Publications
544 results found
Krevor SC, Blunt MJ, Benson SM, et al., 2015, Capillary trapping for geologic carbon dioxide storage - From pore scale physics to field scale implications, International Journal of Greenhouse Gas Control, Vol: 40, Pages: 221-237, ISSN: 1750-5836
A significant amount of theoretical, numerical and observational work has been published focused on various aspects of capillary trapping in CO2 storage since the IPCC Special Report on Carbon Dioxide Capture and Storage (2005). This research has placed capillary trapping in a central role in nearly every aspect of the geologic storage of CO2. Capillary, or residual, trapping – where CO2 is rendered immobile in the pore space as disconnected ganglia, surrounded by brine in a storage aquifer – is controlled by fluid and interfacial physics at the size scale of rock pores. These processes have been observed at the pore scale in situ using X-ray microtomography at reservoir conditions. A large database of conventional centimetre core scale observations for flow modelling are now available for a range of rock types and reservoir conditions. These along with the pore scale observations confirm that trapped saturations will be at least 10% and more typically 30% of the pore volume of the rock, stable against subsequent displacement by brine and characteristic of water-wet systems. Capillary trapping is pervasive over the extent of a migrating CO2 plume and both theoretical and numerical investigations have demonstrated the first order impacts of capillary trapping on plume migration, immobilisation and CO2 storage security. Engineering strategies to maximise capillary trapping have been proposed that make use of injection schemes that maximise sweep or enhance imbibition. National assessments of CO2 storage capacity now incorporate modelling of residual trapping where it can account for up to 95% of the storage resource. Field scale observations of capillary trapping have confirmed the formation and stability of residually trapped CO2 at masses up to 10,000 tons and over time scales of years. Significant outstanding uncertainties include the impact of heterogeneity on capillary immobilisation and capillary trapping in mixed-wet systems. Overall capillary trapp
Menke HP, Bijeljic BR, Andrew MG, et al., 2015, Dynamic three-dimensional pore-scale imaging of reaction in a carbonate at reservoir conditions, Environmental Science and Technology, Vol: 49, Pages: 4407-4414, ISSN: 1068-4980
© 2015 American Chemical Society. Quantifying CO<inf>2</inf> transport and average effective reaction rates in the subsurface is essential to assess the risks associated with underground carbon capture and storage. We use X-ray microtomography to investigate dynamic pore structure evolution in situ at temperatures and pressures representative of underground reservoirs and aquifers. A 4 mm diameter Ketton carbonate core is injected with CO<inf>2</inf>-saturated brine at 50°C and 10 MPa while tomographic images are taken at 15 min intervals with a 3.8 μm spatial resolution over a period of 2<sup>1</sup>/<inf>2</inf> h. An approximate doubling of porosity with only a 3.6% increase in surface area to volume ratio is measured from the images. Pore-scale direct simulation and network modeling on the images quantify an order of magnitude increase in permeability and an appreciable alteration of the velocity field. We study the uniform reaction regime, with dissolution throughout the core. However, at the pore scale, we see variations in the degree of dissolution with an overall reaction rate which is approximately 14 times lower than estimated from batch measurements. This work implies that in heterogeneous rocks, pore-scale transport of reactants limits dissolution and can reduce the average effective reaction rate by an order of magnitude.
Andrew MG, Bijeljic BR, Blunt MJB, 2015, Reservoir condition pore-scale imaging of multiple fluid phases using X-ray microtomography, Journal of Visualized Experiments, ISSN: 1940-087X
X-ray microtomography was used to image, at a resolution of 6.6 µm, the pore-scale arrangement of residual carbon dioxide ganglia in the pore-space of a carbonate rock at pressures and temperatures representative of typical formations used for CO2 storage. Chemical equilibrium between the CO2, brine and rock phases was maintained using a high pressure high temperature reactor, replicating conditions far away from the injection site. Fluid flow was controlled using high pressure high temperature syringe pumps. To maintain representative in-situ conditions within the micro-CT scanner a carbon fiber high pressure micro-CT coreholder was used. Diffusive CO2 exchange across the confining sleeve from the pore-space of the rock to the confining fluid was prevented by surrounding the core with a triple wrap of aluminum foil. Reconstructed brine contrast was modeled using a polychromatic x-ray source, and brine composition was chosen to maximize the three phase contrast between the two fluids and the rock. Flexible flow lines were used to reduce forces on the sample during image acquisition, potentially causing unwanted sample motion, a major shortcoming in previous techniques. An internal thermocouple, placed directly adjacent to the rock core, coupled with an external flexible heating wrap and a PID controller was used to maintain a constant temperature within the flow cell. Substantial amounts of CO2 were trapped, with a residual saturation of 0.203 ± 0.013, and the sizes of larger volume ganglia obey power law distributions, consistent with percolation theory.
