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Hypothesis The change of wettability toward more water-wet by the injection of low salinity water can improve oil recovery from porous rocks, which is known as low salinity water flooding. To simulate this process at the pore-scale, we propose that the alteration in surface wettability mediated by thin water films which are below the resolution of simulation grid blocks has to be considered, as observed in experiments. This is modeled by a wettability alteration model based on rate-limited adsorption of ions onto the rock surface. Simulations The wettability alteration model is developed and incorporated into a lattice Boltzmann simulator which solves both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport. The model is validated against two experiments in the literature, then applied to 3D micro-CT images of a rock. Findings Our model correctly simulated the experimental observations caused by the slow wettability alteration driven by the development of water films. In the simulations on the 3D rock pore structure, a distinct difference in the mixing of high and low salinity water is observed between secondary and tertiary low salinity flooding, resulting in different oil recoveries.

Hypothesis: The wetting behaviour is a key property of a porous medium that controls hydraulic conductivity in multiphase flow. While many porous materials, such as hydrocarbon reservoir rocks, are initially wetted by the aqueous phase, surface active components within the non-wetting phase can alter the wetting state of the solid. Close to the saturation endpoints wetting phase fluid films of nanometre thickness impact the wetting alteration process. The properties of these films depend on the chemical characteristics of the system. Here we demonstrate that surface texture can be equally important and introduce a novel workflow to characterize the wetting state of a porous medium. Experiments: We investigated the formation of fluid films along a rock surface imaged with atomic force microscopy using zeta-potential measurements and a computational model for drainage. The results were compared to spontaneous imbibition test to link sub-pore-scale and core-scale wetting characteristics of the rock. Findings: The results show a dependency between surface coverage by oil, which controls the wetting alteration, and the macroscopic wetting response. The surface-area coverage is dependent on the capillary pressure applied during primary drainage. Close to the saturation endpoint, where the change in saturation was minor, the oil-solid contact changed more than 80%. (C) 2019 The Authors. Published by Elsevier Inc.

In various natural and engineered systems, mineral–fluid interactions take place in the presence of multiple fluid phases. While there is evidence that the interplay between multiphase flow processes and reactions controls the evolution of these systems, investigation of the dynamics that shape this interplay at the pore scale has received little attention. Specifically, continuum scale models rarely consider the effect of multiphase flow parameters on mineral reaction rates or apply simple corrections as a function of the reactive surface area or saturation of the aqueous phase, without developing a mechanistic understanding of the pore-scale dynamics. In this study, we developed a framework that couples the two-phase flow simulator of OpenFOAM (open field operation and manipulation) with the geochemical reaction capability of CrunchTope to examine pore-scale dynamics of two phase flow and their impacts on mineral reaction rates. For our investigations, flat 2D channels and single sine wave channels were used to represent smooth and rough geometries. Calcite dissolution in these channels was quantified with single phase flow and two phase flow at a range of velocities. We observed that the bulk calcite dissolution rates were not only affected by the loss of reactive surface area as it becomes occupied by the non-reactive non-aqueous phase, but also largely influenced by the changes in local velocity profiles, e.g., recirculation zones, due to the presence of the non-aqueous phase. The extent of the changes in reaction rates in the two-phase systems compared to the corresponding single phase system is dependent on the flow rate (i.e., capillary number) and channel geometry, and follows a non-monotonic relationship with respect to aqueous saturation. The pore-scale simulation results highlight the importance of interfacial dynamics in controlling mineral reactions and can be used to better constrain reaction rate descriptions in multiphase continuum scale models. These results also emphasize the need for experimental studies that underpin the development of mechanistic models for multiphase flow in reactive systems.

Transport of solutes and colloids over a large number of pores and for multiple scales were explored using micromodel experiments and analysis. In addition, we provided detailed insight into the interactions of solute and colloids with pore space heterogeneities. This was achieved by systematically changing the fraction of aggregates to perform different micromodel experiments. On these samples, we began by performing saturated transport experiments and continued by investigating the effect of drainage and imbibition cycles on colloid remobilization in the dual-porosity samples. During this study, several customized experimental tools have been developed to enable investigation of flow and transport of non-adsorbing solutes and colloids at the pore scale. For the computational part, we have used pore network modeling to further investigate the interaction of non-adsorbing solutes between the inter-aggregate and intra-aggregate pores. We developed a pore network generator for dual-porosity models and studied the effect of aggregate porosity and aggregate permeability.

