015, Nanoscale imaging of pore-scale fluid-fluid-solid contacts in sandstone, GEOPHYSICAL RESEARCH LETTERS, Vol: 42, Pages: 2189-2195, ISSN: 0094-8276
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- Citations: 74
Berg S, Oedai S, van Batenburg DW, et al., 2015, Visualization of ASP Coreflood Experiments Using X-ray CT Imaging, IOR 2015 - 18th European Symposium on Improved Oil Recovery, Publisher: EAGE Publications BV, ISSN: 2214-4609
Armstrong RT, Evseev N, Koroteev D, et al., 2015, Modeling the velocity field during Haines jumps in porous media, ADVANCES IN WATER RESOURCES, Vol: 77, Pages: 57-68, ISSN: 0309-1708
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- Citations: 86
Mahani H, Keya AL, Berg S, et al., 2015, Insights into the Mechanism of Wettability Alteration by Low-Salinity Flooding (LSF) in Carbonates, ENERGY & FUELS, Vol: 29, Pages: 1352-1367, ISSN: 0887-0624
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- Citations: 328
Mahani H, Berg S, Ilic D, et al., 2015, Kinetics of Low-Salinity-Flooding Effect, SPE Journal, Vol: 20, Pages: 8-20, ISSN: 1086-055X
<jats:title>Summary</jats:title> <jats:p>Low-salinity waterflooding (LSF) is one of the least-understood enhanced-oil-recovery (EOR)/improved-oil-recovery (IOR) methods, and proper understanding of the mechanism(s) leading to oil recovery in this process is needed. However, the intrinsic complexity of the process makes fundamental understanding of the underlying mechanism(s) and the interpretation of laboratory experiments difficult. Therefore, we use a model system for sandstone rock of reduced complexity that consists of clay minerals (Na-montmorillonite) deposited on a glass substrate and covered with crude-oil droplets and in which different effects can be separated to increase our fundamental understanding. We focus particularly on the kinetics of oil detachment when exposed to low-salinity (LS) brine.</jats:p> <jats:p>The system is equilibrated first under high-salinity (HS) brine and then exposed to brines of varying (lower) salinity while the shape of the oil droplets is continuously monitored at high resolution, allowing for a detailed analysis of the contact angle and the contact area as a function of time. It is observed that the contact angle and contact area of oil with the substrate reach a stable equilibrium at HS brine and show a clear response to the LS brine toward less-oil-wetting conditions and ultimately detachment from the clay substrate. This behavior is characterized by the motion of the three-phase (oil/water/solid) contact line that is initially pinned by clay particles at HS conditions, and pinning decreases upon exposure to LS brine. This leads to a decrease in contact area and contact angle that indicates wettability alteration toward a more-water-wet state. When the contact angle reaches a critical value at approximately 40 to 50°, oil starts to detach from the clay. During detachment, most of the oil is released, but in some cases a small amount of oil residue is left behind
Mahani H, Berg S, Ilic D, et al., 2015, Kinetics of Low-Salinity-Flooding Effect, Publisher: SOC PETROLEUM ENG, ISSN: 1086-055X
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- Citations: 155
Van Batenburg DW, Berg S, Oedai S, et al., 2015, Visualization of oil mobilization in asp core floods using X-ray CT imaging
© Copyright 2015, Society of Petroleum Engineers. This paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant (AS) and Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Bentheimer sandstone outcrop material with diameters of approximately 7.55 cm and lengths of approximately 27 cm and one meter. Crude oil with in-situ viscosities of 1.3, 2.3 and 100 cP was used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process. In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance. One important observation from the experiments is that there exist a consistent fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The production following the clean oil bank (tail) observed in many ASP core floods is a consequence of the formation of this fingering zone. Effluent analyses conducted on the produced fluids from the long core experiments showed a sharp, rapid build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradu
Mahani H, Keya AL, Berg S, et al., 2015, Driving mechanism of low salinity flooding in carbonate rocks, Pages: 210-236
