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• Methods such as foam co-injection, application of nano particles and microbial methods are used to improve CO 2 trapping. • Capacity, containment and injectivity are reviewed comprehensively and the methods for improvement are reported. • Hydraulic fracturing is a promising approach to improve injectivity. • Water-wet reservoir was recognized as better options for CO 2 storage. • It is recommended that co-injecting substances like SO 2 and CH 4 can be beneficial for the process. The emission of carbon dioxide (CO 2) is globally recognized as a significant contributing factor to climate change. The natural sequestration of CO 2 in reservoirs is widely recognized as a robust strategy for mitigating carbon emissions. Based on comprehensive analysis of geographic data pertaining to sedimentary thickness and other relevant characteristics, it has been determined that the total global storage capacity ranges between 8000 Gt. and 55,000 Gt. (giga tonne − Gt. = 1012 kg). The current understanding of deep saline formations suggests having the greatest potential for CO 2 storage due to their high storage capacity. This work reviews the studies addressing the active trapping mechanisms, requirements and key aspects related to CO 2 storage in saline aquifers. The active CO 2 geo-storage mechanisms during CO 2 injection include structural, capillary, dissolution, and mineralization. To improve CO 2 trapping, methods such as foam co-injection, application of nano particles and microbial methods are comprehensively addressed in this work. Based on the findings, to enhance injectivity and storage in narrow, low-permeability saline aquifers, hydraulic fracturing is advised, while acknowledging the potential storage efficiency improvement offered by heterogeneity in rock formations. This study emphasizes prioritizing water-wet conditions for enhanced storage and containment security, highlighting the advantages of employing horizontal wells in such formations. Additionally, for increased safety and cost-effectiveness in CCS systems, this study recommends co-injecting substances like SO 2 and CH 4 to address pollutants in CO 2 streams, stressing the importance of a holistic approach for maximizing efficiency and safety in saline formations. [ABSTRACT FROM AUTHOR]

We define contact angles, θ , during displacement of three fluid phases in a porous medium using energy balance, extending previous work on two-phase flow. We test if this theory can be applied to quantify the three contact angles and wettability order in pore-scale images of three-phase displacement. For three phases labelled 1, 2 and 3, and solid, s , using conservation of energy ignoring viscous dissipation (Δ a 1 s cos θ 12 - Δ a 12 - ϕ κ 12 Δ S 1) σ 12 = (Δ a 3 s cos θ 23 + Δ a 23 - ϕ κ 23 Δ S 3) σ 23 + Δ a 13 σ 13 , where ϕ is the porosity, σ is the interfacial tension, a is the specific interfacial area, S is the saturation, and κ is the fluid–fluid interfacial curvature. Δ represents the change during a displacement. The third contact angle, θ 13 can be found using the Bartell-Osterhof relationship. The energy balance is also extended to an arbitrary number of phases. X-ray imaging of porous media and the fluids within them, at pore-scale resolution, allows the difference terms in the energy balance equation to be measured. This enables wettability, the contact angles, to be determined for complex displacements, to characterize the behaviour, and for input into pore-scale models. Two synchrotron imaging datasets are used to illustrate the approach, comparing the flow of oil, water and gas in a water-wet and an altered-wettability limestone rock sample. We show that in the water-wet case, as expected, water (phase 1) is the most wetting phase, oil (phase 2) is intermediate wet, while gas (phase 3) is most non-wetting with effective contact angles of θ 12 ≈ 48 ° and θ 13 ≈ 44 ° , while θ 23 = 0 since oil is always present in spreading layers. In contrast, for the altered-wettability case, oil is most wetting, gas is intermediate-wet, while water is most non-wetting with contact angles of θ 12 = 134 ° ± ~ 10 ° , θ 13 = 119 ° ± ~ 10 ° , and θ 23 = 66 ° ± ~ 10 °. [ABSTRACT FROM AUTHOR]

The development of high-resolution in situ imaging has allowed contact angles to be measured directly inside porous materials. We evaluate the use of concepts in integral geometry to determine contact angle. Specifically, we test the hypothesis that it is possible to determine an average contact angle from measurements of the Gaussian curvature of the fluid/fluid meniscus using the Gauss-Bonnet theorem. We show that it is not possible to unambiguously determine an average contact angle from the Gauss-Bonnet theorem. We instead present an approximate relationship: 2 π n (1 - cos θ) = 4 π - ∫ κ G 12 dS 12 , where n is the number of closed loops of the three-phase contact line where phases 1 and 2 contact the surface, θ is the average contact angle, while κ G 12 is the Gaussian curvature of the fluid meniscus which is integrated over its surface S 12 . We then use the results of pore-scale lattice Boltzmann simulations to assess the accuracy of this approach to determine a representative contact angle for two-phase flow in porous media. We show that in simple cases with a flat solid surface, the approximate expression works well. When applied to simulations on pore space images, the equation provides a robust estimate of contact angle, accurate to within 3 ° , when averaged over many fluid clusters, although individual values can have significant errors because of the approximations used in the calculation. [ABSTRACT FROM AUTHOR]

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. 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. 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. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Abstract We present a new model, named poreReact, to simulate multispecies reactive transport on pore space images. We solve the Navier–Stokes equations and the advection-diffusion equation for concentration on an unstructured grid using the finite volume method implemented in OpenFOAM. We couple it with the chemical model Reaktoro, which we use to calculate the chemical equilibrium of homogeneous reactions in each grid cell, considered as a completely mixed batch reactor. We validate the model against analytical solutions and experimental data, and investigate, for a range of Péclet numbers, the interplay between transport and reaction for multispecies reactive transport in a 3D bead pack where two streams of reactants at different pH are injected in parallel. We analyse the distribution of species and the rates of formation and consumption in the pore space and find that, despite the relative homogeneity of the bead pack and symmetry in injection conditions, the concentration fields of the products can be asymmetric because of the interplay between transport and chemical equilibrium. For different Péclet numbers, we calculate relative yields (the ratio between the observed change in concentration and the change that would be obtained if the reactants were completely mixed). We observe that lower Péclet numbers give rise to higher relative yields because of increased transverse mixing by diffusion. However, higher absolute yields are obtained at higher injection velocities because of the larger amount of matter available for reaction in a given time. Reaction is more favoured in the faster-flowing regions of the pore space. However, this effect is more marked for species for which advection is the dominant mechanism of transport to reactive sites, as opposed to diffusion-mediated reactions where the full velocity distribution is sampled before reaction occurs. [ABSTRACT FROM AUTHOR]

A quantitative in situ characterization of the impact of surface roughness on wettability in porous media is currently lacking. We use reservoir condition micrometer-resolution X-ray tomography combined with automated methods for the measurement of contact angle, interfacial curvature, and surface roughness to examine fluid/fluid and fluid/solid interfaces inside a porous material. We study oil and water in the pore space of limestone from a giant producing oilfield, acquiring millions of measurements of curvature and contact angle on three millimeter-sized samples. We identify a distinct wetting state with a broad distribution of contact angle at the submillimeter scale with a mix of water-wet and water-repellent regions. Importantly, this state allows both fluid phases to flow simultaneously over a wide range of saturation. We establish that, in media that are largely water wet, the interfacial curvature does not depend on solid surface roughness, quantified as the local deviation from a plane. However, where there has been a significant wettability alteration, rougher surfaces are associated with lower contact angles and higher interfacial curvature. The variation of both contact angle and interfacial curvature increases with the local degree of roughness. We hypothesize that this mixed wettability may also be seen in biological systems to facilitate the simultaneous flow of water and gases; furthermore, wettability-altering agents could be used in both geological systems and material science to design a mixed-wetting state with optimal process performance. [ABSTRACT FROM AUTHOR]

