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Rapid implementation of large-scale carbon capture and storage is necessary to limit global warming this century. Amongst various CO2 storage sites, depleted oilfields provide an immediate option since injection infrastructure is in place and there is an economic benefit from enhanced oil recovery. To design secure carbon storage in oilfields, we need to understand how the three fluid phases – CO2, oil, and water – flow simultaneously in the microscopic pore spaces of the reservoir. In this PhD thesis, we present a novel methodology to study three-phase flow in porous media, at various wettability and gas-oil miscibility conditions, using X-ray microtomography. The use of X-ray imaging allows for a complete investigation of the pore-scale properties that control flow and trapping in three-phase flow, i.e., wettability order, spreading and wetting layers, and double/multiple displacement events. In addition, our advanced experimental and image analysis techniques permit access to key petrophysical properties including fluid saturations, capillary pressures, three-phase relative permeabilities and pore occupancy maps. The three-phase experiments we perform include unsteady-state and steady-state flow conditions and employ both laboratory-based and synchrotron X-ray sources. While laboratory-based scanners image the fluid configurations at the end of displacement or at steady-state equilibrium, synchrotron scanners allow us to capture the pore-scale dynamics during displacement. First, we investigate unsteady-state three-phase flow under near-miscible gas-oil conditions – where the gas-oil interfacial tension is ≤ 1 mN/m – and show that fluids display a unique behavior compared to that seen at immiscible conditions where the interfacial tension is larger by one order of magnitude. In a water-wet system, at near-miscible conditions, gas and oil appear to become neutrally wetting to the surface. This prevents oil from spreading in layers sandwiched between gas and water; the strict wettability order – water-oil-gas, from most to least wetting – seen at immiscible conditions breaks down. This facilitates the flow of oil and gas along the same path in the pore space occupying the centre of the larger pores, while water remains connected in wetting layers in the corners. While this behaviour is desirable for oil recovery, it can impact the storage security as oil can no longer trap CO2. In a weakly oil-wet system, the wettability order shifts from oil-water-gas to oil-gas-water as we move from immiscible to near-miscible conditions. As CO2 becomes the intermediate-wet phase, at near-miscible conditions, it forms spreading layers in the corners of the pore space. The existence of CO2 in spreading layers has huge implications on the storage design since its flow conductance is naturally restricted which implies that subsequent water injection is not necessary to prevent CO2 migration and escape. Next, we show that reservoir rocks can undergo severe wettability alterations rendering them strongly oil-wet. Under unsteady-state flow at immiscible conditions, we observe the predicted, but hitherto unreported, three-phase wettability order in strongly oil-wet rocks, where water occupies the largest pores, oil the smallest, while CO2 occupies pores of intermediate size. Although this wettability order is the same as that seen in a weakly oil-wet rock at near-miscible conditions, the pore-scale fluid configurations are different. While CO2, the intermediate-wet phase, spreads in layers at near-miscible conditions, at immiscible conditions, it exists in the pore space as disconnected ganglia. The existence of CO2 in disconnected clusters, at immiscible conditions, allows for the capillary trapping of gas by oil in the centre of the pores which is not possible when CO2 forms layers. However, capillary trapping of gas by water is still impossible at both miscibility conditions since gas is more wetting to the surface than water. This implies that water re-injection to disconnect the CO2 in the reservoir is unnecessary in both cases. Using a synchrotron X-ray source, we then investigate the invasion pattern during unsteady-state two- and three-phase flow – water injection followed by gas – in a strongly oil-wet reservoir rock at immiscible conditions. During water injection, we observe that the displacement of oil by water is a drainage-like process, where water advances as a connected front displacing oil in the centre of the pores, confining the oil to wetting layers. The displacement is an invasion percolation process, where throats, the restrictions between pores, fill in order of size, with the largest available throats filled first. Moreover, we observe drainage associated pore-filling dynamics including Haines jumps and snap-off events. Subsequently, during gas injection, a distinct invasion pattern is observed for three-phase flow, where gas progresses through the pore space in the form of disconnected clusters mediated by double and multiple displacement events. Gas advances in