Several studies conducted mainly on the laboratory scale indicate that in carbonate rocks oil displacement can be influenced by the ionic composition of the brine, providing an opportunity to improve recovery by optimizing the brine mixture used in secondary or tertiary recovery. In industry this topic has been termed "low salinity flooding (LSF) in carbonates" while the underlying mechanisms are not very well understood. The increased oil recovery has been attributed to wettability alteration to a more water-wet state. However, in some studies a positive low salinity effect (LSE) has been ascribed to dissolution of rock, which occurs on the laboratory scale but due to equilibration of brine with carbonate minerals on larger length scales this is not relevant for the reservoir scale. Therefore, the objective of this paper is to gain a better understanding of the underlying mechanism(s) and investigate whether calcite dissolution is the primary mechanism of the LSE. We used a model system where the contact angle of crude oil deposited on planar surfaces coated with crushed carbonate rock particles was monitored as a function of brine composition. The approach is similar to the one published in Mahani et al. (2014) for sandstone rock, but instead of clay minerals we used carbonate materials from natural limestone and Silurian dolomite rocks. Furthermore, the effective surface charge at the oil-water and water-rock interfaces was quantified via zeta-potential measurements at several salinity and pH levels in order to establish a link between changes in the intermolecular interactions at the solid-liquid interface and the contact angle at the brine-oil-rock contact line, which is an indicator for wettability change. The impact of mineral dissolution was addressed by comparing the response to brines that were fully equilibrated (and hence dissolution suppressed) and the response to those completely under-saturated with calcium carbonate (leading to dissolution)
Mahani H, Levy Keya A, Berg S, et al., 2015, The effect of salinity, rock type and pH on the electrokinetics of carbonate-brine interface and surface complexation modeling, Pages: 331-355
Laboratory studies have shown that wettability of carbonate rock can be altered to a less oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (see Mahani et al. 2015b) suggests that a surface-charge change is likely to be the driving mechanism of the low salinity effect in carbonates. Various studies have already established the sensitivity of carbonate surface charge to brine salinity, pH and potential-determining ions in brines. However, it has been less investigated i) whether different types of carbonate reservoir rocks exhibit different electrokinetic properties, ii) how the rocks react to reservoir-relevant brine as well as successive brine dilution and iii) how the surface charge behavior at different salinities and pH can be explained. This paper presents a comparative study aimed at gaining more insights into the electrokinetics of different types of carbonate rock. This is achieved by zeta-potential measurements on Iceland spar calcite and three reservoir-related rocks-middle-eastern limestone, Stevns Klint chalk and Silurian dolomite outcrop-over a wide range of salinity, brine composition and pH. With a view to arriving at a more tractable approach, a surface complexation model implemented in PHREEQC is developed to relate our understanding of the surface reactions to measured zeta-potentials. The trends in the relationships between zeta-potentials on one hand and salinity and pH on the other were quite similar for different types of rock. For all cases, the surface-charge was found to be positive in high-salinity formation water, which should increase oil-wetting. The zeta-potential successively decreased towards negative values when the brine salinity was lowered to seawater level and diluted seawater. At all salinities, the zeta-potential showed a strong dependence on pH, with positive slope with pH which remained so even with excessive dilution. The sensitivity of the zeta-potential to pH-change was ofte
Van Batenburg DW, Berg S, Oedai S, et al., 2015, Visualisation of light oil mobilisation in ASP core floods using X-Ray CT imaging, Pages: 1027-1045
This paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Berea sandstone outcrop material with diameters of approximately 7.55 cm and lengths of 27.5 and 99 cm. Two light crude oils with in-situ viscosities of 1.3 cP and 3.2 cP were used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process. In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance. One important observation from the experiments is that there exist a typical fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The tail production observed in many ASP core floods is a consequence of the formation of this fingering zone. Effluent analyses conducted on the produced fluids from the long core experiments showed an instantaneous build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail production. Another important observation is that a characteristic self-simi