We perform spontaneous imbibition experiments on three carbonates - Estaillades, Ketton, and Portland - which are three quarry limestones that have very different pore structures and span wide range of permeability. We measure the mass of water imbibed in air saturated cores as a function of time under strongly water-wet conditions. Specifically, we perform co-current spontaneous experiments using a highly sensitive balance to measure the mass imbibed as a function of time for the three rocks. We use cores measuring 37 mm in diameter and three lengths of approximately 76 mm, 204 mm, and 290 mm. We show that the amount imbibed scales as the square root of time and find the parameter C , where the volume imbibed per unit cross-sectional area at time t is Ct 1/2 . We find higher C values for higher permeability rocks. Employing semi-analytical solutions for one-dimensional flow and using reasonable estimates of relative permeability and capillary pressure, we can match the experimental data. We finally discuss how, in combination with conventional measurements, we can use theoretical solutions and imbibition measurements to find or constrain relative permeability and capillary pressure. [ABSTRACT FROM AUTHOR]

The effect of pore-scale heterogeneity on non-Darcy flow behaviour is investigated by means of direct flow simulations on 3-D images of a beadpack, Bentheimer sandstone and Estaillades carbonate. The critical Reynolds number indicating the cessation of the creeping Darcy flow regime in Estaillades carbonate is two orders of magnitude smaller than in Bentheimer sandstone, and is three orders of magnitude smaller than in the beadpack. It is inferred from the examination of flow field features that the emergence of steady eddies in pore space of Estaillades at elevated fluid velocities accounts for the early transition away from the Darcy flow regime. The non-Darcy coefficient β , the onset of non-Darcy flow, and the Darcy permeability for all samples are obtained and compared to available experimental data demonstrating the predictive capability of our approach. X-ray imaging along with direct pore-scale simulation of flow provides a viable alternative to experiments and empirical correlations for predicting non-Darcy flow parameters such as the β factor, and the onset of non-Darcy flow. [ABSTRACT FROM AUTHOR]

We use an organic acid (cyclohexanepentanoic acid) to alter the wettability of three carbonates: Estaillades, Ketton and Portland limestones, and observe the relationship between the initial oil saturation and the residual saturation. We take cores containing oil and a specified initial water saturation and waterflood until 10 pore volumes have been injected. We record the remaining oil saturation as a function of the amount of water injected. In the water-wet case, with no wettability alteration, we observe, as expected, a monotonic increase in the remaining oil saturation with initial saturation. However, when the wettability is altered, we observe an increase, then a decrease, and finally an increase in the trapping curve for Estaillades limestone with a small, but continued, decrease in the remaining saturation as more water is injected. This behavior is indicative of mixed-wet or intermediate-wet conditions, as there is no spontaneous imbibition of oil and water. In contrast, Ketton did not show indications of a significant wettability alteration with a similar observed trapping profile to that observed in the water-wet case. Portland limestone also showed a monotonic increasing trend in remaining saturation with initial saturation but with a higher recovery, and less trapping, than the water-wet case. Again, this is intermediate-wet behavior with no spontaneous imbibition of either oil or water, and slow production of oil after water breakthrough. Finally, we repeat the same experiments but instead we age the three carbonates with a high asphaltenic content and high viscosity crude oil at 70 °C mimicking reservoir conditions. The results show a monotonic increase in residual saturation as a function of initial saturation but with higher recovery than the water-wet cases for Estaillades and Portland, with again no indication of wettability alteration for Ketton. We discuss the results in terms of pore-scale recovery process and contact angle hysteresis. In these experiments, water-saturated micro-porosity appears to protect the solid surfaces from a strong wettability alteration, particularly in Ketton. [ABSTRACT FROM AUTHOR]

We present a new control volume finite element method that improves the modelling of multi-phase fluid flow in highly heterogeneous and fractured reservoirs, called the Interface Control Volume Finite Element (ICVFE) method. The method drastically decreases the smearing effects in other CVFE methods, while being mass conservative and numerically consistent. The pressure is computed at the interfaces of elements, and the control volumes are constructed around them, instead of at the elements' vertices. This assures that a control volume straddles, at most, two elements, which decreases the fluid smearing between neighbouring elements when large variations in their material properties are present. Lowest order Raviart–Thomas vectorial basis functions are used for the pressure calculation and first-order Courant basis functions are used to compute fluxes. The method is a combination of Mixed Hybrid Finite Element (MHFE) and CVFE methods. Its accuracy and convergence are tested using three dimensional tetrahedron elements to represent heterogeneous reservoirs. Our new approach is shown to be more accurate than current CVFE methods. [ABSTRACT FROM AUTHOR]

A chemical kinetics algorithm is presented for geochemical applications. The algorithm is capable of handling both equilibrium- and kinetically-controlled reactions in multiphase systems. The ordinary differential equations (ODEs) are solved using an implicit multistep backward differentiation formula (BDF) algorithm to ensure efficiency and stability when integrating stiff ODEs. An adaptive control scheme of the time step is adopted to guarantee small steps in steeper regions and large steps in smoother regions of the integration. Analytical derivatives of the reaction rates and species activities are used to permit the use of larger time steps, and to increase the robustness of the calculations. The chemical equilibrium calculations are performed using a Gibbs free energy minimisation algorithm, which is based on a trust-region interior-point method adapted with a watchdog strategy that yields quadratic rates of convergence near the solution. The chemical kinetics algorithm is applied to geochemical problems relevant to carbon storage in saline aquifers. The calculations assume aqueous, gaseous and mineral phases, where the kinetics of the water–gas–rock interactions are investigated. The results allow us to estimate the time frames at which brine of different salinities and supercritical CO 2 attains equilibrium with a carbonate rock, as well as the amount of carbon dioxide trapped by solubility and mineralisation mechanisms. [ABSTRACT FROM AUTHOR]

We use a streamline-based simulator that accurately captures non-Newtonian rheology and controls numerical dispersion to investigate polymer-flooding design. First, we develop and test a parallel design algorithm to optimize polymer floods with respect to net present value in terms of slug size, polymer concentration, and initiation; in which, simulations are run simultaneously and the results are combined through scaling of optimal slug size. In terms of optimal strategies, the optimization results illustrate that polymer-flooding design – with respect to concentration, slug size, and initiation – is more intuitive than earlier expected. It is always beneficial to start polymer flooding as soon as possible preferably before any waterflooding. The optimal slug size is close to being continuous. The optimal concentration is generally high and represents a balance between mobility gains and injectivity losses. Second, we quantify the impact of uncertainty on both the design and profitability of polymer flooding. This serves as a guide to associated data acquisition efforts, where pre-polymer flooding initiation, efforts can be focused on reducing uncertainties of high impact factors thereby increasing the probability of success. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Abstract: Chemical equilibrium calculations are essential for many environmental problems. It is also a fundamental tool for chemical kinetics and reactive transport modelling, since these applications may require hundreds to billions equilibrium calculations in a single simulation. Therefore, an equilibrium method for such critical applications must be very efficient, robust and accurate. In this work we demonstrate the potential effectiveness of a novel Gibbs energy minimisation algorithm for reactive transport simulations. The algorithm includes strategies to converge from poor initial guesses; capabilities to specify non-linear equilibrium constraints such as pH of an aqueous solution and activity or fugacity of a species; a rigorous phase stability test to determine the unstable phases; and a strategy to boost the convergence speed of the calculations to quadratic rates, requiring only few iterations to converge. We use this equilibrium method to solve geochemical problems relevant to carbon storage in saline aquifers, where aqueous, gaseous and minerals phases are present. The problems are formulated to mimic the ones found in kinetics and transport simulations, where a sequence of equilibrium calculations are performed, each one using the previous solution as the initial guess. The efficiency and convergence rates of the calculations are presented, which require an average of 1–2 iterations. These results indicate that critical applications such as chemical kinetics and reactive transport modelling can potentially benefit by using this multiphase equilibrium algorithm. [Copyright &y& Elsevier]