a process we name three-phase Haines jumps, during which gas re-arranges its configuration in the pore space, retracting from some regions to enable the rapid filling of multiple pores. The gas retraction leads to a permanent disconnection of gas ganglia, which do not reconnect as gas injection proceeds. Lastly, we develop a novel experimental approach to investigate steady-state three-phase flow using pore-scale X-ray imaging. Our newly designed flow cell allows for the differential pressure across the system to be measured, enabling for the simultaneous determination of three-phase relative permeability and capillary pressure. We first investigate steady-state three-phase flow in a water-wet system at immiscible conditions, where the wettability order is water-oil-gas, from most to least wetting. We discover a unique flow dynamics where gas is disconnected across the system despite its continuous injection; gas flows by periodically opening critical flow pathways in intermediate-sized pores. We observe intermittent gas-oil and oil-water behaviour even under capillary-dominated conditions in three-phase flow. At steady-state conditions, it was impossible to displace the trapped gas in our water-wet system since it is double capillary trapped by spreading, oil, and wetting, water, layers. Gas has the lowest relative permeability in the pore space, while oil the highest. Next, we study steady-state three-phase flow in a mixed-wet system at immiscible conditions with an oil-water-gas wettability order. We observe that the gas flow is disconnected, similar to the water-wet system. However, intermittency was more pronounced in the mixed-wet system. The oil relative permeability was the highest in the pore space followed by water, then gas like the water-wet system. The impact of saturation history on gas and water relative permeabilities was larger than its impact on the oil relative permeability. Surprisingly, there was no gas trapping in the system due to its mixed-wet nature which prevents oil and water from completely surrounding the gas phase. This thesis presents an effective and universal methodology to study three-phase flow in porous media at the pore-scale using X-ray microtomography. While the results were strictly discussed in the context of subsurface storage and recovery, it can have implications for many other engineering applications including microfluidic devices, packed bed chemical reactors and catalysis. The findings of this thesis can be used to advise on the design of the optimal conditions to store as much CO2 as possible while maximizing oil production in CO2-enhanced oil recovery projects. Open Access

We present a new model to simulate multispecies reactive transport on pore space images. We solve the Navier-Stokes equations and the advection-diffusion equation for concentration fields on an unstructured grid using the finite volume method. We couple it with the chemical model Reaktoro, which we use to calculate the chemical equilibrium 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 and find that, despite the relative homogeneity of the bead pack, the concentration fields of the products can be asymmetric because of the interplay between transport and chemical equilibrium. 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 larger amount of matter available for reaction. Reaction is more favoured in the faster-flowing regions. 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. Furthermore, we study multispecies mixing and reaction in a more heterogeneous carbonate sample. We use a micro-CT image of Portland limestone containing both macroporosity resolved at the image resolution, and sub-resolution microporosity which is quantified using difference imaging. We extend our solver to accommodate transport and reaction in microporous regions. We demonstrate how the highly variable flow field in carbonate allows reactants and products to disperse more rapidly compared to the more homogeneous bead pack, resulting in a highly non-uniform reaction rate and concentration distribution. This is due to a complex interplay between advection-dominated flow and reaction in the connected fast-flowing macroporous regions, and diffusion-mediated transport and reaction in microporosity. Multispecies mixing and reaction in natural rocks are much more complex than hitherto observed, which needs to be considered in reactive transport studies at different length-scales. Finally, we test the applicability of our code to study dissolution. We first validate our code on multispecies dissolution of a single sphere and a semi-infinite solid. Then, we study dissolution on a micro-CT image composed of dolomite and calcite in ratio 10:1. We find that fast channels are strongly associated with dissolved dolomite, high concentrations of reactants, and low concentrations of products. Open Access

