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We simulate two sets of dissolution experiments in which CO2-saturated solutions are injected into calcite formations. We explore the impact of non-linear reaction kinetics and charge-coupled ion transport in systems representing different levels of flow and mineralogical complexity. First, we flow CO2-saturated water and brine through cylindrical channels drilled through solid calcite cores and compare directly with experimental dissolution rates. We find that simulations using a linear saturation model match experimental results much better than the batch-reactor-derived non-linear saturation model. The use of a coupled diffusion model causes only a very small increase in the overall dissolution rate compared to a single diffusion coefficient, due to the increase in transport rates of reaction products, particularly the highly charged Ca2+ ion. We also determine the relative importance of the two calcite dissolution pathways, with H+ and H2CO3, and conclude that the H2CO3 – calcite reaction is by far the more dominant, in contrast with common assumptions in the literature. Then, we compare to the experiments of Menke et al. (2015) in which CO2-saturated brine was injected into a microporous Ketton carbonate, and compare dissolution rates over time. We find that including non-linear saturation behaviour markedly changes the simulated dissolution rate, by up to a factor of 0.7 in the case of the experimentally derived saturation model of Anabaraonye (2017), however neither case matches the experimental result which is several times slower than the simulation. Including the effects of coupled ion transport lead to virtually no change in overall dissolution rate due to the convection dominated behaviour. The model also shows differences in the trend of the dissolution rate over time observed in Menke et al, with an approximately linear relationship with time compared to the experimental square-root dependence on time. We conclude that the geochemical model may need to include other effects such as dissolution inside microporous regions.

One of the major concerns of carbon capture and storage (CCS) projects is the prediction of the long-term storage security of injected CO2. When injected underground in saline aquifers or depleted oil and gas fields, CO2 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 CO2 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.

Pore-scale visualization was employed to investigate evaporative drying of brine and associated salt deposition at different wetting conditions, using a 2.5D etched-silicon/glass micromodel based on a thin section image of a carbonate rock. We also compared air drying with CO2 drying, with the latter having important applications in CO2 sequestration processes. The resulting permeability impairment was also measured. For deionized water in a water-wet model, we observed the three classical periods of evaporation: the constant rate period (CRP), the falling rate period (FRP), and the receding front period (RFP). The length of the deionized water CRP was much shorter for a uniformly oil-wet model, but mixed wettability made little difference to the drying process. For brine systems at all wetting conditions, the dry area became linear with the square root of time after a short CRP. This is due to the deposited salt acting as a physical barrier to hydraulic connectivity, unlike the case of deionized water, which is due to capillary disconnection from the fracture channel. For the water-wet model, we observed two regions of a linear downward trend in the matrix and fracture permeability measurements. A similar trend was observed for the mixed-wet systems. However, for the oil-wet systems, fracture permeability only changes slightly even for 360 g/L brine, a result of the absence of salt deposits in the fracture caused by the early rupture of the liquid-wetting films needed to aid hydraulic connectivity. Overall, matrix permeability for all wetting conditions decreased with increasing brine concentration and was almost total for the 360 g/L brine. Finally, using CO2 rather than air as carrier gas makes the brine phase more wetting, especially in the deionized water case, with the result that hydraulic connectivity was maintained for longer in the CO2 case compared to dry out with air.

The aim of this work is to better understand fluid displacement mechanisms at the pore scale in relation to capillary-filling rules. Using specifically designed micro-models we investigate the role of pore body shape on fluid displacement during drainage and imbibition via quasi-static and spontaneous experiments at ambient conditions. The experimental results are directly compared to lattice Boltzmann (LB) simulations. The critical pore-filling pressures for the quasi-static experiments agree well with those predicted by the Young–Laplace equation and follow the expected filling events. However, the spontaneous imbibition experimental results differ from those predicted by the Young–Laplace equation; instead of entering the narrowest available downstream throat the wetting phase enters an adjacent throat first. Thus, pore geometry plays a vital role as it becomes the main deciding factor in the displacement pathways. Current pore network models used to predict displacement at the field scale may need to be revised as they currently use the filling rules proposed by Lenormandet al.(J. Fluid Mech., vol. 135, 1983, pp. 337–353). Energy balance arguments are particularly insightful in understanding the aspects affecting capillary-filling rules. Moreover, simulation results on spontaneous imbibition, in excellent agreement with theoretical predictions, reveal that the capillary number itself is not sufficient to characterise the two phase flow. The Ohnesorge number, which gives the relative importance of viscous forces over inertial and capillary forces, is required to fully describe the fluid flow, along with the viscosity ratio.