We present a robust and efficient method for calculating chemical equilibria of general multiphase systems. The method is based on a stoichiometric approach, which uses Newton’s method to solve a system of mass-action equations coupled with a system of equilibrium constraints. A stabilisation procedure is developed to promote convergence of the calculation when a presupposed phase in the chemical system is absent in the equilibrium state. The formulation of the chemical equilibrium problem is developed by presuming no specific details of the involved phases and species. As a consequence, the method is flexible and general enough so that the calculation can be customised with a combination of thermodynamic models that are appropriate for the problem of interest. Finally, we show the use of the method to solve relevant geochemical equilibrium problems for modelling carbon storage in highly saline aquifers. [ABSTRACT FROM AUTHOR]

Crossflow is a major factor affecting recovery efficiency in heterogeneous permeable media. In typical water-oil displacements, viscous-dominated crossflow improves oil recovery efficiency relative to no-crossflow depending on the shock-front and/or the mobility ratio across the displacement front. Its impact is not yet fully understood for augmented or engineered waterfloods such as controlled/low salinity waterflooding (LSWF). This is critical in such a flood with two distinct displacement shock-fronts – unlike a standard waterflood – that are potentially influenced by mixing of the brines which further complicates the crossflow behaviour. This paper presents a comprehensive treatment of crossflow effects on recovery or displacement efficiency along stratified media of contrasting properties during LSWF considering physical dispersion. We define dimensionless numbers to characterize no-crossflow, viscous- and gravity-dominated crossflow regimes for different mobility-ratios. In two-dimensional numerical simulations, we explore the influence of property contrasts and mobility-ratios across the two distinct shock-fronts on the viscous crossflow behaviour in a LSWF. The sensitivity of viscous crossflow recovery and (low-salinity) engineered-water sweep efficiency to mobility-ratios is evaluated at different performance times relative to no-crossflow displacement. Viscous crossflow (VC) is found to be relevant in water-oil displacements for permeability contrasts less than or equal to 1000, but less important for EOR low-salinity displacement once the permeability contrast exceeds 50. For the mobility-ratio cases considered, VC is unidirectional – from the fast to slow layer – only when the mobility-ratios across the two distinct shock-fronts are both favourable. Unlike a typical water-oil displacement, the weak dependency of late-time recovery efficiency on VC is observed to be a function of the mobility-ratio and dispersion in LSWF. An unfavourable mobility-ratio case is identified for viscous-dominated crossflow effects that is specific to low-salinity displacements. Ways to improve the flood design to ensure favourable displacement are presented. The findings of this study can help for better understanding of crossflow behaviour and regimes in reservoir settings, to mitigate any potential unfavourable impact on recovery or displacement efficiency with engineered or low-salinity water injection. • Range of property contrasts relevant to VC established for LSWF. • Two VC regimes defined based on shock-fronts' mobility ratios. • Unfavourable mobility-ratio case identified for LS displacement. • Late-time VC effects function of mobility ratios and dispersion. [ABSTRACT FROM AUTHOR]

We performed core flooding experiments on Indiana limestone using the porous plate method to measure the amount of trapped CO2 at a temperature of 50 °C and two pressures: 4.2 and 9 MPa. Brine was mixed with CO2 for equilibration, then the mixture was circulated through a sacrificial core. Porosity and permeability tests conducted before and after 884 h of continuous core flooding confirmed negligible dissolution. A trapping curve for supercritical (sc)CO2 in Indiana showing the relationship between the initial and residual CO2 saturations was measured and compared with that of gaseous CO2. The results were also compared with scCO2 trapping in Berea sandstone at the same conditions. A scCO2 residual trapping end point of 23.7% was observed, indicating slightly less trapping of scCO2 in Indiana carbonates than in Berea sandstone. There is less trapping for gaseous CO2 (end point of 18.8%). The system appears to be more water-wet under scCO2 conditions, which is different from the trend observed in Berea; we hypothesize that this is due to the greater concentration of Ca2+ in brine at higher pressure. Our work indicates that capillary trapping could contribute to the immobilization of CO2 in carbonate aquifers. [ABSTRACT FROM AUTHOR]

Abstract: 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. [Copyright &y& Elsevier]

Abstract: The rapid growth and climate of the Greater London region have contributed towards large deficits in water supply. Inexpensive, energy-efficient and sustainable water resource schemes are increasingly sought as a means to boost supply. Here, we propose a small-scale recycling scheme whereby tertiary-treated wastewater is pumped to the Cretaceous chalk of the London Basin. By taking advantage of the natural filtration properties of the underlying chalk, contaminants can be effectively attenuated over relatively short length scales to result in pure water. The problem is approached from four different scales. First, we define two localities in London where such a pumping scheme might operate; regions which combine a thick unsaturated zone and high chalk transmissivity, both essential to ensure maximum contaminant removal and minimum environmental impact. Secondly, the effects of pumping fluid into the Chalk at the two localities are quantified using a finite-difference groundwater flow model. We show that rivers impose a regular groundwater flow regime, whereas pre-existing abstraction wells will lead to less predictable results. Thirdly, we consider the effect of fractures on channelling rapid fluid flow within the rock mass. By digitising a fracture map based upon outcrop measurements from chalk exposed on the Kent coast similar to that beneath London, we quantify transport patterns of wastewater after injection. Imbibition to the chalk matrix (and therefore filtration) will occur where fluid pressure gradients are highest, for instance around disconnected fracture tips. Finally we demonstrate the efficacy of chalk in contaminant removal by injecting an analogue ‘effluent’ through a chalk core. ICP-AES analysis on the recovered solution shows the contaminants (viz. a suite of heavy metals) are arrested or removed over relatively small time- and length-scales. Numerical and analytical solutions fit the data poorly, shedding some light on the importance of hydrodynamic dispersion of aqueous contaminants within the chalk. [Copyright &y& Elsevier]