Vitoonkijvanich S, AlSofi AM, Blunt MJ, 2015, Design of foam-assisted carbon dioxide storage in a North Sea aquifer using streamline-based simulation, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 33, Pages: 113-121, ISSN: 1750-5836
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- Citations: 23
Kuznetsov D, Cotterill S, Giddins MA, et al., 2015, Low-salinity waterflood simulation: Mechanistic and phenomenological models, Pages: 537-555
This paper describes a simulation study of the low-salinity effect in sandstone reservoirs. The proposed mechanistic model allows differentiation of water composition effects and includes multi-ionic exchange and double layer expansion. The manifestation of these effects can be observed in coreflood experiments. We define a set of chemical reactions, to describe the contribution of van der Waals forces, ligand exchange, and cation bridging to mobilization of residual oil. The reaction set is simplified by incorporating wettability weighting coefficients that reflect the contribution of different adsorbed ions to the wettability of the rock. Changes in wettability are accounted for by interpolation of the relative permeability and capillary pressure curves between the low and high salinity sets. We also construct and test simplified phenomenological models, one relating the change of the relative permeability to the concentration of a dissolved salinity tracer and another one to the concentration of a single adsorbed tracer. The full mechanistic model, with multiple ion tracking, is in good qualitative agreement with experimental data reported in the literature. A very close agreement with the mechanistic model was obtained for a coreflood simulation using single tracer phenomenological models. The similarity of the results is explained by the fact that the most critical factor influencing the flow behavior was the function used to interpolate between the oil- and water-wet sets of saturation curves. Similar interpolation functions in different models lead to similar oil recovery predictions. This study has developed a detailed chemical reaction model that captures both multicomponent ion exchange and double layer expansion effects, and can be used to improve understanding of low-salinity recovery mechanisms by analyzing their relative contributions. The approach of matching a tracer model to a detailed mechanistic model promises a route to the development of simplif
Masalmeh SK, Jing X, Roth S, et al., 2015, Towards predicting multi-phase flow in porous media using digital rock physics: Workflow to test the predictive capability of pore-scale modeling
Digital rock physics (DRP) has gained significant development in the last decade. At its current state, in general DRP cannot yet reliably a priori predict two-phase fluid flow properties without knowledge of wettability/contact angles, especially for non-water-wet rock. Prediction of two phase flow properties becomes even more challenging for carbonate rocks which are rarely water-wet and have a complex pore structure. The two main challenges are to model pore geometries and size distributions at a representative elementary volume (REV) and the representation of wettability. Advances in micro- and nano-CT imaging and computer capability may help solve the first challenge, although the translation from images to model input parameters and REV consideration remains a research topic. However, wettability distribution (as an input parameter) cannot be predicted and will remain to be the most significant problem in attempting to predict multi-phase flow properties. In this paper, we study the use of pore-scale imaging and modeling (DRP) to predict relative permeability curves. We recommend that we should shift focus from a priori prediction of fluid-flow properties, to instead investigate how much experimental special core analysis (SCAL) and imaging data is required as input to calibrate or constrain the model before computing two- or three-phase flow properties for field applications. In this paper we will focus on two main issues: 1- The role of DRP and how it can complement SCAL data, 2- How can we improve the predictive capability of DRP through the use of imaging data combined with benchmarking and tuning to match core-scale measurements. A case study and a recommended workflow to integrate DRP in the whole SCAL procedure is presented. In the case study, the measured primary drainage capillary pressure is used to modify the pore size distribution inferred from multi-scale imaging, while the waterflood capillary pressure is used to estimate contact angle. Then wate
Pereira Nunes JP, Bijeljic B, Blunt MJ, 2015, Simulating petrophysical time-lapse in carbonate rocks at the pore-scale, Pages: 1200-1204
The increase in CO2-injection activities for CCS and EOR has led the industry and the academia to explore the implications of rock-fluid interactions for full-scale development projects of carbonate reservoirs. Digital rock physics is a very promising technology to characterize sedimentary rocks. It provides invaluable information that helps the development of sensible upscaling techniques for both reactive and non-reactive flow in porous media. We present a streamline-based pore-scale simulation method capable of predicting the evolution of porosity and permeability of carbonate rocks subjected to CO2 injection at reservoir conditions. The method runs directly on the voxels of high resolution tomographic images of carbonate samples. We validate the method using dynamic imaging data of CO2 injection at in situ conditions and we show that core-scale reaction rates are lower than laboratory (batch) rates due to the heterogeneity of the flow field at the pore-scale. Potential impacts for reservoir development and monitoring will be discussed.
