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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., (Copyright © 2017 The Authors. Published by Elsevier B.V. All rights reserved.)

Underground storage permanence is a major concern for carbon capture and storage. Pumping CO2 into carbonate reservoirs has the potential to dissolve geologic seals and allow CO2 to escape. However, the dissolution processes at reservoir conditions are poorly understood. Thus, time-resolved experiments are needed to observe and predict the nature and rate of dissolution at the pore scale. Synchrotron fast tomography is a method of taking high-resolution time-resolved images of complex pore structures much more quickly than traditional µ-CT. The Diamond Lightsource Pink Beam was used to dynamically image dissolution of limestone in the presence of CO2-saturated brine at reservoir conditions. 100 scans were taken at a 6.1 µm resolution over a period of 2 hours. The images were segmented and the porosity and permeability were measured using image analysis and network extraction. Porosity increased uniformly along the length of the sample; however, the rate of increase of both porosity and permeability slowed at later times.

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.

Assessment of the viability of enhanced gas recovery (EGR), in which CO 2 is injected into natural gas reservoirs, requires accurate and appropriate reservoir simulations. These necessitate provision of parameters describing dispersion between the fluids. Here we systematically measure fluid dispersion in various rock cores (sandstones and carbonates), both dry and at irreducible water saturation, at reservoir conditions. In this manner we evaluate the impact of the irreducible water on the miscible displacement processes. As such this represents the first measurement of dispersion as a function of water saturation for supercritical gases in consolidated media. Complementary measurements of water spatial distribution along the rock axis, as well as the pore size distribution occupied by the water were performed using magnetic resonance techniques. Irreducible water was found to increase dispersivity by a factor of up to 7.3. The dispersion coefficient ( K ) was measured as a function of velocity and the data for both dry and water-containing samples were successfully combined on a K –Péclet number ( Pe ) plot, enabling ready future inclusion into EGR reservoir models. The power-law dependence of K upon Pe produced an exponent of 1.2 for dry and water-saturated sandstones and 1.4 for dry and water-saturated carbonates, consistent with literature results ( Bijeljic et al., 2011; Honari et al., 2015 ). [ABSTRACT FROM AUTHOR]

Reinjection of CO 2 into producing natural gas reservoirs is considered as a promising technology to improve gas recovery, mitigate atmospheric emissions and control climate change. However, natural gas and CO 2 are miscible at reservoir conditions and could result in CO 2 contamination of produced natural gas. This mixing process and consequently the viability of Enhanced Gas Recovery (EGR) projects can be quantitatively determined by reservoir simulations – such simulations require a description of gas dispersion. Here we conduct fluid transport experiments through carbonate and sandstone rock cores at various reservoir conditions to evaluate the effect of medium heterogeneity on the dispersion between supercritical CO 2 and CH 4 , accounting for erroneous contributions from entrance/exit and gravitational effects. Early breakthrough and long-tailed profiles are observed for one of the carbonate cores (Ketton) which is attributed to the existence of intra-grain micro-pores, which results in a persistent pre-asymptotic transport regime. Thus a revised model (Mobile-Immobile Model) was successfully used for this core to obtain dispersion coefficients characteristic of the eventual asymptotic regime. Both heterogeneous carbonate rocks considered exhibit higher dispersion than that observed in previously-measured homogeneous sandstone cores (Honari et al., 2013). The power law describing the dependency of dispersion coefficient on Péclet number at comparatively high interstitial displacement velocities gave an exponent of 1.2 for sandstones and 1.4 for carbonates, consistent with literature predictions (Bijeljic and Blunt, 2006; Bijeljic et al., 2011) based on pore-scale simulations. [ABSTRACT FROM AUTHOR]

Highlights: [•] Significant amounts of CO2 were trapped in a wide range of rock types. [•] The efficiency of trapping is independent of pore-morphology and chemistry. [•] The size distribution of residual clusters is broadly consistent with percolation theory. [ABSTRACT FROM AUTHOR]

Abstract: We investigate at the pore scale fluid-rock interactions that occur in the context of carbon dioxide (CO2) storage in saline carbonate aquifers. Brine saturated with super critical CO2 is injected into two carbonate samples (Estaillades limestone and an aquifer sample) at typical storage conditions (9MPa and 50oC). Dry high resolution micro-computed tomography scans are obtained prior to and after the experiments and the pore structure, connectivity and computed flow fields are compared using image analysis and pore-scale modeling techniques. We perform direct simulations of transport properties and velocity fields on the 3D scans and we extract representative pore-throat networks to compute average coordination number and assess changes in pore and throat size distributions. In this study, we experimentally mimic near wellbore region conditions by injecting fluids at relatively high flow rates. For high Péclet and Damkö hler numbers, experimental observations confirm the formation of highly conductive channels i.e wormholes. A significant increase in porosity and permeability is found with fewer pore and throats after dissolutionwhile the average coordination number does not change significantly. Flow becomes concentrated in the wormhole regions after reactions although a very wide range of velocities is still observed. [Copyright &y& Elsevier]