[Display omitted] The wettability change from oil-wet towards more water-wet conditions by injecting diluted brine can improve oil recovery from reservoir rocks, known as low salinity waterflooding. We investigated the underlying pore-scale mechanisms of this process to determine if improved recovery was associated with a change in local contact angle, and if additional displacement was facilitated by the formation of micro-dispersions of water in oil and water film swelling. X-ray imaging and high-pressure and temperature flow apparatus were used to investigate and compare high and low salinity waterflooding in a carbonate rock sample. The sample was placed in contact with crude oil to obtain an initial wetting state found in hydrocarbon reservoirs. High salinity brine was then injected at increasing flow rates followed by low salinity brine injection using the same procedure. Development of water micro-droplets within the oil phase and detachment of oil layers from the rock surface were observed after low salinity waterflooding. During high salinity waterflooding, contact angles showed insignificant changes from the initial value of 115°, while the mean curvature and local capillary pressure values remained negative, consistent with oil-wet conditions. However, with low salinity, the decrease in contact angle to 102° and the shift in the mean curvature and capillary pressure to positive values indicate a wettability change. Overall, our analysis captured the in situ mechanisms and processes associated with the low salinity effect and ultimate increase in oil recovery. [ABSTRACT FROM AUTHOR]

Abstract: We present a stable numerical scheme for modelling multiphase flow in porous media, where the characteristic size of the flow domain is of the order of microns to millimetres. The numerical method is developed for efficient modelling of multiphase flow in porous media with complex interface motion and irregular solid boundaries. The Navier–Stokes equations are discretised using a finite volume approach, while the volume-of-fluid method is used to capture the location of interfaces. Capillary forces are computed using a semi-sharp surface force model, in which the transition area for capillary pressure is effectively limited to one grid block. This new formulation along with two new filtering methods, developed for correcting capillary forces, permits simulations at very low capillary numbers and avoids non-physical velocities. Capillary forces are implemented using a semi-implicit formulation, which allows larger time step sizes at low capillary numbers. We verify the accuracy and stability of the numerical method on several test cases, which indicate the potential of the method to predict multiphase flow processes. [Copyright &y& Elsevier]

Abstract: Wettability controls fluid saturation and distribution in reservoir rocks, that in turn affects two-phase properties such as Nuclear Magnetic Resonance (NMR) response. We simulated the NMR response of two-phase systems during drainage and waterflooding in pore-scale networks representing sand packs and sandstones using a random walk method. Different wettabilities were studied and the simulation results were compared with previously published experimental measurements. In oil-wet media, we predict a slow decay with a broad T 2 distribution because water in the center of the pores has a low bulk relaxivity; there is little surface relaxivity since the grain surfaces are covered by oil layers. This suggests a straightforward technique to indicate oil wettability in core samples. [Copyright &y& Elsevier]

Abstract: We study the effects of wettability on waterflood oil recovery using a capillary-controlled pore-scale network model. We validate the model against experimental data in the literature on mixed-wet Berea sandstone and then apply it to study multiphase flow through four networks extracted from different types of rock: a sand pack, a poorly consolidated sandstone from the Middle East, a granular carbonate and Berea sandstone. We study the effects of initial water saturation, contact angle distribution and oil-wet fraction on recovery. For a uniformly-wet system, where the contact angle everywhere falls within a relatively narrow range, recovery increases as the system becomes less water-wet and reaches a maximum for oil-wet conditions where recovery is approximately constant for average intrinsic contact angles above 100°. As the initial water saturation increases, recovery decreases in water-wet systems whereas in oil-wet systems it initially increases and then decreases. For mixed-wet systems that contain water-wet and oil-wet regions of the pore space, the oil-wet fraction plays a more important role in determining recovery than the contact angle in the oil-wet regions. Optimal recovery occurs when a small fraction of the system is water-wet. Pore structure plays a relatively minor role in the generic behavior, although it does influence the initial saturation for maximum recovery and the magnitude of the recovery. These results are explained in terms of pore-scale displacement mechanisms and fluid configurations. [Copyright &y& Elsevier]

Abstract: Network modeling is used to study the flow in porous media of Ellis and Herschel–Bulkley fluids, which model a large group of time-independent non-Newtonian fluids. Previous work is extended to include yield-stress and shear-thickening phenomena. We use two topologically-disordered networks representing a sand pack and Berea sandstone. Analytical expressions for the volumetric flow rate in a single tube are derived and implemented in each pore and throat to simulate single-phase flow in the pore space. An iterative technique is used to compute the relationship between flow rate and pressure gradient across the whole network. The single tube behavior is compared to that of the network. Experimental data in the literature are compared to the network simulation results to validate the model and investigate its predictive capabilities. Good agreement is obtained in many cases. The flow of yield-stress fluids in porous media is analyzed. Two algorithms to predict the network threshold yield pressure are implemented and compared to the numerically computed threshold yield pressure of the network. [Copyright &y& Elsevier]

Abstract: A methodology for extracting networks from pore space images is presented. It computes the location and sizes of pores and throats to create a topologically equivalent representation of the void space of three-dimensional (3D) rock images, using the concept of maximal balls [Silin, D.B., Jin, G. and Patzek, T.W., 2003. Robust Determination of the Pore Space Morphology in Sedimentary rocks. SPE 84296, Annual Technical Conference and Exhibition, Denver, Colorado, USA, October.]. The model is successfully tested on sandstone and carbonate samples. The network extracted from a representation of Fontainebleau sandstone yielded a coordination number distribution that agrees well with that computed using a different extraction algorithm that is based on knowing the location of grain centers [Øren, P. and Bakke, S., 2003. Reconstruction of Berea sandstone and pore-scale modelling of wettability effects. Journal of Petroleum Science and Engineering 39 177–199.]. The model was further tested on a carbonate sample from subsurface Oman for which it is not possible to identify grains easily. For all the samples investigated in this study, the predicted absolute permeabilities, using the newly extracted networks, agree well with the laboratory measured values. [Copyright &y& Elsevier]

Abstract: The reconstruction of porous media is of great interest in a wide variety of fields, including earth science and engineering, biology, and medicine. To predict multiphase flow through geologically realistic porous media it is necessary to have a three-dimensional (3D) representation of the pore space. Multiple-point statistics were used, based on two-dimensional (2D) thin-sections as training images, to generate 3D pore space representations. The method was borrowed from geostatistical techniques that use pixel-based representations to reproduce large-scale patterns. Thin-section images can provide multiple-point statistics, which describe the statistical relation between multiple spatial locations. Assuming that the medium is isotropic, a 3D image can be generated that preserves typical patterns of the void space seen in the thin sections. The method is tested on Fontainebleau and Berea sandstones for which 3D images from micro-CT scanning are available. The use of multiple-point statistics predicts long-range connectivity of the structures (measured by local percolation probability) better than standard two-point statistics methods. The selection of multiple-point statistics is a key issue and is discussed in detail. [Copyright &y& Elsevier]

We extend the streamline method to model diffusion and dispersion in solute transport problems using an operator splitting technique. Fluid is moved along streamlines ignoring dispersion, and then component concentrations are mapped onto the underlying grid. Dispersion is included by solving the dispersive portion of the conservation equation on the grid. We quantify the effects of numerical dispersion resulting from remapping solutions from streamlines to the grid.We verify the method by comparison with one-dimensional analytical solutions and by predicting the results of a tracer test in a heterogeneous sand pack. We show the ability of our formulation to handle finely resolved geological models by running a 1.122 million cell field-scale problem.At both the laboratory and field scales we find long tails in the breakthrough curves. The average behavior is consistent with anomalous or non-Gaussian transport where wide variations in permeability result in a large spread of flow velocities. Local mixing caused by dispersion or diffusion can impact the overall recovery of tracer but does not significantly affect the late-time behavior of the plumes. [Copyright &y& Elsevier]