Petvipusit KR, Elsheikh AH, King PR, et al., 2015, An efficient optimisation technique using adaptive spectral high-dimensional model representation: Application to CO<inf>2</inf> sequestration strategies, Pages: 1576-1595
The successful operation of CO2 sequestration relies on designing optimal injection strategies that maximise economic performance while guaranteeing long-term storage security. Solving this optimisation problem is computationally demanding. Hence, we propose an efficient surrogate-assisted optimisation technique with three novel aspects: (1) it relies on an ANOVA-like decomposition termed High- Dimensional Model Representation; (2) component-wise interactions are approximated with adaptive sparse grid interpolation; and (3) the surrogate is adaptively partitioned closer to the optimal solution within the optimisation iteration. A High-Dimensional Model Representation (HDMR) represents the model output as a hierarchical sum of component functions with different input variables. This structure enables us to select influential lower-order functions that impact the model output for efficient reduced-order representation of the model. In this work, we build the surrogate based on the HDMR expansion and make use of Sobol indices to adaptively select the significant terms. Then, the selected lower-order terms are approximated by using the Adaptive Sparse Grid Interpolation (ASGI) approach. Once the HDMR is built, a global optimizer is run to decide: 1) the domain shrinking criteria; and 2) the centre point for the next HDMR building. Therefore, this proposed technique is called a walking Cut-AHDMR as it shrinks the search domain while balancing the trade-off between exploration and exploitation of the optimisation algorithm. The proposed technique is evaluated on a benchmark function and on the PUNQ-S3 reservoir model. Based on our numerical results, the walking Cut-AHDMR is a promising approach: not only does it require substantially fewer forward runs in building the surrogate of high dimension but it also effectively guides the search towards the optimal solution. The proposed method provides an efficient tool to find optimal injection schedules that maximise economic v
Seers TD, Hodgetts D, Andrew M, et al., 2015, From digital outcrops to digital rocks - Multiscale characterization of structural heterogeniety within porous sandstones, Pages: 4027-4031
Large scale faults are important structural elements within many conventional clastic reservoirs, acting as potential conduits, baffles or barriers to hydrocarbon or CO2 migration. Though inconspicuous within most seismic tomography datasets, smaller subsidiary faults, commonly within the damage zones of parent structures, may also play an important role. Within high porosity sandstones these smaller faults typically form through cataclasis (grain reorganisation, dilation, isovolumetric strain, grain fracturing and crushing), creating thin, tabular low permeability zones which serve to compartmentalize the reservoir. Though microfaults within high porosity sandstones are commonly assumed to adversely impact upon hydrocarbon production and CO2 injection, little is known about their volumetric properties at the continuum scale (esp. volumetric intensity), or the pore-scale processes which govern their capacity to trap mobile geofluids. In this paper, we seek to address these uncertainties, using a novel outcrop constrained discrete fracture network modelling code to obtain estimates of fault volumetric intensity, and employing high pressure-temperature synchrotron tomography to resolve pore-scale multiphase flow across a single cataclastic fault. The coupled studies indicate that whilst fault rocks may form a major fraction of a given rock mass, the presence of intra-fault capillary heterogeneity may significantly reduce their capacity to restrict the migration of geofluids.