Van Batenburg DW, Berg S, Oedai S, et al., 2015, Visualization of oil mobilization in asp core floods using X-ray CT imaging
This paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant (AS) and Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Bentheimer sandstone outcrop material with diameters of approximately 7.55 cm and lengths of approximately 27 cm and one meter. Crude oil with in-situ viscosities of 1.3, 2.3 and 100 cP was used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process. In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance. One important observation from the experiments is that there exist a consistent fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The production following the clean oil bank (tail) observed in many ASP core floods is a consequence of the formation of this fingering zone. Effluent analyses conducted on the produced fluids from the long core experiments showed a sharp, rapid build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail p
Berg S, Armstrong RT, Georgiadis A, et al., 2014, Onset of Oil Mobilization and Nonwetting-Phase Cluster-Size Distribution, Petrophysics, ISSN: 1529-9074
Armstrong RT, Ott H, Georgiadis A, et al., 2014, Subsecond pore-scale displacement processes and relaxation dynamics in multiphase flow, Water Resources Research, Vol: 50, Pages: 9162-9176, ISSN: 0043-1397
With recent advances at X‐ray microcomputed tomography (μCT) synchrotron beam lines, it is now possible to study pore‐scale flow in porous rock under dynamic flow conditions. The collection of four‐dimensional data allows for the direct 3‐D visualization of fluid‐fluid displacement in porous rock as a function of time. However, even state‐of‐the‐art fast‐μCT scans require between one and a few seconds to complete and the much faster fluid movement occurring during that time interval is manifested as imaging artifacts in the reconstructed 3‐D volume. We present an approach to analyze the 2‐D radiograph data collected during fast‐μCT to study the pore‐scale displacement dynamics on the time scale of 40 ms which is near the intrinsic time scale of individual Haines jumps. We present a methodology to identify the time intervals at which pore‐scale displacement events in the observed field of view occur and hence, how reconstruction intervals can be chosen to avoid fluid‐movement‐induced reconstruction artifacts. We further quantify the size, order, frequency, and location of fluid‐fluid displacement at the millisecond time scale. We observe that after a displacement event, the pore‐scale fluid distribution relaxes to (quasi‐) equilibrium in cascades of pore‐scale fluid rearrangements with an average relaxation time for the whole cascade between 0.5 and 2.0 s. These findings help to identify the flow regimes and intrinsic time and length scales relevant to fractional flow. While the focus of the work is in the context of multiphase flow, the approach could be applied to many different μCT applications where morphological changes occur at a time scale less than that required for collecting a μCT scan.
Leu L, Berg S, Enzmann F, et al., 2014, Fast X-ray Micro-Tomography of Multiphase Flow in Berea Sandstone: A Sensitivity Study on Image Processing, TRANSPORT IN POROUS MEDIA, Vol: 105, Pages: 451-469, ISSN: 0169-3913
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- Citations: 105
Berg S, Safonov S, Dinariev O, et al., 2014, ENHANCED OIL RECOVERY USING DIGITAL CORE SAMPLE
Performing an enhanced oil recovery (EOR) injection operation in an oilfield having a reservoir may include obtaining a EOR scenarios that each include a chemical agent, obtaining a three-dimensional (3D) porous solid image of a core sample, and generating a 3D pore scale model from the 3D porous solid image. The core sample is a 3D porous medium representing a portion of the oilfield. The 3D pore scale model describes a physical pore structure in the 3D porous medium. Simulations are performed using the EOR scenarios to obtain simulation results by, for each EOR scenario, simulating, on the first 3D pore scale model, the EOR injection operation using the chemical agent specified by the EOR scenario to generate a simulation result. A comparative analysis of the simulation results is performed to obtain a selected chemical agent. Further, an operation is performed using the selected chemical agent
Armstrong RT, Georgiadis A, Ott H, et al., 2014, Critical capillary number: Desaturation studied with fast X- ray computed microtomography, GEOPHYSICAL RESEARCH LETTERS, Vol: 41, Pages: 55-60, ISSN: 0094-8276
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- Citations: 131
Koroteev D, Dinariev O, Evseev N, et al., 2013, Application of digital rock technology for chemical EOR screening, Pages: 480-491