Pore-network models have been used to describe a wide range of properties from capillary pressure characteristics to interfacial area and mass transfer coefficients. The void space of a rock or soil is described as a network of pores connected by throats. The pores and throats are assigned some idealized geometry and rules are developed to determine the multiphase fluid configurations and transport in these elements. The rules are combined in the network to compute effective transport properties on a mesoscopic scale some tens of pores across. This approach is illustrated by describing a pore-scale model for two- and three-phase flow in media of arbitrary wettability. The appropriate pore-scale physics combined with a geologically representative description of the pore space gives a model that can predict average behavior, such as capillary pressure and relative permeability. This capability is demonstrated by successfully predicting primary drainage and waterflood relative permeabilities for Berea sandstone. The implications of this predictive power for improved characterization of subsurface simulation models are discussed. A simple example field study of waterflooding an oil-wet system near the oil/water contact shows how the assignment of physically-based multiphase flow properties based on pore-scale modeling gives significantly different predictions of oil recovery than using current empirical relative permeability models. Methods to incorporate pore-scale results directly into field-scale simulation are described. In principle, the same approach could be used to describe any type of process for which the behavior is understood at the pore scale. [Copyright &y& Elsevier]

Pore-scale imaging and modeling has advanced greatly through the integration of Deep Learning into the workflow, from image processing to simulating physical processes. In Digital Core Analysis, a common tool in Earth Sciences, imaging the nano- and micro-scale structure of the pore space of rocks can be enhanced past hardware limitations, while identification of minerals and phases can be automated, with reduced bias and high physical accuracy. Traditional numerical methods for estimating petrophysical parameters and simulating flow and transport can be accelerated or replaced by neural networks. Techniques and common neural network architectures used in Digital Core Analysis are described with a review of recent studies to illustrate the wide range of tasks that benefit from Deep Learning. Focus is placed on the use of Convolutional Neural Networks (CNNs) for segmentation in pore-scale imaging, the use of CNNs and Generative Adversarial Networks (GANs) in image quality enhancement and generation, and the use of Artificial Neural Networks (ANNs) and CNNs for pore-scale physics modeling. Current limitations and challenges are discussed, including advances in network implementations, applications to unconventional resources, dataset acquisition and synthetic training, extrapolative potential, accuracy loss from soft computing, and the computational cost of 3D Deep Learning. Future directions of research are also discussed, focusing on the standardization of datasets and performance metrics, integrated workflow solutions, and further studies in multiphase flow predictions, such as CO 2 trapping. The use of Deep Learning at the pore-scale will likely continue becoming increasingly pervasive, as potential exists to improve all aspects of the data-driven workflow, with higher image quality, automated processing, and faster simulations. • Deep learning in pore-scale image processing and physics simulations is reviewed. • Nano/micro-scale rock imaging can be enhanced past hardware limits with automated/unbiased mineral identification. • Traditional numerical methods can be accelerated or replaced by neural networks. • Limitations, challenges, and future directions are also discussed. • Potential exists throughout the data-driven workflow for higher image quality, automated processing, and faster simulations. [ABSTRACT FROM AUTHOR]

High-resolution three-dimensional X-ray microscopy can be used to image the pore space of materials. Machine learning algorithms can generate a statistical ensemble of representative images of arbitrary sizes for rock characterization, modeling, and analysis. However, current methods struggle to capture features at different spatial scales observed in many complex rocks which have a wide range of pore size. We use the Improved Pyramid Wasserstein Generative Adversarial Network (IPWGAN) to automatically reproduce multi-scale features in segmented three-dimensional images of porous materials, enabling the reliable generation of large-scale representations of complex porous media. A Laplacian pyramid generator is introduced, which creates pore-space features across a hierarchy of spatial scales. Feature statistics mixing regularization enhances the discriminator's ability to distinguish between real and generated images by mixing their feature statistics, thereby indirectly enhancing the generator's ability to capture and reproduce multi-scale pore-space features, leading to increased diversity and realism in the generated images. The method has been tested on five sandstone and carbonate samples. The generated images, which can be of any size – including cm-scale ten-billion-cell images – demonstrate the power of the approach. These images have two-point correlation functions, porosity, permeability, Euler characteristic, curvature, and specific surface area closer to those of the training datasets than existing machine learning techniques. The generated images accurately capture geometric and flow properties, demonstrating a considerable improvement over previously published studies using generative adversarial networks. For instance, the mean relative error in the calculated absolute permeability between the Berea sandstone images generated by IPWGAN and the corresponding real rock images can be reduced by 79%. The work allows representative models of a wide range of porous media to be generated, offering potential benefits in carbon dioxide sequestration, underground hydrogen storage, and enhanced oil recovery. • The improved GAN generates random pore-space images of arbitrary size. • The method reproduces geometric and flow properties of images of five sandstones and carbonates. • The method captures pore-space features over a range of length scales through a pyramid generator structure, among other improvements. [ABSTRACT FROM AUTHOR]

Low-salinity or controlled salinity waterflooding (LSWF) is a promising enhanced oil recovery (EOR) technique. In simulations of this process, numerical dispersion smears saturation fronts, causing errors in the results. The objective of this work is to control these effects in LSWF simulation. We examine the impact of numerical dispersion on simulated LSWF performance. The low-salinity (LS) front is smeared even at unfeasibly fine grids. The velocities of the water fronts are altered. A numerical mixed zone forms around the interface between the injected and resident brines. This mimics a typical physical mixing effect. In reservoir simulation, threshold salinities are defined where the low salinity effect (LSE) is first encountered. It has been suggested that numerical dispersion effects can be corrected by imposing effective thresholds. We demonstrate that existing methods to evaluate these effective salinities do not accurately predict the salt front movement especially when dispersion is significant. We propose a simple simulation-based approach to evaluate the effective salinities based on the conservation of volumes of the resident and injected brines in the reference and upscaled solutions. After comparing analytical and corrected coarse-grid solutions in one-dimension, the effectiveness of the approach is demonstrated in multi-dimensional systems. A method is proposed to control the numerical mixed zone to replicate a physical longitudinal mixing effect. This method is demonstrated in one-dimension and does not require a fine-grid numerical solution as a benchmark. We investigate the effects of effective thresholds on the modeled transverse mixing or dispersion. A method to model transverse dispersion in simulations with an effective longitudinal component is suggested. This method is extended to the explicit modeling of physical dispersion in systems with transverse flows. We can now simply evaluate the effective salinities for a simulation grid; and control its numerical dispersion effects to representative physical mixing or dispersion. • Numerical dispersion creates an unphysical mixed zone which alters the velocities of the water fronts. • Analytical prediction of the salt front movement is often inaccurate in coarse grids. • The velocities of the LS water front and the mid salinity threshold are distinctly different in dispersive grids. • Conserving the volumes of resident and injected brines reliably corrects numerical dispersion effects on front-velocities. • Effective salinity thresholds control the representative numerical mixing in a grid with no need for grid refinement. [ABSTRACT FROM AUTHOR]