Carbon dioxide (CO 2 ) sequestration is a climate change mitigation technique which relies on residual and solubility trapping in injection locations with saline aquifers. The dissolution of CO 2 into resident brines results in density-driven convection which further enhances the geological trapping potential. We report on the use of an analogue fluid pair to investigate density-driven convection in 3D in an unconsolidated bead pack. X-ray computed tomography (CT) is used to image density-driven convection in the opaque porous medium non-invasively. Two studies have been conducted that differ by the Rayleigh number (Ra) of the system, which in this study is changed by altering the maximum density difference of the fluid pair. We observe the same general mixing pattern in both studies. Initially, many high density fingers move downward through the bead pack and as time progresses these coalesce and form larger dominate flow paths. However, we also observe that a higher Rayleigh number leads to the denser plume moving faster towards the bottom of the system. Due to the finite size of the system, this in turn leads to early convective shut-down.

Understanding the chemical interactions between CO 2 -saturated brine systems and reservoir rocks is essential for predicting the fate of CO 2 following injection into a geological reservoir. In this work, the dissolution rates of calcite (CaCO 3 ) in CO 2 -saturated brines were measured at temperatures between 325 K and 373 K and at pressures up to 10 MPa. The experiments were performed in batch reactors implementing the rotating disk technique in order to eliminate the influence of fluid-surface mass transport resistance and obtain surface reaction rates. Three aqueous brine systems were investigated in this study: NaCl at a molality m = 2.5 mol·kg −1 , NaHCO 3 with m ranging from (0.005 to 1) mol·kg −1 and a multicomponent Na-Mg-K-Cl-SO 4 -HCO 3 brine system with an ionic strength of 1.8 mol·kg −1 . Measured dissolution rates were compared with predictions from previously published models. Activity calculations were performed according to the Pitzer model as implemented in the PHREEQC geochemical simulator. Calcite dissolution rates in NaCl and the multicomponent brine system showed minor increases when compared to the (CO 2 + H 2 O) system at identical conditions, despite the lower concentration of dissolved CO 2 . These trends are consistent with the expected minor decreases in solution pH. In NaHCO 3 systems, consistent with increase in solution pH, significant decreases in dissolution rates were observed. In addition, these systems significantly deviated from model predictions at higher salt molalities. Vertical scanning interferometry (VSI) was used to examine the mineral surfaces before and after dissolution experiments to provide qualitative information on saturation states and dissolution mechanism.

Understanding the transport of chemical components in porous media is fundamentally important to many reservoir processes such as contaminant transport and reactive flows involved in CO2 sequestration. Carbonate rocks in particular present difficulties for pore-scale simulations because they contain large amounts of sub-micron porosity. In this work, we introduce a new hybrid simulation model to calculate hydrodynamic dispersion in pore-scale images of real porous media and use this to elucidate the origins and behaviour of stagnant zones arising in transport simulations using micro-CT images of carbonates. For this purpose a stochastic particle model for simulating the transport of a solute is coupled to a Lattice-Boltzmann algorithm to calculate the flow field. The particle method incorporates second order spatial and temporal resolution to resolve finer features of the domain. We demonstrate how dispersion coefficients can be accurately obtained in capillaries, where corresponding analytical solutions are available, even when these are resolved to just a few lattice units. Then we compute molecular displacement distributions for pore-spaces of varying complexity: a pack of beads; a Bentheimer sandstone; and a Portland carbonate. Our calculated propagator distributions are compared directly with recent experimental PFG-NMR propagator distributions (Scheven et al., 2005; Mitchell et al., 2008), the latter excluding spin relaxation mechanisms. We observe that the calculated transport propagators can be quantitatively compared with the experimental distribution, provided that spin relaxations in the experiment are excluded, and good agreement is found for both the sandstone and the carbonate. However, due to the absence of explicit micro-porosity from the carbonate pore space image used for flow field simulations we note that there are fundamental differences in the physical origins of the stagnant zones for micro-porous rocks between simulation and experiment. We show that for a given micro-CT image of a carbonate, small variations in the parameters chosen for the segmentation process lead to different amounts of stagnancy which diffuse away at different rates. Finally, we use a filtering method to show that this is due to the presence of spurious isolated pores which arise from the segmentation process and suggest an approach to overcome this limitation.