Masalmeh SK, Jing X, Roth S, et al., 2015, Towards predicting multi-phase flow in porous media using digital rock physics: Workflow to test the predictive capability of pore-scale modeling
Copyright 2015, Society of Petroleum Engineers. Digital rock physics (DRP) has gained significant development in the last decade. At its current state, in general DRP cannot yet reliably a priori predict two-phase fluid flow properties without knowledge of wettability/contact angles, especially for non-water-wet rock. Prediction of two phase flow properties becomes even more challenging for carbonate rocks which are rarely water-wet and have a complex pore structure. The two main challenges are to model pore geometries and size distributions at a representative elementary volume (REV) and the representation of wettability. Advances in micro- and nano-CT imaging and computer capability may help solve the first challenge, although the translation from images to model input parameters and REV consideration remains a research topic. However, wettability distribution (as an input parameter) cannot be predicted and will remain to be the most significant problem in attempting to predict multi-phase flow properties. In this paper, we study the use of pore-scale imaging and modeling (DRP) to predict relative permeability curves. We recommend that we should shift focus from a priori prediction of fluid-flow properties, to instead investigate how much experimental special core analysis (SCAL) and imaging data is required as input to calibrate or constrain the model before computing two- or three-phase flow properties for field applications. In this paper we will focus on two main issues: 1- The role of DRP and how it can complement SCAL data, 2- How can we improve the predictive capability of DRP through the use of imaging data combined with benchmarking and tuning to match core-scale measurements. A case study and a recommended workflow to integrate DRP in the whole SCAL procedure is presented. In the case study, the measured primary drainage capillary pressure is used to modify the pore size distribution inferred from multi-scale imaging, while the waterflood capillary press
Menke HP, Andrew MG, Bijeljic B, et al., 2015, Dynamic pore-scale imaging of reaction in heterogeneous carbonates using a synchrotron Pink Beam, Pages: 3152-3156
We present an experimental method whereby 'Pink Beam' synchrotron radiation is used in X-ray microtomography to investigate pore structure changes during supercritical CO2 injection in very heterogeneous carbonates at high temperatures and pressures.The raw images were binarized and the magnitude of dissolution was identified on a voxel-by-voxel basis. This information was used to extract pore-by-pore dissolution data.
Iglauer S, Paluszny A, Blunt MJ, 2015, Simultaneous oil recovery and residual gas storage: A pore-level analysis using in situ X-ray micro-tomography (vol 103, pg 905, 2013), FUEL, Vol: 139, Pages: 780-780, ISSN: 0016-2361
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- Citations: 2
Ranaee E, Porta GM, Riva M, et al., 2014, Prediction of three-phase oil relative permeability through a sigmoid-based model, Journal of Petroleum Science and Engineering, Vol: 126, Pages: 190-200, ISSN: 1873-4715
Ott H, Andrew M, Snippe J, et al., 2014, Microscale solute transport and precipitation in complex rock during drying, Geophysical Research Letters, Vol: 41, Pages: 8369-8376, ISSN: 1944-8007
Raeini AQ, Blunt MJ, Bijeljic B, 2014, Direct simulations of two-phase flow on micro-CT images of porous media and upscaling of pore-scale forces, Advances in Water Resources, Vol: 74, Pages: 116-126, ISSN: 0309-1708
Pore-scale forces have a significant effect on the macroscopic behaviour of multiphase flow through porous media. This paper studies the effect of these forces using a new volume-of-fluid based finite volume method developed for simulating two-phase flow directly on micro-CT images of porous media. An analytical analysis of the relationship between the pore-scale forces and the Darcy-scale pressure drops is presented. We use this analysis to propose unambiguous definitions of Darcy-scale viscous pressure drops as the rate of energy dissipation per unit flow rate of each phase, and then use them to obtain the relative permeability curves. We show that this definition is consistent with conventional laboratory/field measurements by comparing our predictions with experimental relative permeability. We present single and two-phase flow simulations for primary oil injection followed by water injection on a sandpack and a Berea sandstone. The two-phase flow simulations are presented at different capillary numbers which cover the transition from capillary fingering at low capillary numbers to a more viscous fingering displacement pattern at higher capillary numbers, and the effect of capillary number on the relative permeability curves is investigated. Overall, this paper presents a new finite volume-based methodology for the detailed analysis of two-phase flow directly on micro-CT images of porous media and upscaling of the results to the Darcy scale.