Fast and reliable EOR process selection is a critical step in any EOR project. The digital rock (DR) approach jointly developed by Shell and SLB is aimed to be the smallest scale yet advanced EOR Pilot technology. In this document, we describe the application of DR technology for screening of different EOR mechanisms at pore-scale focused to enhance recovery from a particular reservoir formation. For EOR applications DR brings unique capabilities as it can fully describe different multiphase flow properties at different regimes. The vital part of the proposed approach is the high-efficient pore-scale simulation technology called Direct Hydrodynamics (DHD) Simulator. DHD is based on a density functional approach applied for hydrodynamics of complex systems. Currently, DHD is benchmarked against multiple analytical solutions and experimental tests and optimized for high performance (HPC) computing. It can handle many physical phenomena: multiphase compositional flows with phase transitions, different types of fluid-rock and fluid-fluid interactions with different types of fluid rheology. As an input data DHD uses 3D pore texture and composition of rocks with distributed micro-scale wetting properties and pore fluid model (PVT, rheology, diffusion coefficients, and adsorption model). In a particular case, the pore geometry comes from 3D X-ray microtomographic images of a rock sample. The fluid model is created from lab data on fluid characterization. The output contains the distribution of components, velocity and pressure fields at different stages of displacement process. Several case studies are demonstrated in this work and include comparative analysis of effectiveness of applications of different chemical EOR agents performed on digitized core samples. Copyright 2013, Society of Petroleum Engineers.
Mahani H, Berg S, Ilic D, et al., 2013, Kinetics of the low salinity waterflooding effect studied in a model system, Pages: 457-470
Low salinity waterflooding (LSF) provides an opportunity for improved oil recovery. However the complexity of the process makes both the fundamental understanding of the underlying mechanism(s) and the interpretation of laboratory experiments difficult. Therefore we use a model system for sandstone which consists of clay minerals deposited on a glass substrate and covered with crude oil droplets in order to study the kinetics of oil detachment when exposed to low salinity brine. The system is equilibrated first under high saline brine and then exposed to brines of varying (lower) salinity while the shape of the oil droplets is continuously monitored at high resolution allowing for a detailed analysis of the contact angle and the contact area as a function of time. We observe that the contact angle and contact area of oil with the substrate reach a stable equilibrium at high saline brine and show a clear response to the low salinity brine towards less oil wetting conditions and ultimately detachment from the clay (Na-montmorillonite) substrate. This behavior is characterized by the motion of the 3-phase (oil-water-solid) contact line which is initially pinned by clay particles at high salinity conditions and that pinning decreases upon exposure to low salinity brine leading to a decrease in contact area and contact angle which indicates wettability alteration towards a more water-wet state. When the contact angle reaches a critical value around 40-50°, oil drops start to detach from the clay. During detachment most of the oil is released but in some cases a small amount of oil residue is left behind on the clay substrate. Our results for different salinity levels indicate that the kinetics of this wettability change correlates with a simple buoyancy over adhesion force balance and has a time constant of hours to days; i.e., it takes longer than commonly assumed. The unexpectedly long time constant, i.e. longer than expected by diffusion alone, is compatible with
Armstrong RT, Berg S, 2013, Interfacial velocities and capillary pressure gradients during Haines jumps, PHYSICAL REVIEW E, Vol: 88, ISSN: 1539-3755
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- Citations: 151
Suijkerbuijk BMJM, Kuipers HPCE, Van Kruijsdijk CPJW, et al., 2013, The development of a workflow to improve predictive capability of low salinity response, Pages: 5480-5490