Summary In the last decade, imaging techniques capable of reconstructing three-dimensional (3-D) pore-scale model have played a pivotal role in the study of fluid flow through complex porous media. In this study, we present advances in the application of confocal laser scanning microscopy (CLSM) to image, reconstruct and characterize complex porous geological materials with hydrocarbon reservoir and CO2 storage potential. CLSM has a unique capability of producing 3-D thin optical sections of a material, with a wide field of view and submicron resolution in the lateral and axial planes. However, CLSM is limited in the depth (z-dimension) that can be imaged in porous materials. In this study, we introduce a ‘grind and slice’ technique to overcome this limitation. We discuss the practical and technical aspects of the confocal imaging technique with application to complex rock samples including Mt. Gambier and Ketton carbonates. We then describe the complete workflow of image processing to filtering and segmenting the raw 3-D confocal volumetric data into pores and grains. Finally, we use the resulting 3-D pore-scale binarized confocal data obtained to quantitatively determine petrophysical pore-scale properties such as total porosity, macro- and microporosity and single-phase permeability using lattice Boltzmann (LB) simulations, validated by experiments.

The rheology of Zuata heavy crude oil, saturated with carbon dioxide, was studied at a temperature of 50 °C and pressures up to 220 bar. Observations of phase behavior were also reported and used to interpret the rheological data. The crude oil is very viscous and non-Newtonian at ambient pressure, but when brought into equilibrium with CO2, the non-Newtonian behavior was weakened and eventually disappeared at high CO2 pressures. When diluted with 10 and 30 wt % toluene, the diluted crude oils and their mixtures with CO2 behaved as Newtonian fluids. The CO2-saturated mixture of the crude oil samples showed an exponential decrease in viscosity with increasing CO2 pressure but an increase in viscosity at higher pressures. During observation through a view cell, the CO2 dissolution caused a swelling effect on the original crude oil. When saturated with CO2, the swelling effect also occurred on the 10 wt % diluted crude oil but the volume of the oil-rich phase was decreased at higher pressures. However, for the 30 wt % diluted crude oil, a second liquid phase was observed on top of the oil-rich phase, at pressures higher than the CO2 critical point. The mixture viscosity was inversely proportional to the CO2 solubility.

We report experimental measurements of the dissolution rate of several carbonate minerals in CO2-saturated water or brine at temperatures between 323 K and 373 K and at pressures up to 15 MPa. The dissolution kinetics of pure calcite were studied in CO2-saturated NaCl brines with molalities of up to 5 mol kg−1. The results of these experiments were found to depend only weakly on the brine molality and to conform reasonably well with a kinetic model involving two parallel first-order reactions: one involving reactions with protons and the other involving reaction with carbonic acid. The dissolution rates of dolomite and magnesite were studied in both aqueous HCl solution and in CO2-saturated water. For these minerals, the dissolution rates could be explained by a simpler kinetic model involving only direct reaction between protons and the mineral surface. Finally, the rates of dissolution of two carbonate-reservoir analogue minerals (Ketton limestone and North-Sea chalk) in CO2-saturated water were found to follow the same kinetics as found for pure calcite. Vertical scanning interferometry was used to study the surface morphology of unreacted and reacted samples. The results of the present study may find application in reactive-flow simulations of CO2-injection into carbonate-mineral saline aquifers.