AlSofi AM, Blunt MJ, 2014, Polymer flooding design and optimization under economic uncertainty, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 124, Pages: 46-59, ISSN: 0920-4105
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- Citations: 26
Siavashi M, Blunt MJ, Raisee M, et al., 2014, Three-dimensional streamline-based simulation of non-isothermal two-phase flow in heterogeneous porous media, COMPUTERS & FLUIDS, Vol: 103, Pages: 116-131, ISSN: 0045-7930
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- Citations: 43
Andrew M, Bijeljic B, Blunt MJ, 2014, Pore-by-pore capillary pressure measurements using X-ray microtomography at reservoir conditions: Curvature, snap-off, and remobilization of residual CO<sub>2</sub>, WATER RESOURCES RESEARCH, Vol: 50, Pages: 8760-8774, ISSN: 0043-1397
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- Citations: 112
Leal AMM, Blunt MJ, LaForce TC, 2014, A chemical kinetics algorithm for geochemical modelling, Applied Geochemistry, Vol: 55, Pages: 46-61, ISSN: 1872-9134
Petvipusit KR, Elsheikh AH, Laforce TC, et al., 2014, Robust optimisation of CO<sub>2</sub> sequestration strategies under geological uncertainty using adaptive sparse grid surrogates, COMPUTATIONAL GEOSCIENCES, Vol: 18, Pages: 763-778, ISSN: 1420-0597
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- Citations: 21
Kang PK, de Anna P, Nunes JP, et al., 2014, Pore-scale intermittent velocity structure underpinning anomalous transport through 3-D porous media, GEOPHYSICAL RESEARCH LETTERS, Vol: 41, Pages: 6184-6190, ISSN: 0094-8276
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- Citations: 127
Siena M, Guadagnini A, Riva M, et al., 2014, Statistical scaling of pore-scale Lagrangian velocities in natural porous media, PHYSICAL REVIEW E, Vol: 90, ISSN: 1539-3755
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- Citations: 17
Amaechi B, Iglauer S, Pentland CH, et al., 2014, An Experimental Study of Three-Phase Trapping in Sand Packs, TRANSPORT IN POROUS MEDIA, Vol: 103, Pages: 421-436, ISSN: 0169-3913
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- Citations: 11
Andrew M, Bijeljic B, Blunt MJ, 2014, Pore-scale contact angle measurements at reservoir conditions using X-ray microtomography, Advances in Water Resources, Vol: 68, Pages: 24-31, ISSN: 0309-1708
Contact angle is a principal control of the flow of multiple fluid phases through porous media; however its measurement on other than flat surfaces remains a challenge. A new method is presented for the measurement of the contact angle between immiscible fluids at the pore scale at reservoir conditions (10 MPa and 50 °C) inside a quarry limestone through the use of X-ray microtomography. It is applied to a super-critical CO2–brine–carbonate system by resampling the micro-CT data onto planes orthogonal to the contact lines, allowing for vectors to be traced along the grain surface and the CO2–brine interface. A distribution of contact angles ranging from 35° to 55° is observed, indicating that the CO2–brine–carbonate system is weakly water-wet. This range of contact angles can be understood as the result of contact angle hysteresis and surface heterogeneity on a range of length scales. Surface heterogeneity is examined by comparison of micro-CT results with optical thin sections and SEM images.