The performance of nano- and micro-porous materials in capturing and releasing fluids, such as during CO 2 geo-storage and water/gas removal in fuel cells and electrolyzers, is determined by their wettability in contact with the solid. However, accurately characterizing wettability is challenging due to spatial variations in dynamic forces, chemical heterogeneity, and surface roughness. In situ measurements can potentially measure wettability locally as a contact angle - the angle a denser phase (e.g water) contacts solid in the presence of a second phase (e.g. hydrogen, air, CO 2) - but suffer from difficulties in accurately capturing curvatures, contact areas, and contact loops of multiphase fluids. We introduce a novel extended topological method for in situ contact angle measurement and provide a comparative review of current geometric and topological methods, assessing their accuracy on ideal surfaces, porous rocks containing CO 2 , and water in gas diffusion layers. The new method demonstrates higher accuracy and reliability of in situ measurements for uniformly wetting systems compared to previous topological approaches, while geometric measurements perform best for mixed-wetting domains. This study further provides a comprehensive open-source platform for in situ characterization of wettability in porous materials with implications for gas geo-storage, fuel cells and electrolyzers, filtration, and catalysis. [Display omitted] • A review of topological and geometrical in situ methods of wettability measurements on porous materials. • A novel Extended Topological Method is introduced and comparatively reviewed and benchmarked on mixed wetting porous media. • A detailed and simplified implementation and analysis of the ill-posed meshing stage alongside geometric methods of measurement. • Topological and geometric methods are similar on uniformly wet systems while geometric methods excel in mixed wet domains. • Open-sourced, enabling scientific community to expand in situ wettability characterization beyond its geoscience origins. [ABSTRACT FROM AUTHOR]

Green hydrogen, produced from surplus electricity during peak production, can be injected into subsurface reservoirs and retrieved during high-demand periods. In this study, X-ray tomography was employed to examine hysteresis resulting from repeated hydrogen injection and withdrawal. An unsteady state experiment was performed to evaluate the distribution of hydrogen and brine after drainage and imbibition cycles: images of the pore-space configuration of fluids were taken immediately once injection had stopped and after waiting for a period of 16 h with no flow. A Bentheimer sandstone sample with a length of 60 mm and diameter of 12.8 mm was used, and hydrogen was injected at ambient temperature and a pore pressure of 1 MPa. The gas flow rate was decreased from 2 ml/min to 0.08 ml/min over three cycles of gas injection followed by water flooding, while the brine injection rate was kept constant. The results showed the presence of capillary pressure hysteresis and hydrogen migration through Ostwald ripening due to the diffusion of gas dissolved in the brine. These phenomena were characterized through analysis of interfacial curvature, area, connectivity and pore occupancy. The hydrogen tended to reside in the larger pore spaces, consistent with water-wet conditions. 16 h after flow had stopped, the hydrogen aggregated into larger ganglia with a single large connected ganglion dominating the volume. Moreover, the Euler characteristic decreased after 16 h, indicating an improvement in connectivity. The work implies that Ostwald ripening – mass transport of dissolved gas – leads to less hysteresis and better connectivity than would be assumed ignoring this effect, as done in assessments of hydrocarbon flow and trapping. [Display omitted] • X-ray imaging investigated pore-scale hysteresis during hydrogen storage. • Hydrogen migration by Ostwald ripening was observed. • Ostwald ripening led to better connectivity of the gas phase. • The work implies less hysteresis for hydrogen than for hydrocarbons. [ABSTRACT FROM AUTHOR]

Over the last century, the state of stress in the earth's upper crust has undergone rapid changes because of human activities associated with fluid withdrawal and injection in subsurface formations. The stress dependency of multiphase flow mechanisms in earth materials is a substantial challenge to understand, quantify, and model for many applications in groundwater hydrology, applied geophysics, CO2 subsurface storage, and the wider geoenergy field (e.g., geothermal energy, hydrogen storage, hydrocarbon recovery). Here, we conduct core-scale experiments using N2/water phases to study primary drainage followed by spontaneous imbibition in a carbonate specimen under increasing isotropic effective stress and isothermal conditions. Using X-ray computed micro-tomography images of the unconfined specimen, we introduce a novel coupling approach to reconstruct pore-deformation and simulate multiphase flow inside the deformed pore-space followed by a semi-analytical calculation of spontaneous imbibition. We show that the irreducible water saturation increases while the normalized volume of spontaneously imbibed water into the specimen decreases (46–25%) in response to an increase in effective stress (0–30 MPa), leading to higher residual gas saturations. Furthermore, the imbibition rate decreases with effective stress, which is also predicted by a numerical model, due to a decrease in water relative permeability as the pore-space becomes more confined and tortuous. This fundamental study provides new insights into the physics of multiphase fluid transport, CO2 storage capacity, and recovery of subsurface resources incorporating the impact of poromechanics. [ABSTRACT FROM AUTHOR]

We present an application of deep generative models in the context of partial differential equation constrained inverse problems. We combine a generative adversarial network representing an a priori model that generates geological heterogeneities and their petrophysical properties, with the numerical solution of the partial-differential equation governing the propagation of acoustic waves within the earth's interior. We perform Bayesian inversion using an approximate Metropolis-adjusted Langevin algorithm to sample from the posterior distribution of earth models given seismic observations. Gradients with respect to the model parameters governing the forward problem are obtained by solving the adjoint of the acoustic wave equation. Gradients of the mismatch with respect to the latent variables are obtained by leveraging the differentiable nature of the deep neural network used to represent the generative model. We show that approximate Metropolis-adjusted Langevin sampling allows an efficient Bayesian inversion of model parameters obtained from a prior represented by a deep generative model, obtaining a diverse set of realizations that reflect the observed seismic response. [ABSTRACT FROM AUTHOR]

• Capillary pressure in drainage and waterflood was measured on a reservoir carbonate. • Capillary pressure in primary drainage was measured over two orders of magnitude. • During primary drainage, macro-pores were displaced first and then micro-porosity. • Oil displacement from micro-porosity in waterflood occurred at low capillary pressure. • The capillary pressure was approximately an order of magnitude lower than in drainage. A porous plate technique was developed to measure capillary pressure during both primary drainage and waterflooding in a reservoir carbonate rock sample. During primary drainage, a water-wet ceramic disc at the end of the sample allowed brine to be displaced but prevented the escape of oil while oil was injected at a sequence of increasing pressures. Saturation was measured using high-resolution three-dimensional X-ray imaging from the differences in greyscale (X-ray adsorption) between dry, partially-saturated and completely-saturated images. A two-step displacement process was observed, with the resolvable macro-pores displaced by oil followed by invasion into unresolved micro-porosity with a variation of two orders of magnitude in capillary pressure. The sample was then exposed to crude oil to render some of the solid surfaces oil-wet. A small amount of spontaneous imbibition (displacement at a positive capillary pressure) was observed in micro-porosity. Then an oil-wet porous plate was added to the outlet, so that water could be injected at a sequence of increasing pressures while only oil could escape. As expected, the oil-wet macro-porosity was displaced by brine at a low capillary pressure with a magnitude similar to that seen during drainage (but of opposite sign). Remarkably though the displacement of oil from micro-porosity occurred at a capillary pressure approximately an order of magnitude lower than in drainage, implying the existence of mixed-wettability with fluid menisci that are approximately minimal surfaces. The work demonstrates that in mixed-wet media displacement of oil from micro-porosity can occur at much lower capillary pressures that would be estimated from primary drainage results using the calculated pore size distribution. [ABSTRACT FROM AUTHOR]