Analog fluids have been widely used to mimic the convective mixing of carbon dioxide into brine in the study of geological carbon storage. Although these fluid systems had many characteristics of the real system, the viscosity contrast between the resident fluid and the invading front was significantly different and largely overlooked. We used x-ray computed tomography to image convective mixing in a three-dimensional porous medium formed of glass beads and compared two invading fluids that had a viscosity 3.5× and 16× that of the resident fluid. The macroscopic behavior such as the dissolution rate and onset time scaled well with the viscosity contrast. However, with a more viscous invading fluid, fundamentally different plume structures and final mixing state were observed due in large part to greater dispersion.

We use a pore-scale dissolution model to simulate the dissolution of calcite by HCl in two different systems and compare with experiment. The model couples flow and transport with chemical reactions at the mineral surface and in the fluid bulk. Firstly, we inject HCl through a single channel drilled through a solid calcite core as a simple validation case, and as a model system with which to elucidate the chemical mechanisms of the dissolution process. The overall dissolution rate is compared to a corresponding experiment. Close agreement with experimental and simulated dissolution rates is found, which also serves to validate the model. We also define a new form of effective Damkohler number which can be obtained from simulated chemical distributions, and show how this gives a more precise measure of the balance of transport and reaction. Secondly, we inject HCl into a Ketton carbonate rock core at high flow rate, which leads to wormhole formation, and compare to experiment. The simulation matches the experimental mass dissolution rate extracted from the micro-CT images, and predicts the resulting morphological changes reasonably well. The permeability change though is greater in the experiment than in the simulation, and this is shown to be due to more elongated wormhole formation in experiment. Possible reasons for this are discussed, including uncertainties in diffusion coefficients, and calcite density variations and micro-porosity in the Ketton grains. The distribution of chemical species from the simulation then permits a detailed understanding of the rate-controlling mechanisms at work, including the relative importance of the H+–calcite and H2CO3–calcite dissolution pathways.

[EN] We carried out drying studies on a 2.5D micromodel based on a thin section of a carbonate rock to investigate the impact of wettability on the capillary disconnect, the moment when liquid films de-pin from the external evaporating surface. While this is coincident with the transition to low evaporation rate (diffusion limited) for deionized-water, our experiments show, the corner wetting films persisted after the transition to low evaporation rate for both water-wet and mixed-wet micromodels for brine, as solid salt continued to build up at the external evaporating surface. Fully oil wet micromodels showed a drying rate transition coincident with de-pinning., We gratefully acknowledge funding for this PhD research from the Petroleum Technology Development Fund, provided by the Nigerian Government. This work was done using equipment provided by the Qatar Carbonates and Carbon Storage Research Centre (QCCSRC). We gratefully acknowledge the funding of QCCSRC provided jointly by Qatar Petroleum, Shell, and the Qatar Science & Technology Park.