We identify a distinct two-phase flow invasion pattern in a mixed-wet porous medium. Time-resolved high-resolution synchrotron X-ray imaging is used to study the invasion of water through a small rock sample filled with oil, characterized by a wide non-uniform distribution of local contact angles both above and below 90 ° . The water advances in a connected front, but throats are not invaded in decreasing order of size, as predicted by invasion percolation theory for uniformly hydrophobic systems. Instead, we observe pinning of the three-phase contact between the fluids and the solid, manifested as contact angle hysteresis, which prevents snap-off and interface retraction. In the absence of viscous dissipation, we use an energy balance to find an effective, thermodynamic, contact angle for displacement and show that this angle increases during the displacement. Displacement occurs when the local contact angles overcome the advancing contact angles at a pinned interface: it is wettability which controls the filling sequence. The product of the principal interfacial curvatures, the Gaussian curvature, is negative, implying well-connected phases which is consistent with pinning at the contact line while providing a topological explanation for the high displacement efficiencies in mixed-wet media.

The performance of latent thermal energy storage (LTES) heat exchangers is related to the stored energy (i.e. state of charge) during the (dis)charging of the energy storage system. Therefore, measuring the stored energy is crucial to understand the behavior of LTES systems. However, technical considerations often oppose the measurability of the stored energy. The present article presents a case where only measurements at the in- and outlet of the heat transfer fluid and on the outer surface of the heat exchanger were possible. Based on this sparse set of measurements, estimators for the stored energy are developed. To test these estimators, a finite volume model of the LTES heat exchanger is made. The finite volume model is fitted by comparing the predicted heat transfer fluid outlet temperature for 36 experiments. The energy estimators are compared to simulation results. The estimators for the stored energy in the heat transfer fluid, metal and phase change material obtain an average deviation of respectively 0.5 %, 3.9 % and 0.6 % with the stored energy predicted by the finite volume model. The estimator for the stored energy in the heat transfer fluid should be applicable to all LTES heat exchangers while the applicability of the estimators for stored energy in the metal and phase change material depend on small temperature differences between surface and interior of the metal and negligible heat losses.

We study the impact of brine acidity and initial pore structure on the dynamics of fluid/solid reaction at high Peclet numbers and low Damkohler numbers. A laboratory μ -CT scanner was used to image the dissolution of Ketton, Estaillades, and Portland limestones in the presence of CO 2 -acidified brine at reservoir conditions (10 MPa and 50 °C) at two injected acid strengths for a period of 4 h. Each sample was scanned between 6 and 10 times at ∼4 μm resolution and multiple effluent samples were extracted. The images were used as inputs into flow simulations, and analysed for dynamic changes in porosity, permeability, and reaction rate. Additionally, the effluent samples were used to verify the image-measured porosity changes. We find that initial brine acidity and pore structure determine the type of dissolution. Dissolution is either uniform where the porosity increases evenly both spatially and temporally, or occurs as channelling where the porosity increase is concentrated in preferential flow paths. Ketton, which has a relatively homogeneous pore structure, dissolved uniformly at pH = 3.6 but showed more channelized flow at pH = 3.1. In Estaillades and Portland, increasingly complex carbonates, channelized flow was observed at both acidities with the channel forming faster at lower pH. It was found that the effluent pH, which is higher than that injected, is a reasonably good indicator of effective reaction rate during uniform dissolution, but a poor indicator during channelling. The overall effective reaction rate was up to 18 times lower than the batch reaction rate measured on a flat surface at the effluent pH, with the lowest reaction rates in the samples with the most channelized flow, confirming that transport limitations are the dominant mechanism in determining reaction dynamics at the fluid/solid boundary.

X-ray microcomputed tomography (X-ray μ-CT) is a rapidly advancing technology that has been successfully employed to study flow phenomena in porous media. It offers an alternative approach to core scale experiments for the estimation of traditional petrophysical properties such as porosity and single-phase flow permeability. It can also be used to investigate properties that control multiphase flow such as rock wettability or mineral topology. In most applications, analyses are performed on segmented images obtained employing a specific processing pipeline on the greyscale images. The workflow leading to a segmented image is not straightforward or unique and, for most of the properties of interest, a ground truth is not available. For this reason, it is crucial to understand how image processing choices control properties estimation. In this work, we assess the sensitivity of porosity, permeability, specific surface area, in situ contact angle measurements, fluid–fluid interfacial curvature measurements and mineral composition to processing choices. We compare the results obtained upon the employment of two processing pipelines: non-local means filtering followed by watershed segmentation; segmentation by a manually trained random forest classifier. Single-phase flow permeability, in situ contact angle measurements and mineral-to-pore total surface area are the most sensitive properties, as a result of the sensitivity to processing of the phase boundary identification task. Porosity, interfacial fluid–fluid curvature and specific mineral descriptors are robust to processing. The sensitivity of the property estimates increases with the complexity of its definition and its relationship to boundary shape.