Leal AMM, Blunt MJ, LaForce TC, 2014, Efficient chemical equilibrium calculations for geochemical speciation and reactive transport modelling, GEOCHIMICA ET COSMOCHIMICA ACTA, Vol: 131, Pages: 301-322, ISSN: 0016-7037
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- Citations: 47
Andrew M, Bijeljic B, Blunt MJ, 2014, Pore-scale imaging of trapped supercritical carbon dioxide in sandstones and carbonates, International Journal of Greenhouse Gas Control, Vol: 22, Pages: 1-14, ISSN: 1750-5836
Geological carbon dioxide storage must be designed such that the CO2 cannot escape from the rock formation into which it is injected, and often simple stratigraphic trapping is insufficient. CO2 can be trapped in the pore space as droplets surrounded by water through capillary trapping. X-ray microtomography was used to image, at a resolution of 6.6 μm, the pore-scale arrangement of these droplets in three carbonates and two sandstones. The pressures and temperatures in the pore space were representative of typical storage formations, while chemical equilibrium was maintained between the CO2, brine and rock phases to replicate conditions far away from the injection site. In each sample substantial amounts of CO2 were trapped, with the efficiency of trapping being insensitive to pore-morphology and chemistry. Apart from in one extremely well connected sample, the size distribution of residual ganglia larger than 105 voxel3 obey power law distributions with exponents broadly consistent with percolation theory over two orders of magnitude. This work shows that residual trapping can be used to locally immobilise CO2 in a wide range of rock types.
Amin SM, Weiss DJ, Blunt MJ, 2014, Reactive transport modelling of geologic CO<sub>2</sub> sequestration in saline aquifers: The influence of pure CO<sub>2</sub> and of mixtures of CO<sub>2</sub> with CH<sub>4</sub> on the sealing capacity of cap rock at 37 °C and 100 bar, CHEMICAL GEOLOGY, Vol: 367, Pages: 39-50, ISSN: 0009-2541
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- Citations: 35
Guadagnini A, Blunt MJ, Riva M, et al., 2014, Statistical Scaling of Geometric Characteristics in Millimeter Scale Natural Porous Media, TRANSPORT IN POROUS MEDIA, Vol: 101, Pages: 465-475, ISSN: 0169-3913
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- Citations: 13
Nunes JPP, Raeini AQ, Bijeljic B, et al., 2014, Simulation of carbonate dissolution at the porescale using a streamline method, Pages: 2549-2553
Carbon dioxide is currently being injected into saline aquifers and depleted oil and gas reservoirs with both enhanced oil recovery (EOR) and carbon capture and storage (CCS) purposes. The injected CO2 in contact with the reservoir fluids creates an acidic mixture that can potentially react with the host rock causing changes in the petrophysical properties of the reservoir. From the experimental point of view much work has been recently published in the scientific literature about the impact of acidic brine in carbonate reservoirs. These laboratory results indicate that strong rock-fluid interactions may occur, however, pore-scale models capable of predicting how the petrophysical changes associated with these reactions can be related to transport properties are yet to be developed. The recent increase in computational power and tomographic capability made possible the acquisition of high resolution images of heterogeneous carbonates that are very suitable to study in detail the flow and transport properties of such rocks. In this paper we demonstrate how micro-CT images of carbonate rocks can be used to model reactive transport at the pore scale. We apply a particle tracking algorithm based on a pore-scale streamline tracing method to simulate carbonate dissolution.
Menke HP, Bijeljic B, Andrew MG, et al., 2014, Dynamic pore-scale imaging of reactive transport in heterogeneous carbonates at reservior conditions, Pages: 2554-2558
Four carbonate rock types were studied, two relatively homogeneous carbonates, Ketton and Mt. Gambier, and two very heterogeneous carbonates, Estalliades and Portland Basebed. Each rock type was imaged using dynamic x-ray microtomography under the same reservoir and flow conditions to gain insight into the impact of heterogeneity. A 4-mm carbonate core was injected with CO2-saturated brine at 10 MPa and 50oC for 2 hours. Depending on sample heterogeneity and X-ray source, tomographic images were taken at between 30-second and 20-minute time-resolutions and a 4-micron spatial resolution during injection. Changes in porosity, permeability, and structure were obtained and a pore-throat network was extracted. Furthermore, pore-scale flow modelling was performed directly on the binarized image and used to track velocity distributions as the pore network evolved.
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