We present an experimental study of dissolution-driven convection in a three-dimensional porous medium formed from a dense random packing of glass beads. Measurements are conducted using the model fluid system MEG/water in the regime of Rayleigh numbers, \documentclass[12pt]{minimal} \usepackage{amsmath} \usepackage{wasysym} \usepackage{amsfonts} \usepackage{amssymb} \usepackage{amsbsy} \usepackage{mathrsfs} \usepackage{upgreek} \setlength{\oddsidemargin}{-69pt} \begin{document}$$Ra=2000{-}5000$$\end{document}Ra=2000-5000. X-ray computed tomography is applied to image the spatial and temporal evolution of the solute plume non-invasively. The tomograms are used to compute macroscopic quantities including the rate of dissolution and horizontally averaged concentration profiles, and enable the visualisation of the flow patterns that arise upon mixing at a spatial resolution of about (\documentclass[12pt]{minimal} \usepackage{amsmath} \usepackage{wasysym} \usepackage{amsfonts} \usepackage{amssymb} \usepackage{amsbsy} \usepackage{mathrsfs} \usepackage{upgreek} \setlength{\oddsidemargin}{-69pt} \begin{document}$$2\times 2\times 2)\,\hbox {mm}^3$$\end{document}2×2×2)mm3. The latter highlights that under this Ra regime convection becomes truly three-dimensional with the emergence of characteristic patterns that closely resemble the dynamical flow structures produced by high-resolution numerical simulations reported in the literature. We observe that the mixing process evolves systematically through three stages, starting from pure diffusion, followed by convection-dominated and shutdown. A modified diffusion equation is applied to model the convective process with an onset time of convection that compares favourably with the literature data and an effective diffusion coefficient that is almost two orders of magnitude larger than the molecular diffusivity of the solute. The comparison of the experimental observations of convective mixing against their numerical counterparts of the purely diffusive scenario enables the estimation of a non-dimensional convective mass flux in terms of the Sherwood number, \documentclass[12pt]{minimal} \usepackage{amsmath} \usepackage{wasysym} \usepackage{amsfonts} \usepackage{amssymb} \usepackage{amsbsy} \usepackage{mathrsfs} \usepackage{upgreek} \setlength{\oddsidemargin}{-69pt} \begin{document}$$Sh=0.025Ra$$\end{document}Sh=0.025Ra. We observe that the latter scales linearly with Ra, in agreement with both experimental and numerical studies on thermal convection over the same Ra regime.

The fouling of ultrafiltration (UF) and nanofiltration (NF) membranes during the treatment of surface waters continues to be of concern and the particular role of natural organic matter (NOM) requires further investigation. In this study the effect of pH and surface charge on membrane fouling during the treatment of samples of a representative surface water (Hyde Park recreational lake) were evaluated, together with the impact of pre-ozonation. While biopolymers in the surface water could be removed by the UF membrane, smaller molecular weight (MW) fractions of NOM were poorly removed, confirming the importance of membrane pore size. For NF membranes the removal of smaller MW fractions (800 Da–10 kDa) was less than expected from their pore size; however, nearly all of the hydrophobic, humic-type substances could be removed by the hydrophilic NF membranes for all MW distributions (greater than 90%). The results indicated the importance of the charge and hydrophilic nature of the NOM. Thus, the hydrophilic NF membrane could remove the hydrophobic organic matter, but not the hydrophilic substances. Increasing charge effects (more negative zeta potentials) with increasing solution pH were found to enhance organics removal and reduce fouling (flux decline), most likely through greater membrane surface repulsion. Pre-ozonation of the surface water increased the hydrophilic fraction and anionic charge of NOM and altered their size distributions. This resulted in a decreased fouling (less flux decline) for the UF and smaller pore NF, but a slight increase in fouling for the larger pore NF. The differences in the NF behavior are believed to relate to the relative sizes of ozonated organic fractions and the NF pores; a similar size of ozonated organic fractions and the NF pores causes significant membrane fouling.

We report measurements of the calcite dissolution rate in CO 2 -saturated water at pressures ranging from (6.0 to 13.8) MPa and temperatures from (323 to 373) K. The rate of calcite dissolution in HCl(aq) at temperatures from (298 to 353) K was also measured at ambient pressure with pH between 2.0 and 3.3. A specially-designed batch reactor system, implementing a rotating disc technique, was used to obtain the dissolution rate at the solid/liquid interface of a single crystal, free of mass transfer effects. We used vertical scanning interferometry to examine the texture of the calcite surface produced by the experiment and the results suggested that at far-from-equilibrium conditions, the measured calcite dissolution rate was independent of the initial defect density due to the development of a dynamic dissolution pattern which became steady-state shortly after the onset of dissolution. The results of this study indicate that the calcite dissolution rate under surface-reaction-controlled conditions increases with the increase of temperature from (323 to 373) K and CO 2 partial pressure from (6.0 to 13.8) MPa. Fitting the conventional first order transition state kinetic model to the observed rate suggested that, although sufficient to describe calcite dissolution in CO 2 -free HCl(aq), this model clearly underestimate the calcite dissolution rate in the (CO 2 + H 2 O) system over the range of conditions studied. A kinetic model incorporating both pH and the activity of CO 2 (aq) has been developed to represent the dissolution rates found in this study. We report correlations for the corresponding reaction rate coefficients based on the Arrhenius equation and compare the apparent activation energies with values from the literature. The results of this study should facilitate more rigorous modelling of mineral dissolution in deep saline aquifers used for CO 2 storage.