The use of Darcy's law to describe steady-state multiphase flow in porous media has been justified by the assumption that the fluids flow in continuously connected pathways. However, a range of complex interface dynamics have been observed during macroscopically steady-state flow, including intermittent pathway flow where flow pathways periodically disconnect and reconnect. The physical mechanisms controlling this behavior have remained unclear, leading to uncertainty concerning the occurrence of the different flow regimes. We observe that the fraction of intermittent flow pathways is dependent on the capillary number and viscosity ratio. We propose a phase diagram within this parameter space to quantify the degree of intermittent flow.

Conservation of energy is used to derive a thermodynamically-consistent contact angle, θ t , when fluid phase 1 displaces phase 2 in a porous medium. Assuming no change in Helmholtz free energy between two local equilibrium states we find that Δ a 1 s cos θ t = κ ϕ Δ S 1 + Δ a 12 , where a is the interfacial area per unit volume, ϕ is the porosity, S is the saturation and κ the curvature of the fluid-fluid interface. The subscript s denotes the solid, and we consider changes, Δ , in saturation and area. With the advent of high-resolution time-resolved three-dimensional X-ray imaging, all the terms in this expression can be measured directly. We analyse imaging datasets for displacement of oil by water in a water-wet and a mixed-wet sandstone. For the water-wet sample, the curvature is positive and oil bulges into the brine with almost spherical interfaces. In the mixed-wet case, larger interfacial areas are found, as the oil resides in layers. The mean curvature is close to zero, but the interface tends to bulge into brine in one direction, while brine bulges into oil in the other. We compare θ t with the values measured geometrically in situ on the pore-scale images, θ g . The thermodynamic angle θ t provides a robust and consistent characterization of wettability. For the water-wet case the calculated value of θ t gives an accurate prediction of multiphase flow properties using pore-scale modelling.

We perform direct numerical simulation using a pore-scale fluid–fluid reactive transport model (Alhashmi et al. in J Contam Hydrol 179:171–181, 2015. doi: 10.1016/j.jconhyd.2015.06.004 ) to investigate the impact of pore structure heterogeneity on the effective reaction rate in different porous media. We simulate flow, transport, and reaction in three pore-scale images: a beadpack, Bentheimer sandstone, and Doddington sandstone for a range of transport and reaction conditions. We compute the reaction rate, velocity distributions, and dispersion coefficient comparing them with the results for non-reactive transport. The rate of reaction is a subtle combination of the amount of mixing and spreading that cannot be predicted from the non-reactive dispersion coefficient. We demonstrate how the flow field heterogeneity affects the effective reaction rate. Dependent on the intrinsic flow field heterogeneity characteristic and the flow rate, reaction may: (a) occur throughout the zones where both resident and injected particles exist (for low Peclet number and a homogeneous flow field), (b) preferentially occur at the trailing edge of the plume (for high Peclet number and a homogeneous flow field), or (c) be disfavored in slow-moving zones (for high Peclet number and a heterogeneous flow field).

We investigate the impact of initial pore structure and velocity field heterogeneity on the dynamics of fluid/solid reaction at high Peclet numbers (fast flow) and low Damkohler number (relatively slow reaction rates). The Diamond Lightsource Pink Beam was used to image dissolution of Estaillades and Portland limestones in the presence of CO 2 -saturated brine at reservoir conditions (10 MPa and 50 °C representing ~ 1 km aquifer depth) at two flow rates for a period of 2 h. Each sample was scanned between 51 and 94 times at 4.76-μm resolution and the dynamic changes in porosity, permeability, and reaction rate were examined using image analysis and flow modelling. We find that the porosity can either increase uniformly through time along the length of the samples, or may exhibit a spatially and temporally varying increase that is attributed to channel formation, a process that is distinct from wormholing, depending on initial pore structure and flow conditions. The dissolution regime was structure-dependent: Estaillades with a higher porosity showed more uniform dissolution, while the lower porosity Portland experienced channel formation. The effective reaction rates were up to two orders of magnitude lower than those measured on a flat substrate with no transport limitations, indicating that the transport of reactant and product is severely hampered away from fast flow channels.