The sequestration of carbon dioxide (CO2) into geologic formations is one of the long-term solutions proposed to mitigate atmospheric CO2 concentrations [1]. Potential storage sites include deep saline aquifers and depleted hydrocarbon reservoirs. In the case of carbonate reservoirs, the possibility of significant dissolution reaction taking place between CO2, in situ brines and rock is very real. Proposed in this thesis is a method to dynamically image reactive transport in carbonates at subsurface conditions, representing the movement of CO2 saturated brine in the reservoir. The work will focus on understanding reactive transport in carbonate reservoirs by imaging changes in the pore structure, porosity and permeability in representative rock samples induced by the simultaneous flow and reaction of CO2 saturated brine at reservoir conditions. X-ray micro-tomography will be the imaging tool of choice to investigate pore structure changes during reactive transport experiments. Effluent from the dissolution reactions will be collected for analysis via inductively coupled plasma mass spectrometry (ICP-MS) to monitor the preferential dissolution of different minerals in the rock. Direct simulation on 3D images from micro-tomography (μCT) and network modelling tools will be used for further analysis of the rock property evolution. In this thesis we study dissolution of carbonate minerals with an increasing level of complexity to observe the effect of chemical and physical heterogeneity. We start with a single mineral dolomite case where we investigate the impact of rock heterogeneity and flowrate on reaction rates and dissolution dynamics. Next we study dissolution in a chemically heterogeneous medium consisting of two minerals with contrasting initial structure and transport properties, but with uniform spatial distribution. Finally, we studied a heterogeneous reservoir sample consisting of dolomite and calcite (having the ratio 8 to 1) which had a non-uniform spatial distribution. Open Access

In recent years, oil shale has attracted renewed attention as an unconventional energy resource, with vast and largely untapped reserves. Oil shale is a fine-grained sedimentary rock containing a sufficiently high content of immature organic matter from which shale oil and combustible gas can be extracted through pyrolysis. Several complex physical and chemical changes occur during the pyrolysis of oil shale where macromolecular network structures of kerogen are thermally decomposed. The pyrolysis of oil shale leads to the formation of a microscopic pore network in which the oil and gas products flow. The pore structure and the connectivity are significant characteristics which determine fluid flow and ultimate hydrocarbon recovery. In this thesis, a state-of-the-art multi-scale multi-dimensional workflow was applied to image and quantify the Lacustrine Eocene Green River (Mahogany Zone) formation, the world’s largest oil shale deposit. Samples were imaged before, during and after pyrolysis using laboratory and synchrotron-based X-ray Micro-tomography (µCT), Optical Microscopy, Automated Ultra-High Resolution Scanning Electron Microscopy (SEM), MAPS Mineralogy (Modular Automated Processing System) and Focused Ion Beam Scanning Electron Microscopy (FIB-SEM). Results of image analysis using optical (2-D), SEM (2-D), and µCT (3-D) reveal a complex fine-grained microstructure dominated by organic-rich parallel laminations in a tightly bound heterogeneous mineral matrix. MAPS Mineralogy combined with ultrafast measurements highlighted mineralogic textures dominated by dolomite, calcite, K-feldspar, quartz, pyrite and illitic clays. From high resolution backscattered electron (BSE) images, intra-organic, inter-organic-mineral, intra and inter-mineral pores were characterised with varying sizes and geometries. A detailed X-ray µCT study with increasing pyrolysis temperature (300-500°C) at 12 µm, 2 µm and 0.8 µm voxel sizes illuminated the evolution of pore structure, which is shown to be a strong function of the spatial distribution of organic content. In addition, FIB-SEM 3-D visualisations showed an unconnected pore space of 0.5% with pores sizes between 15 nm and 22 nm for the un-pyrolysed sample and a well-connected pore space of 18.2% largely with pores of equivalent radius between 1.6 µm and 2.0 µm for the pyrolysed sample. Synchrotron 4-D results at a time resolution of 160 seconds and a voxel size of 2 µm revealed a dramatic change in porosity accompanying pyrolysis between 390-400°C with the formation of micron-scale heterogeneous pores followed by interconnected fracture networks predominantly along the organic-rich laminations. Combining these techniques provides a powerful tool for quantifying petrophysical properties before, during and after oil shale pyrolysis. Quantitative 2-D, 3-D and 4-D imaging datasets across nm-µm-mm length scales are of great value to better understand, predict and model dynamics of pore structure change and hydrocarbon transport and production during oil shale pyrolysis. Open Access