Most evaporation experiments using artificial porous media have focused on single capillaries or sand packs. We have carried out, for the first time, evaporation studies on a 2.5D micromodel based on a thin section of a sucrosic dolomite rock. This allowed direct visual observation of pore-scale processes in a network of pores. NaCl solutions from 0 wt. % (de-ionized water) to 36 wt. % (saturated brine) were evaporated by passing dry air through a channel in front of the micromodel matrix. For de-ionized water, we observed the three classical periods of evaporation: the constant rate period (CRP) in which liquid remains connected to the matrix surface, the falling rate period, and the receding front period, in which the capillary connection is broken and water transport becomes dominated by vapour diffusion. However, when brine was dried in the micromodel, we observed that the length of the CRP decreased with increasing brine concentration and became almost non-existent for the saturated brine. In the experiments with brine, the mass lost by evaporation became linear with the square root of time after the short CRP. However, this is unlikely to be due to capillary disconnection from the surface of the matrix, as salt crystals continued to be deposited in the channel above the matrix. We propose that this is due to salt deposition at the matrix surface progressively impeding hydraulic connectivity to the evaporating surface.

A rheometer system to measure the rheology of crude oil in equilibrium with carbon dioxide (CO2) at high temperatures and pressures is described. The system comprises a high-pressure rheometer which is connected to a circulation loop. The rheometer has a rotational flow-through measurement cell with two alternative geometries: coaxial cylinder and double gap. The circulation loop contains a mixer, to bring the crude oil sample into equilibrium with CO2, and a gear pump that transports the mixture from the mixer to the rheometer and recycles it back to the mixer. The CO2 and crude oil are brought to equilibrium by stirring and circulation and the rheology of the saturated mixture is measured by the rheometer. The system is used to measure the rheological properties of Zuata crude oil (and its toluene dilution) in equilibrium with CO2 at elevated pressures up to 220 bar and a temperature of 50 °C. The results show that CO2 addition changes the oil rheology significantly, initially reducing the viscosity as the CO2 pressure is increased and then increasing the viscosity above a threshold pressure. The non-Newtonian response of the crude is also seen to change with the addition of CO2.

In the last decade, the study of fluid flow in porous media has developed considerably due to the combination of X-ray Micro Computed Tomography (micro-CT) and advances in computational methods for solving complex fluid flow equations directly or indirectly on reconstructed three-dimensional pore space images. In this study, we calculate porosity and single phase permeability using micro-CT imaging and Lattice Boltzmann (LB) simulations for 8 different porous media: beadpacks (with bead sizes 50 µm and 350 µm), sandpacks (LV60 and HST95), sandstones (Berea, Clashach and Doddington) and a carbonate (Ketton). Combining the observed porosity and calculated single phase permeability, we shed new light on the existence and size of the Representative Element of Volume (REV) capturing the different scales of heterogeneity from the pore-scale imaging. Our study applies the concept of the ‘Convex Hull’ to calculate the REV by considering the two main macroscopic petrophysical parameters, porosity and single phase permeability, simultaneously. The shape of the hull can be used to identify strong correlation between the parameters or greatly differing convergence rates. To further enhance computational efficiency we note that the area of the convex hull (for well-chosen parameters such as the log of the permeability and the porosity) decays exponentially with sub-sample size so that only a few small simulations are needed to determine the system size needed to calculate the parameters to high accuracy (small convex hull area). Finally we propose using a characteristic length such as the pore size to choose an efficient absolute voxel size for the numerical rock.