Complex pore‐scale dynamics have been observed during multiphase flow through porous rocks. These dynamics are not incorporated in large scale models for the migration and trapping of subsurface fluids such as CO2 or hydrogen. We show that fluctuations in pressure measured at the core‐scale (centimeters) can reflect fluid displacements at the pore‐scale (millimeters). The spectral characteristics of pressure data are shown to depend on the flow dynamics, the size of the rock sample, and the heterogeneity of the pore space. These results show that pressure data, transformed into the time‐frequency domain using wavelets, provides information about flow dynamics, across scales, that are otherwise challenging to acquire. Plain Language Summary: Understanding the flow of fluid in porous rocks is crucial for the safe, long‐term, storage of CO2 and hydrogen. Complex fluid flow has been observed in small pores. However, imaging limitations prevent direct observation of such dynamics in larger samples. As such, small‐scale flow remains a considerable source of uncertainty for predicting the underground storage or movement of fluid. In the absence of suitable imaging techniques, we demonstrate how flow dynamics at smaller scales can be explored by analyzing pressure data and its fluctuations using mathematical techniques. We apply this approach to larger samples and discover that pressure fluctuations contain useful information about flow dynamics, sample size, and rock composition that are often otherwise unavailable. Key Points: Pore‐scale dynamics can be linked to pressure fluctuations measured across the coreThe spectral signature of the pressure fluctuations can be used to classify the dominant flow regimeBy exploring the spectral signature of pressure fluctuations at the larger scale, we are able to infer the underlying pore‐scale dynamics [ABSTRACT FROM AUTHOR]

• Micro-CT imaging is applied to measure relative permeability of microporous carbonate. • We devise a differential imaging method to quantify oil fraction in micro-porosity. • We show that significant fraction of oil from micro-porosity can be recovered. • We characterise intermittent flow of oil and brine. • We show that flow intermittency is dependent on pore and throat size. We imaged the steady-state flow of brine and decane (oil) at different fractional flows during dual injection in a micro-porous limestone, Estaillades, using X-ray micro-tomography. We applied differential imaging to: (a) distinguish micro-porous regions from macro-pores, and (b) determine fluid pore occupancy in both regions, and relative permeability at a capillary number, Ca = 7.3 × 10−6. The sample porosity was approximately 28%, with 7% in macro-pores and 21% in pores that could not be directly resolved (micro-porosity). Fluid occupancy in micro-porosity was classified into three sub-phases: micro-pore space with oil, micro-pore space with brine, and micro-pores partially filled with oil and brine. Our method indicated an initially higher oil recovery from micro-porosity, consistent with waterflooding in a water-wet rock. The fractional flow and relative permeabilities of the two fluids were obtained from measurements of the pressure differential across the sample and the saturation calculated from the images. The brine saturation and relative permeabilities are impacted by the presence of water-wet micro-porosity which provides additional connectivity to the phases. Furthermore, we find that in addition to brine and decane, a fraction of the macroscopic pore space contains an intermittent phase, which is occupied either by brine or decane during the hour-long scan time. Pore and throat occupancy of oil, brine and intermittent phase were obtained from images at different fractional flows using the generalized pore network extracted from the image of macro-pores. The intermittent phase, where the occupancy fluctuated between oil-filled and brine-filled, was predominantly located in the small and intermediate size pores and throats. Overall, we establish a new experimental methodology to: (i) quantify initial and recovered oil in micro-pores, (ii) characterise intermittent flow, and (iii) measure steady-state relative permeability in carbonates, which is shown to be greatly influenced by micro-porosity. [ABSTRACT FROM AUTHOR]

Highlights • Our novel procedure of injecting oil after reactive transport has revealed previously unidentified (ghost) regions of partially-dissolved grains of a carbonate rock. • X-ray micro-tomography and FIB-SEM techniques were used to identify and resolve these ghost regions in three-dimensions at the nm- to µm-scale. • Ignoring the presence of these ghost regions can result in the overestimation of porosity and permeability predicted from segmented X-ray tomographic images. Abstract One of the major concerns of carbon capture and storage (CCS) projects is the prediction of the long-term storage security of injected CO 2. When injected underground in saline aquifers or depleted oil and gas fields, CO 2 mixes with the resident brine to form carbonic acid. The carbonic acid can react with the host carbonate rock, and alter the rock structure and flow properties. In this study, we have used X-ray micro-tomography and focused ion beam scanning electron microscopy (FIB-SEM) techniques to investigate the dissolution behavior in wettability-altered carbonate rocks at the nm- to µm-scale, to investigate CO 2 storage in depleted oil fields that have oil-wet or mixed-wet conditions. Our novel procedure of injecting oil after reactive transport has revealed previously unidentified (ghost) regions of partially-dissolved rock grains that were difficult to identify in X-ray tomographic images after dissolution from single fluid phase experiments. We show that these ghost regions have a significantly higher porosity and pore sizes that are an order of magnitude larger than that of unreacted grains. The average thickness of the ghost regions as well as the overall rock dissolution decreases with increasing distance from the injection point. During dissolution micro-porous rock retains much of its original fabric. This suggests that considering the solid part of these ghost regions as macro (bulk) pore space can result in the overestimation of porosity and permeability predicted from segmented X-ray tomographic images, or indeed from reactive transport models that assume a uniform, sharp reaction front at the grain surface. [ABSTRACT FROM AUTHOR]

This paper examines the role of momentum transfer across fluid-fluid interfaces in two-phase flow. A volume-of-fluid finite-volume numerical method is used to solve the Navier-Stokes equations for two-phase flow at the micro-scale. The model is applied to investigate viscous coupling effects as a function of the viscosity ratio, the wetting phase saturation and the wettability, for different fluid configurations in simple pore geometries. It is shown that viscous coupling effects can be significant for certain pore geometries such as oil layers sandwiched between water in the corner of mixed wettability capillaries. A simple parametric model is then presented to estimate general mobility terms as a function of geometric properties and viscosity ratio. Finally, the model is validated by comparison with the mobilities computed using direct numerical simulation. [ABSTRACT FROM AUTHOR]

In the color gradient lattice Boltzmann model (CG-LBM), a fictitious-density wetting boundary condition has been widely used because of its ease of implementation. However, as we show, this may lead to inaccurate results in some cases. In this paper, a new scheme for the wetting boundary condition is proposed which can handle complicated 3D geometries. The validity of our method for static problems is demonstrated by comparing the simulated results to analytical solutions in 2D and 3D geometries with curved boundaries. Then, capillary rise simulations are performed to study dynamic problems where the three-phase contact line moves. The results are compared to experimental results in the literature (Heshmati and Piri, 2014). If a constant contact angle is assumed, the simulations agree with the analytical solution based on the Lucas–Washburn equation. However, to match the experiments, we need to implement a dynamic contact angle that varies with the flow rate. [ABSTRACT FROM AUTHOR]

We present an experimental and numerical study of transport in carbonates during dissolution and its upscaling from the pore (∼μm) to core (∼cm) scale. For the experimental part, we use nuclear magnetic resonance (NMR) to probe molecular displacements (propagators) of an aqueous hydrochloric acid (HCl) solution through a Ketton limestone core. A series of propagator profiles are obtained at a large number of spatial points along the core at multiple time-steps during dissolution. For the numerical part, first, the transport model—a particle-tracking method based on Continuous Time Random Walks (CTRW) by Rhodes et al. (2008)—is validated at the pore scale by matching to the NMR-measured propagators in a beadpack, Bentheimer sandstone, and Portland carbonate (Scheven et al., 2005). It was found that the emerging distribution of particle transit times in these samples can be approximated satisfactorily using the power law function ψ ( t ) ∼ t −1 − β , where 0 < β < 2. Next, the evolution of the propagators during reaction is modelled: at the pore scale, the experimental data is used to calibrate the CTRW parameters; then the shape of the propagators is predicted at later observation times. Finally, a numerical upscaling technique is employed to obtain CTRW parameters for the core. From the NMR-measured propagators, an increasing frequency of displacements in stagnant regions was apparent as the reaction progressed. The present model predicts that non-Fickian behaviour exhibited at the pore scale persists on the centimetre scale. [ABSTRACT FROM AUTHOR]