Reactive transport is an important field of study in the earth sciences. It captures both natural phenomena, and industrial and environmental applications, including transport of pollutants in the subsurface, nuclear waste storage, and carbon storage. The aim of this thesis is to provide a better understanding of coupled physico-chemical processes governing these phenomena as well as to be used as tools for better understanding these environmental applications. We introduce from first principles a novel pore-scale modelling approach capable of simulating single-phase fluid-fluid reactive transport directly on voxels of 3D images of porous media constructed from X-ray tomography. We use a streamline-based particle tracking method for simulating flow and transport, while for reaction to occur, both reactants must be within a diffusive distance. We assign a probability of reaction, as a function of the reaction rate constant and the diffusion length. The model for reaction is validated against analytical solutions in a free fluid as well as against experimental data on reactive transport in porous media. It takes into account the degree of incomplete mixing present at the sub-pore level. We demonstrate the nature of dynamic changes in the reaction rate, which is related to the degree of pore-scale mixing. Our model does not use any calibrating parameters to fit empirical data unlike other models published in the literature. The model is then extended to investigate the impact of pore structure heterogeneity, transport, and reaction conditions on the overall reaction rate in porous media by studying different classes of porous media. The overall reaction rate varies significantly according to the degree of heterogeneity and transport conditions. It is found that the rate of reaction is a subtle combination of the amount of mixing and spreading that cannot be predicted from the dispersion coefficient alone. At low Péclet number, the effective reaction rate is principally controlled by the amount of mixing due to diffusion. On the other hand, at high Péclet number the reaction rate is controlled by a combination of pore-scale mixing due to spreading and the degree of heterogeneity of the pore structure. Open Access

It is well established that more than half of the world’s hydrocarbon reserves are contained in carbonate reservoirs. In a global context, which is characterized by an increasing demand in energy, population growth and overall economic development, it is very important to unlock potential carbonate resources while mitigating the effects of climate change. Moreover, significant volumes of carbon dioxide – the major greenhouse gas contributor to global warming – can be stored in carbonate subsurface formations such as carbonate depleted reservoirs and deep saline aquifers. Therefore, better understanding of carbonate porous media has a wide range of major industrial and environmental applications. However, because of complex pore structures, including the presence of micro-porosity, heterogeneities at different scales, combined with high chemical reactivity, it remains very challenging to describe flow and transport in carbonates. In this thesis, we focus on carbonate porous media and aim to better describe flow, transport and reaction in them. The main application of this work is related to carbon storage in deep saline carbonate aquifers. More particularly, we address fluid-rock interactions e.g. wettability alterations and reactive transport, that occur in carbonate formations. First, we investigate the impact of wettability alteration on multi-phase flow properties. We use pore-network modelling to analyze the impact of wettability alteration by modelling water-flood relative permeability for six different carbonate samples with different connectivity. Pore-scale multi-phase flow physics is described in detail and the efficiency of water-flooding in mixed-wet carbonates is related to the wettability and pore connectivity. We study six carbonate samples. Four quarry samples – Indiana, Portland, Guiting and Mount Gambier – and two subsurface samples obtained from a deep saline Middle Eastern aquifer. The pore space is imaged in three dimensions using X-ray micro-tomography at a resolution of a few microns. The images are segmented into pore and void and a topologically representative network of pores and throats is extracted from these images. We then simulate quasi-static displacement in the networks. We represent mixed-wet behaviour by varying the oil-wet fraction of the pore space. The relative permeability is strongly dependent on both the wettability and the average coordination number of the network. We show that traditional measures of wettability based on the point where the relative permeability curves cross are not reliable. Good agreement is found between our calculations and measurements of relative permeability on carbonates in the literature. The work helps establish a library of benchmark samples for multi-phase flow and transport computations. The implications of the results for field-scale displacement mechanisms are discussed, and the efficiency of waterflooding as an oil recovery process in carbonate reservoirs is assessed depending on the wettability and pore space connectivity. Secondly, we investigate at the laboratory column scale (50 cm), fluid-rock interactions that occur through the injection of an acidic solution into carbonate porous media. Laboratory columns are packed with crushed and sieved porous Guiting carbonate grains. Therefore a homogenous porous medium at the Darcy scale is created and the effect of micro-heterogeneities on transport and reactive transport properties is highlighted. We first conduct a series of passive tracer experiments. Salinity is used as a non-reactive tracer as brine is injected at a constant flow rate into columns pre-saturated with equilibrated deionised water. Solute breakthrough curves are experimentally obtained by measuring the conductivity of collected effluent samples. Subsequently, by solving the advection-dispersion equations using PHREEQC geochemical software, we compare the experimental measurements with numerical predictions of breakthrough curves. A good match is obtained for a dual porosity model and a dispersion coefficient is estimated. We then investigate reactive transport by injecting at constant flow rate acidic brine (hydrochloric acid diluted in saline brine with an overall pH of 3) into columns pre-saturated with equilibrated brine. We measure the effluent concentrations using ICP-AES (inductively coupled plasma atomic emission spectroscopy) Moreover; scanning electron microscopy (SEM) is used to determine single grain-scale changes. We assess the impact of flow rate on the resident time distribution of solutes and reaction profiles along the columns. We discuss challenges encountered regarding the reproducibility of the results and we highlight the implications of such phenomenological studies on carbon storage in carbonates. Finally, we experimentally examine fluid-rock interactions that are induced by the injection of supercritical CO2 (sc-CO2) in carbonate formations at the pore scale. I designed and built a novel experimental apparatus that allows the injection of brine enriched with sc-CO2 at typical CO2 storage conditions. In our experiments the temperature is 500C and the injecting pressure is 9MPa. A novel methodology that combines pore-scale imaging, core flooding and pore-scale modelling is applied in the context of CO2-carbonate-brine interactions. We experimentally use a high pressure and temperature mixing vessel to generate brines enriched with sc-CO2.The mixture is then injected using high precision piston pumps at a constant flow rate (Q=0.1 ml/min) into carbonate micro samples (5 mm diameter and 20 mm length) saturated with pre-equilibrated high salinity brine. We measure the permeability changes in real time during the injection of reactive fluids, In addition, 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 modelling techniques. We perform direct simulations of transport properties and velocity fields on the three-dimensional scans and we extract representative pore-throat networks to compute average coordination number and assess changes in pore and throat size distributions. Moreover, we assess the impact of reaction rate on reactive transport. We alter the reaction rate and hence the Damkӧhler number by under saturating the sc-CO2/brine mixture with crushed and sieved carbonate grains. Two regimes of dissolution are experimentally observed: dominant wormholing and a more uniform dissolution regime. High resolution 3D scans of the dissolution patterns confirm these observations. Permeability increases over several order of magnitude with wormholing whereas for the uniform dissolution, the increase in permeability is less pronounced. Overall, fewer pore and throats are present after dissolution while 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. We then compare the observed results for single phase flow (wormholing induced by the injection of single phase brine saturated with sc-CO2) to two-phase flow reactive flow experiments (co injection of sc-CO2 and brine). Results show that wormholing is also seen in the two-phase experiments. Directions for future research in the area of fluid-rock interactions are then discussed. Open Access

CO2 storage in saline aquifers (sandstone/carbonate types) has been proposed as a promising solution to help reduce CO2 emissions to the atmosphere. CO2 will likely be stored as a dense, supercritical (sc.) phase. There are different mechanisms by which CO2 could be stored safely underground; structural and stratigraphic trapping, dissolution trapping, capillary trapping, and mineral trapping. I study capillary trapping. We assume that in the middle of a CO2 plume, many kilometres in extent, the CO2, brine and rock have been in mutual contact for several years. In these circumstances, the degree of capillary trapping is determined by a displacement of CO2 by brine under these equilibrated conditions. Reproducing such conditions in the laboratory poses a challenge. I have measured the first trapping curve, the relation between initial and residual CO2 saturation, for carbonates in the literature, as well as contributing to the first data on sandstones. For capillary trapping experiment, the porous plate method was used