In this paper we describe an improved sample-preparation technique for applying confocal laser scanning microscopy to image the void space of porous geological media, particularly various kinds of carbonate rocks with significant microporosity. We have improved the existing sample-preparation technique for confocal imaging by introducing a positive-pressure application step. This additional step helps to force the fluorescent-doped epoxy mixture inside the submicron pores (the microporosity) which make up a significant fraction of the total porosity of the carbonate rocks being characterized using confocal laser scanning microscopy. We also provide additional technical details and discuss practical aspects important to consider when imaging carbonate rock samples using this technique.

[1] We simulate flow and solute transport directly on pore space images of rock cores with increasing degree of heterogeneity: a bead pack, Bentheimer sandstone, and Portland carbonate. A novel scheme is proposed to predict probability distributions for molecular displacements using the lattice Boltzmann (LB) method to calculate both the flow field and solute dispersion. We observe that for homogeneous rock samples, such as bead packs, the displacement distribution remains Gaussian with time increasing. In the more heterogeneous rocks, the displacement distribution separates into a moving and a stagnant part. In this case, we observe that the magnitude of the moving distribution decreases whereas a stagnant peak at the initial position ( ζ=0) increases with increasing heterogeneity of the porous medium. We compare our results directly with NMR experimental data for molecular displacements and find excellent agreement. To quantify the degree of heterogeneity, we calculate the fraction of solute particles trapped by integrating over the stagnant peak. We observe that the fraction of trapped solute increases from the bead pack (0 %) to Bentheimer sandstone (1.488%) to Portland carbonate (8.131%). Our analysis shows that the LB-based propagator simulation is able to predict the transport in porous media efficiently and accurately.

We report pH measurements for CO2-saturated water in the pressure range from (0.28 to 15.3) MPa and temperatures from (308.3 to 423.2) K. Commercially available pH and Ag/AgCl electrodes were used together with a high pressure equilibrium vessel operating under conditions of precisely controlled temperature and pressure. The results of the study indicate that pH decreases along an isotherm in proportion to −log10(x), where x is the mole fraction of dissolved CO2 in H2O. The expanded uncertainty of the pH measurements is 0.06 pH units with a coverage factor of 2. The reported results are in good agreement with the literature in pressure ranges up to 16 MPa at temperatures below 343 K. An empirical equation has been developed to represent the present results with an expanded uncertainty of 0.05 pH units. We also compare our results with a chemical equilibrium model and find agreement to within 0.1 pH unit.

This paper presents results of our study of the kinetics of asphaltene aggregation as a function of different precipitants, solvents, and the Hildebrand solubility parameter δ. The aggregation was studied in situ in the crude oil using confocal laser-scanning microscopy. We observe that the kinetics of asphaltene aggregation strongly depends upon the Hildebrand solubility parameter of the mixture. The aggregation process, which occurs when adding precipitant close to the precipitation onset point, can be described by a diffusion-limited aggregation (DLA) process. A slight change of the Hildebrand solubility parameter away from the precipitation onset point into the precipitation regime leads to a different kinetic mechanism. In this regime, we observe that the aggregate size increases almost linearly over time, which is an indication of the crossover between DLA and reaction-limited aggregation (RLA). The maximum mean aggregate diameter increases from 18 μm near the onset point to 90 μm away from the onse...