Low Salinity Waterflooding (LSF) is an emerging improved oil recovery (IOR) technology that has been shown to work in a number of cases, while sometimes - unexpectedly - no incremental oil production is observed. Industry has not yet reached consensus on the mechanism behind LSF, which precludes effective screening and prioritization of LSF candidate fields. In this paper a workflow is introduced that improves the way fields are screened for their LSF potential. It employs closely interlinked experiments and modeling work from the molecular scale to the macroscopic Darcy scale, thereby closing gaps that previously impeded the predictability of the low salinity effect. The new workflow is based on the notion that wettability is a surface phenomenon. Elucidation of the low salinity mechanism should thus not be based on bulk measurements, but rather on the characterization of surface compositions and forces. The main insights that follow from this work are: • Application of successful LSF leads to a wettability modification towards more water-wet, which is consistently observed at the atomic scale and at the core scale; • The surface alterations that occur during LSF correlate with macroscopic observations such as oil recovery from core plugs; • The time scales involved in wettability modification towards a more water-wet state can easily be long enough to lead to false negatives in common SCAL experiments; It is demonstrated that double layer expansion (DLE) is likely behind the low salinity mechanism, as processes involving cation exchange are expected to only occur long after breakthrough of the low salinity bank. Even though the workflow has been developed for LSF in sandstones, it is also being employed for LSF in carbonates. The fundamental insight that surface properties dominate the response does not only impact how LSF research and related SCAL experiments are being conducted, but impacts all other EOR processes relying on interfacial phenomena
Georgiadis A, Berg S, Makurat A, et al., 2013, Pore-scale micro-computed-tomography imaging: Nonwetting-phase cluster-size distribution during drainage and imbibition, Physical Review E, Vol: 88, ISSN: 1539-3755
We investigated the cluster-size distribution of the residual nonwetting phase in a sintered glass-bead porousmedium at two-phase flow conditions, by means of micro-computed-tomography (μCT) imaging with pore-scaleresolution. Cluster-size distribution functions and cluster volumes were obtained by image analysis for a range ofinjected pore volumes under both imbibition and drainage conditions; the field of view was larger thanthe porosity-based representative elementary volume (REV). We did not attempt to make a definition for atwo-phase REV but used the nonwetting-phase cluster-size distribution as an indicator. Most of the nonwettingphasetotal volume was found to be contained in clusters that were one to two orders of magnitude larger thanthe porosity-based REV. The largest observed clusters in fact ranged in volume from 65% to 99% of the entirenonwetting phase in the field of view. As a consequence, the largest clusters observed were statistically notrepresented and were found to be smaller than the estimated maximum cluster length. The results indicate thatthe two-phase REV is larger than the field of view attainable by μCT scanning, at a resolution which allows forthe accurate determination of cluster connectivity.
Berg S, Ott H, Klapp SA, et al., 2013, Real-time 3D imaging of Haines jumps in porous media flow, PROCEEDINGS OF THE NATIONAL ACADEMY OF SCIENCES OF THE UNITED STATES OF AMERICA, Vol: 110, Pages: 3755-3759, ISSN: 0027-8424
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- Citations: 435
Berg S, Oedai S, Ott H, 2013, Displacement and mass transfer between saturated and unsaturated CO<sub>2</sub>-brine systems in sandstone, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 12, Pages: 478-492, ISSN: 1750-5836
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- Citations: 132
Ott H, Berg S, 2013, Stability of CO<sub>2</sub>-brine primary drainage, International Conference on Greenhouse Gas Technologies (GHGT), Publisher: ELSEVIER SCIENCE BV, Pages: 4568-4574, ISSN: 1876-6102
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- Citations: 5
Berg S, Ott H, 2012, Stability of CO<sub>2</sub>-brine immiscible displacement, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 11, Pages: 188-203, ISSN: 1750-5836
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- Citations: 92
Ott H, de Kloe K, van Bakel M, et al., 2012, Core-flood experiment for transport of reactive fluids in rocks, REVIEW OF SCIENTIFIC INSTRUMENTS, Vol: 83, ISSN: 0034-6748
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- Citations: 33
Georgiadis A, Berg S, Maitland G, et al., 2012, Pore-Scale Micro-CT Imaging: Cluster Size Distribution during Drainage and Imbibition, 6TH TRONDHEIM CONFERENCE ON CO2 CAPTURE, TRANSPORT AND STORAGE, Vol: 23, Pages: 521-526, ISSN: 1876-6102
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- Citations: 7
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