during primary drainage. Two sandstones (Berea and Doddington) and two types of carbonates (Ketton and Indiana) were studied. These experiments were conducted at temperatures of 33, 50, and 70 ˚C and 9 MPa pressure, which matches the conditions observed for several current and planned storage sites. Two displacement steps, primary drainage and water flooding were followed to reach residually trapped CO2 saturation. The isothermal de-pressurization method was used to measure the amount of scCO2 residually trapped. The drainage capillary pressure curve, the Leverett J-function and the trapping curve were measured. During capillary trapping experiments, the brine was equilibrated with CO2 to achieve immiscible displacement. We used a stirred reactor, to equilibrate CO2 with brine. The solubility of CO2 in brine was also measured using the isothermal depressurization method and compared with data in the literature.In Berea sandstone the trapping curves at 33, 50 and 70˚C were compared. We showed that temperature (density) variation has no effect on the saturation of scCO2 that is residually trapped. In Doddington sandstone our result was consistent with that from a micro-flow cell in which the trapped scCO2 was imaged using an X-ray source at the pore scale. We find that significant quantities of the CO2 can be trapped, with residual saturations up to 35%, but less than in analogue experiments where oil is displaced by brine. Hence, it is hypothesized that scCO2-brine systems in sandstones are weakly water-wet with less trapping than the more strongly wetting analogues. Capillary trapping in carbonates is very challenging. In carbonates, another step was required, where brine/CO2/carbonate will be equilibrated together before running the capillary trapping experiment. The apparatus used for sandstone rocks was modified so that the geochemical reaction between CO2/rock was accounted for. Samples are taken and analysed to ensure that the brine/CO2 mixture is saturated with carbonate minerals. In Indiana, the CO2 trapping curve for scCO2 at 50 ˚C and 9 MPa was compared with that of gaseous CO2 at 50 ˚C and 4.2 MPa. A scCO2 residual trapping endpoint of 23.7% was observed in Indiana for scCO2, with a smaller trapping end point in Ketton limestone. This indicates a slightly less trapping of scCO2 in carbonates than in sandstone. There is also less trapping for gaseous CO2 (endpoint of 18.8%). The system appears to be more water-wet under scCO2 conditions, which is different from the trend observed in Berea; the greater concentration of Ca2+ in brine at higher pressure was hypothesised to lead to more water-wet conditions. Our work indicates that capillary trapping could effectively store CO2 in carbonate aquifers.

Fluid flow and dispersion of solute particles are modelled directly on three-dimensional pore-space images of rock samples. To simulate flow, the finite-difference method combined with a standard predictor-corrector procedure to decouple pressure and velocity is applied. We study the permeability and the size of representative elementary volume (REV) of a range of consolidated and unconsolidated porous media. We demonstrate that the flow-based REV is larger than for geometry-based properties such as porosity and specific surface area, since it needs to account for the tortuosity and connectedness of the flow paths. For solute transport we apply a novel streamline-based algorithm that is similar to the Pollock algorithm common in field-scale reservoir simulation, but which employs a semi-analytic formulation near solid boundaries to capture, with sub-grid resolution, the variation in velocity near the grains. A random walk method is used to account for mixing by molecular diffusion. The algorithm is validated by comparison with published results for Taylor-Aris dispersion in a single capillary with a square cross-section. We then accurately predict experimental data available in the literature for longitudinal dispersion coefficient as a function of Peclet number. We study a number of sandpack, sandstone and carbonate samples for which we have good quality three-dimensional images. There is a power-law dependence of dispersion coefficient as a function of Peclet number, with an exponent that is a function of pore-space heterogeneity: the carbonates we study have a distinctly different behaviour than sandstones and sandpacks. This is related to the differences in transit time probabilities of solute particles travelling between two neighbouring voxels. We then study the non-Fickian behaviour of solute transport in porous media by modelling the NMR propagators and the time-dependent dispersion coefficients of different rock types. The behaviour is explained using Continuous Time Random Walk (CTRW) theory: transport is qualitatively different for the complex porous media such as carbonates compared to the sandstone or sandpack, with long tailing and an almost immobile peak concentration. We discuss extensions of the work to reactive transport and the simulation of transport in finely-resolved images with billions of voxels.