• In this oil-wet carbonate, micro-porosity plays a crucial role in flow connectivity. • The displacement is characterised by a thermodynamic contact angle of 120°. • The flow behaviour is different from a mixed-wet sandstone with angle close to 95°. • The carbonate case has a high brine rel-perm and a large/negative capillary pressure. High-resolution X-ray imaging combined with a steady-state flow experiment is used to demonstrate how pore-scale displacement affects macroscopic properties in an altered-wettability microporous carbonate, where porosity and fluid saturation can be directly obtained from the grey-scale micro-CT images. The resolvable macro pores are largely oil-wet with an average thermodynamic contact angle of 120°. The pore-by-pore analysis shows locally either oil or brine almost fully occupied the macro pores, with some oil displacement in the micro-porosity. We observed a typical oil-wet behaviour consistent with the contact angle measurement. The brine tended to occupy the larger macro pores, leading to a higher brine relative permeability, lower residual oil saturation, than under water-wet conditions and in a mixed-wet sandstone. The capillary pressure was negative and seven times larger in the carbonate than the sandstone, despite having a similar average pore size. These different displacement patterns are principally determined by the difference in wettability. [ABSTRACT FROM AUTHOR]

• A reactive transport model is developed using CTRW and validated with NMR experiment. • Both model and experiment effective reaction rates are 3 orders of magnitude lower than batch rates. • Model and experimental molecular propagators describe flow and porosity evolution. We develop a reactive transport model for dissolution of porous materials using a Continuous Time Random Walk (CTRW) formulation with first-order kinetics. Our model is validated with a dataset for a Ketton carbonate rock sample undergoing dissolution on injection of an acid, monitored using Nuclear Magnetic Resonance (NMR). The experimental data includes the 3D porosity distribution at the beginning and end of the experiment, 1D porosity profiles along the direction of flow during dissolution, as well as the molecular fluid displacement probability distributions (propagators). With the calibration of only a single parameter, we successfully predict the porosity changes and the propagators as a signature of flow heterogeneity evolution in the dissolution experiment. We also demonstrate that heterogeneity in the flow field leads to an effective reaction rate, limited by transport of reactants, that is almost three orders of magnitude lower than measured under batch reaction conditions. The effective reaction rate predicted by the model is in good agreement with the experimentally measured rate. Furthermore, as dissolution proceeds, the formation of channels in the rock focused the flow in a few fast-flowing regions. The predicted dissolution patterns are similar to those observed experimentally. This study establishes a workflow to calibrate and validate the CTRW reactive transport model with NMR experiments. [ABSTRACT FROM AUTHOR]

[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]

• 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]

• 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]

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 propose an experimental methodology to visualize asphaltene precipitation in the pore space of rocks and assess the reduction in permeability. We perform core flooding experiments integrated with X-ray microtomography (micro-CT). The simultaneous injection of pure heptane and crude oil containing asphaltene induces the precipitation of asphaltene in the pore space. The degree of precipitation is controlled by the measurement of differential pressure across the sample. After precipitation, doped heptane is injected to replace the fluid to enhance the contrast between precipitated asphaltene and doped heptane. The micro-CT images are segmented into three phases: void, precipitated asphaltene, and rock. In the experiment, we observed that the precipitated asphaltene which occupied 39.1% of the pore volume caused a 29-fold reduction in permeability. Furthermore, we analyze the spatial distribution of precipitated asphaltene which showed that the asphaltene tended to clog the larger pores. We also computed the flow field numerically on the images and obtained good agreement between simulated and measured permeability. The distribution of local velocity showed that after precipitation the flow was confined to narrow channels in the pore space. This method can be applied to any type of porous system with precipitation. [ABSTRACT FROM AUTHOR]

• Oil and water layers were not seen at near-miscible gas injection conditions. • Oil flows in centres of large pores rather than layers at near-miscible conditions. • Gas directly contacts water in the pore space at near-miscible conditions. • Microscopic displacement efficiency is highly improved at near-miscible conditions. • Gas occupies the biggest pores, while oil and water occupy pores of varying sizes. We study in situ three-phase near-miscible CO 2 injection in a water-wet carbonate rock at elevated temperature and pressure using X-ray microtomography. We examine the recovery mechanisms, presence or absence of oil layers, pore occupancy and interfacial areas during a secondary gas injection process. In contrast to an equivalent immiscible system, we did not observe layers of oil sandwiched between gas in the centre of the pore space and water in the corners. At near-miscible conditions, the measured contact angle between oil and gas was approximately 73°, indicating only weak oil wettability in the presence of gas. Oil flows in the centres of large pores, rather than in layers for immiscible injection, when displaced by gas. This allows for a rapid production of oil since it is no longer confined to movement in thin layers. A significant recovery factor of 80% was obtained and the residual oil saturation existed as disconnected blobs in the corners of the pore space. At equilibrium, gas occupied the biggest pores, while oil and water occupied pores of varying sizes (small, medium and large). Again, this was different from an immiscible system, where water occupied only the smallest pores. We suggest that a double displacement mechanism, where gas displaces water that displaces oil is responsible for shuffling water into larger pores than that seen after initial oil injection. This is only possible since, in the absence of oil layers, gas can contact water directly. The gas-oil and oil-water interfacial areas are lower than in the immiscible case, since there are no oil layers and even water layers in the macro-pore space become disconnected; in contrast, there is a larger direct contact of oil to the solid. These results could serve as benchmarks for developing near-miscible pore-scale modelling tools. [ABSTRACT FROM AUTHOR]