This study presents a simple and robust numerical scheme to model two-phase flow in porous media where capillary forces dominate over viscous effects. The volume-of-fluid method is employed to capture the fluid-fluid interface whose dynamics is explicitly described based on a finite volume discretization of the Navier–Stokes equations. Interfacial forces are calculated directly on reconstructed interface elements such that the total curvature is preserved. The computed interfacial forces are explicitly added to the Navier–Stokes equations using a sharp formulation which effectively eliminates spurious currents. The stability and accuracy of the implemented scheme is validated on several two- and three-dimensional test cases, which indicate the capability of the method to model two-phase flow processes at the micro-scale. In particular we show how the co-current flow of two viscous fluids leads to greatly enhanced flow conductance for the wetting phase in corners of the pore space, compared to a case where the non-wetting phase is an inviscid gas. [ABSTRACT FROM AUTHOR]

We investigate the impact of capillary backpressure on spontaneous counter-current imbibition. For such displacements in strongly water-wet systems, the non-wetting phase is forced out through the inlet boundary as the wetting phase imbibes into the rock, creating a finite capillary backpressure. Under the assumption that capillary backpressure depends on the water saturation applied at the inlet boundary of the porous medium, its impact is determined using the continuum modelling approach by varying the imposed inlet saturation in the analytical solution. We present analytical solutions for the one-dimensional incompressible horizontal displacement of a non-wetting phase by a wetting phase in a porous medium. There exists an inlet saturation value above which any change in capillary backpressure has a negligible impact on the solutions. Above this threshold value, imbibition rates and front positions are largely invariant. A method for identifying this inlet saturation is proposed using an analytical procedure and we explore how varying multiphase flow properties affects the analytical solutions and this threshold saturation. We show the value of this analytical approach through the analysis of previously published experimental data. [ABSTRACT FROM AUTHOR]

We use high‐resolution three‐dimensional X‐ray imaging to study hydrogen injection and withdrawal in the pore space of Bentheimer sandstone. The results are compared with a replicate experiment using nitrogen. We observe less trapping with hydrogen because the initial saturation after drainage is lower due to channeling. Remarkably we observe that after imbibition, if the sample is imaged again after 12 hr, there is a significant rearrangement of the trapped hydrogen. Many smaller ganglia disappear while the larger ganglia swell, with no detectable change in overall gas volume. For nitrogen, the fluid configuration is largely unchanged. This rearrangement is facilitated by concentration gradients of dissolved gas in the aqueous phase—Ostwald ripening, We estimate the time‐scales for this effect to be significant, consistent with the experimental observations. The swelling of larger ganglia potentially increases the gas connectivity, leading to less hysteresis and more efficient withdrawal. Plain Language Summary: The supply of energy by hydrogen is a key component of a zero‐carbon economy; an essential part of global hydrogen use is underground storage at the gigatonne scale in porous rocks. However, the behavior of hydrogen in the subsurface is not well understood. Using high‐resolution three‐dimensional X‐ray imaging, we observe that in the pore‐space, there is a significant rearrangement of hydrogen trapped by water. Many smaller trapped bubbles disappear while the larger ones grow. The process is driven by differences in the amount of gas dissolved in the aqueous phase: this is called Ostwald ripening. We estimate the time‐scales effect as being important, which are consistent with the experimental observations. The work implies that there is less trapping for hydrogen injection and withdrawal compared to equivalent hydrocarbon systems, which makes the process efficient. Key Points: Hydrogen trapping and rearrangement in porous rock have been observed in situOstwald ripening is observed over timescales consistent with theoretical predictionsThe results imply less trapping and hysteresis than with completely insoluble gas [ABSTRACT FROM AUTHOR]

The energy transition is the pathway to transform the global economy away from its current dependence on fossil fuels towards net zero carbon emissions. This requires the rapid and large-scale deployment of renewable energy. However, most renewables, such as wind and solar, are intermittent and hence generation and demand do not necessarily match. One way to overcome this problem is to use excess renewable power to generate hydrogen by electrolysis, which is used as an energy store, and then consumed in fuel cells, or burnt in generators and boilers on demand, much as is presently done with natural gas, but with zero emissions. Using hydrogen in this way necessitates large-scale storage: the most practical manner to do this is deep underground in salt caverns, or porous rock, as currently implemented for natural gas and carbon dioxide. This paper reviews the concepts, and challenges of underground hydrogen storage. As well as summarizing the state-of-the-art, with reference to current and proposed storage projects, suggestions are made for future work and gaps in our current understanding are highlighted. The role of hydrogen in the energy transition and storage methods are described in detail. Hydrogen flow and its fate in the subsurface are reviewed, emphasizing the unique challenges compared to other types of gas storage. In addition, site selection criteria are considered in the light of current field experience. [ABSTRACT FROM AUTHOR]

Multiphase flow in porous media is strongly influenced by the wettability of the system, which affects the arrangement of the interfaces of different phases residing in the pores. We present a method for estimating the effective contact angle, which quantifies the wettability and controls the local capillary pressure within the complex pore space of natural rock samples, based on the physical constraint of constant curvature of the interface between two fluids. This algorithm is able to extract a large number of measurements from a single rock core, resulting in a characteristic distribution of effective in situ contact angle for the system, that is modelled as a truncated Gaussian probability density distribution. The method is first validated on synthetic images, where the exact angle is known analytically; then the results obtained from measurements within the pore space of rock samples imaged at a resolution of a few microns are compared to direct manual assessment. Finally the method is applied to X-ray micro computed tomography (micro-CT) scans of two Ketton cores after waterflooding, that display water-wet and mixed-wet behaviour. The resulting distribution of in situ contact angles is characterized in terms of a mixture of truncated Gaussian densities. [ABSTRACT FROM AUTHOR]

We study dissolution in a chemically heterogeneous medium consisting of two minerals with contrasting initial structure and transport properties. We perform a reactive transport experiment using CO2-saturated brine at reservoir conditions in a millimeter-scale composite core composed of Silurian dolomite and Ketton limestone (calcite) arranged in series. We repeatedly image the composite core using X-ray microtomography (XMT) and collect effluent to assess the individual mineral dissolution. The mineral dissolution from image analysis was comparable to that measured from effluent analysis using inductively coupled plasma mass spectrometry (ICP-MS). We find that the ratio of the effective reaction rate of calcite to that of dolomite decreases with time, indicating the influence of dynamic transport effects originating from changes in pore structure coupled with differences in intrinsic reaction rates. Moreover, evolving flow and transport heterogeneity in the initially heterogeneous dolomite is a key determinant in producing a two-stage dissolution in the calcite. The first stage is characterized by a uniform dissolution of the pore space, while the second stage follows a single-channel growth regime. This implies that spatial memory effects in the medium with a heterogeneous flow characteristic (dolomite) can change the dissolution patterns in the medium with a homogeneous flow characteristic (calcite). [ABSTRACT FROM AUTHOR]