During CO2 storage in depleted oil fields, under immiscible conditions, CO2 can be trapped in the pore space by capillary forces, providing safe storage over geological times - a phenomenon named capillary trapping. Synchrotron X-ray imaging was used to obtain dynamic three-dimensional images of the flow of the three phases involved in this process - brine, oil and gas (nitrogen) - at high pressure and temperature, inside the pore space of Ketton limestone. First, using continuous imaging of the porous medium during gas injection, performed after waterflooding, we observed chains of multiple displacements between the three phases, caused by the connectivity of the pore space. Then, brine was re-injected and double capillary trapping - gas trapping by oil and oil trapping by brine - was the dominant double displacement event. We computed pore occupancy, saturations, interfacial area, mean curvature and Euler characteristic to elucidate these double capillary trapping phenomena, which lead to a high residual gas saturation. Pore occupancy and saturation results show an enhancement of gas trapping in the presence of both oil and brine, which potentially makes CO2 storage in depleted oil reservoirs attractive, combining safe storage with enhanced oil recovery through immiscible gas injection. Mean curvature measurements were used to assess the capillary pressures between fluid pairs during double displacements and these confirmed the stability of the spreading oil layers observed, which facilitated double capillary trapping. Interfacial area and Euler characteristic increased, indicating lower oil and gas connectivity, due to the capillary trapping events.

Injection of CO2 deep underground into porous rocks, such as saline aquifers, appears to be a promising tool for reducing CO2 emissions and the consequent climate change. During this process CO2 displaces brine from individual pores and the sequence in which this happens determines the efficiency with which the rock is filled with CO2 at the large scale. At the pore scale, displacements are controlled by the balance of capillary, viscous and inertial forces. We simulate this process by a numerical technique, multi-GPU Lattice Boltzmann, using X-ray images of the rock pores. The simulations show the three types of fluid displacement patterns, at the larger scale, that have been previously observed in both experiments and simulations: viscous fingering, capillary fingering and stable displacement. Here we examine the impact of the patterns on storage efficiency and then focus on slow flows, where displacements at the pore scale typically happen by sudden jumps in the position of the interface between brine and CO2, Haines jumps. During these jumps, the fluid in surrounding pores can rearrange in a way that prevent later displacements in nearby pores, potentially reducing the efficiency with which the CO2 fills the total available volume in the rock.

We derive the entropy production for transport of multi-phase fluids in a non-deformable, porous medium exposed to differences in pressure, temperature, and chemical potentials. Thermodynamic extensive variables on the macro-scale are obtained by integrating over a representative elementary volume (REV). Using Euler homogeneity of the first order, we obtain the Gibbs equation for the REV. From this we define the intensive variables, the temperature, pressure and chemical potentials and, using the balance equations, derive the entropy production for the REV. The entropy production defines sets of independent conjugate thermodynamic fluxes and forces in the standard way. The transport of two-phase flow of immiscible components is used to illustrate the equations., Comment: 25 pages, 7 figures, Talk at Interpore, New Orleans, 2018

Geological carbon dioxide storage must be designed such that the CO 2 cannot escape from the rock formation into which it is injected, and often simple stratigraphic trapping is insufficient. CO 2 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 CO 2 , brine and rock phases to replicate conditions far away from the injection site. In each sample substantial amounts of CO 2 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 10 5 voxel 3 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 CO 2 in a wide range of rock types.

Two carbonate rocks were studied experimentally at reservoir conditions at two flow rates using dynamic X-ray tomography. Cores of both homogeneous (Ketton) and heterogeneous (Portland) carbonates, were injected with CO 2 -saturated at 10 MPa and 50oC. Images were taken at between 30-second and 40- minute time-resolutions during injection. Reaction-induced changes in porosity, permeability, and structure were obtained by segmenting the images and extracting a pore/throat network. Differences in dissolution type and magnitude were found for each rock and flow rate. At the highest flow rates, Ketton displayed uniform dissolution. Conversely, Portland formed wormholes at high and compact dissolution at low flow rates.

Pore-scale imaging and modelling – digital core analysis – is becoming a routine service in the oil and gas industry, and has potential applications in contaminant transport and carbon dioxide storage. This paper briefly describes the underlying technology, namely imaging of the pore space of rocks from the nanometre scale upwards, coupled with a suite of different numerical techniques for simulating single and multiphase flow and transport through these images. Three example applications are then described, illustrating the range of scientific problems that can be tackled: dispersion in different rock samples that predicts the anomalous transport behaviour characteristic of highly heterogeneous carbonates; imaging of super-critical carbon dioxide in sandstone to demonstrate the possibility of capillary trapping in geological carbon storage; and the computation of relative permeability for mixed-wet carbonates and implications for oilfield waterflood recovery. The paper concludes by discussing limitations and challenges, including finding representative samples, imaging and simulating flow and transport in pore spaces over many orders of magnitude in size, the determination of wettability, and upscaling to the field scale. We conclude that pore-scale modelling is likely to become more widely applied in the oil industry including assessment of unconventional oil and gas resources. It has the potential to transform our understanding of multiphase flow processes, facilitating more efficient oil and gas recovery, effective contaminant removal and safe carbon dioxide storage.

Laboratory experiments and field trials have shown that oil recovery from carbonate reservoirs can be increased by modifying the brine composition injected during recovery in a process termed controlled salinity water-flooding (CSW). However, CSW remains poorly understood and there is no method to predict the optimum CSW composition. This work demonstrates for the first time that improved oil recovery (IOR) during CSW is strongly correlated to changes in zeta potential at both the mineral-water and oil-water interfaces. We report experiments in which IOR during CSW occurs only when the change in brine composition induces a repulsive electrostatic force between the oil-brine and mineral-brine interfaces. The polarity of the zeta potential at both interfaces must be determined when designing the optimum CSW composition. A new experimental method is presented that allows this. Results also show for the first time that the zeta potential at the oil-water interface may be positive at conditions relevant to carbonate reservoirs. A key challenge for any model of CSW is to explain why IOR is not always observed. Here we suggest that failures using the conventional (dilution) approach to CSW may have been caused by a positively charged oil-water interface that had not been identified.

Co-injection of water with CO2 is an effective scheme to control the initial gas saturation in porous media. The fractional flow rate of water about 5 to 10% is enough to reduce the initial gas saturations, and after water injection, most of gas injected in porous media is trapped by capillarity with low fractional volume of migrating gas. In this paper, first we derive an analytical model to predict the gas saturations for the co-injection with water. Next, the effect of the initial gas saturation, which is controlled by the fractional flow ratio in co-injection process, on the residual gas saturation at capillary trapping is investigated experimentally for the water and nitrogen system at room condition. Depending on the relative permeabilities, the initial gas saturation is reduced by the co-injection of water. In case of the Berea sandstone core, if the initial saturation is controlled to be in the range between 20% and 40%, most of the gas is trapped by capillarity and less than 20% of gas with respect to the injected gas volume is migrate by water injection. In case of the packed bed of Toyoura standard sand, the initial gas saturation is about 20% for a wide range of gas fractional flow rate from 0.50 to 0.95. The residual gas saturation for these conditions is about 15%. Approximately less than 25% of gas migrates by water injection. Based on the analytical model and the experimental results, advantages and disadvantages of co-injection systems are discussed.

A fundamental understanding of flow in porous media at the pore-scale is necessary to be able to upscale average displacement processes from core to reservoir scale. The study of fluid flow in porous media at the pore-scale consists of two key procedures: Imaging - reconstruction of three-dimensional (3D) pore space images; and modelling such as with single and two-phase flow simulations with Lattice-Boltzmann (LB) or Pore-Network (PN) Modelling. Here we analyse pore-scale results to predict petrophysical properties such as porosity, single-phase permeability and multi-phase properties at different length scales. The fundamental issue is to understand the image resolution dependency of transport properties, in order to up-scale the flow physics from pore to core scale. In this work, we use a high resolution micro-computed tomography (micro-CT) scanner to image and reconstruct three dimensional pore-scale images of five sandstones (Bentheimer, Berea, Clashach, Doddington and Stainton) and five complex carbonates (Ketton, Estaillades, Middle Eastern sample 3, Middle Eastern sample 5 and Indiana Limestone 1) at four different voxel resolutions (4.4 µm, 6.2 µm, 8.3 µm and 10.2 µm), scanning the same physical field of view. Implementing three phase segmentation (macro-pore phase, intermediate phase and grain phase) on pore-scale images helps to understand the importance of connected macro-porosity in the fluid flow for the samples studied. We then compute the petrophysical properties for all the samples using PN and LB simulations in order to study the influence of voxel resolution on petrophysical properties. We then introduce a numerical coarsening scheme which is used to coarsen a high voxel resolution image (4.4 µm) to lower resolutions (6.2 µm, 8.3 µm and 10.2 µm) and study the impact of coarsening data on macroscopic and multi-phase properties. Numerical coarsening of high resolution data is found to be superior to using a lower resolution scan because it avoids the problem of partial volume effects and reduces the scaling effect by preserving the pore-space properties influencing the transport properties. This is evidently compared in this study by predicting several pore network properties such as number of pores and throats, average pore and throat radius and coordination number for both scan based analysis and numerical coarsened data.

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.