We investigate both drainage and spontaneous imbibition processes at the pore scale using a combination of micro- fluidic experiments and lattice-Boltzmann (LB) flow calculations. First, we have fabricated a range of specifically designed etched micro-models to investigate the role of pore shape and throat width on fluid displacement. These designs include junctions with both equal and unequal channel widths in order to achieve a range of capillary entry pressures. All models were etched into Poly(methyl methacrylate) (PMMA) and chemically treated to create a hydrophobic surface. The displacement process is captured via a high-speed video microscope under ambient conditions. The experimental results were then directly compared with LB simulations. For the drainage experiments, we observe that the fluid displacement in the junction follows the Young-Laplace Law. For the case of spontaneous imbibition, however, the models with unequal channel widths display different displacement behaviour. Our experimental observations are confirmed in detail by Lattice Boltzmann Method (LBM) simulations, lending credibility to our observations. Instead of following Young-Laplace filling rules, we observe that the throat in closest proximity fills up first. This has potentially important consequences for calculation of residual saturation of CO 2 at the core scale, which is determined by spontaneous imbibition of brine following CO 2 injection.

As we continue to use fossil fuels for our energy supply, the concentration of CO2 in the Earth’s atmosphere is likely to continue to increase. It has been shown that this is correlated with an increase in the temperature of the atmosphere and potential associated climate change. To mitigate this problem, Carbon Capture and Storage (CCS) has been mooted over the past decade. In this chapter, we will focus on CO2 storage in downhole rock formations. Rock formations suitable for storage include saline aquifers and depleted oil and gas reservoirs. Also coal bed methane (CBM) reservoirs may be suitable for storage, but we will not consider these in the current chapter. In the case of saline aquifers, we consider only the storage of CO2. In the case of depleted oil/gas reservoirs, the storage of CO2 can be combined with Enhanced Oil Recovery (EOR). This may lead to a more favorable economic scenario and has recently been coined as CCUS (Carbon Capture and Utilized Storage). In particular we will focus in this chapter on carbonate reservoirs. Sandstone reservoirs have been relatively well studied. However, much less is known about the storage properties of carbonate rocks, which have very different petrophysical and flow properties. Moreover, carbonate rocks constitute a significant fraction of existing depleted hydrocarbon reservoirs. Our aim is to study the pore scale properties of carbonates and upscale these to the core and field scales. First, carbonates have a very different structure from sandstones, associated with their composition and diagenesis. Carbonates usually have a much broader pore size distribution (PSD) than sandstones with extensive microporosity (Cantrell and Hagerty 1999). In addition, carbonates are often naturally fractured (Ameen et al. 2010). This leads to a broad range of heterogeneity as a function of length scale, in comparison …

During the later stages of flow from an oil well, water inevitably appears in the produced fluids. When crude oil and water are energetically mixed by constrictions in the production tubing, emulsions can form. Heavy crudes may also contain surface-active agents that can stabilize the emulsion, resulting in persistent flow problems. If carbon dioxide is injected into such a reservoir (e.g., for CO2 enhanced oil recovery), then CO2 will dissolve into both oil and water phases affecting the emulsion properties; however, this aspect has been neglected in the literature thus far. This paper presents a study of the rheology of oil/water emulsion altered by carbon dioxide. The emulsion was prepared by blending 50 wt % water and 50 wt % Zuata heavy crude oil in a high shear mixer (Silverson), resulting in a water-in-oil emulsion. The emulsion was subsequently stable at ambient conditions for several weeks without the addition of any surfactants. A high-pressure rheometer system coupled to a mixing vessel and fluid circulation loop allowed the emulsion to be brought into equilibrium with CO2, and its rheology was then measured at a temperature of 50 °C and pressures from ambient to 120 bar. The emulsion without dissolved CO2 was found to be slightly shear thinning below a critical shear rate, above which the viscosity jumped to a much lower value. The CO2 dissolution had two effects: first, it reduced the emulsion viscosity at low shear while preserving the shear thinning behavior, and second, increasing the CO2 pressure in equilibrium with the emulsion increased the critical shear rate at which the viscosity jump occurred. At shear rates above the jump, the emulsion viscosity dropped to a level lower than that of the original continuous phase (oil). It is likely that the viscosity jump occurred as a result of phase inversion; however, this was difficult to observe directly. The jump was reversed (with some hysteresis) as the shear rate was reduced again. Dissolved CO2 can influence the emulsion properties, such as phase inversion, through its action in both phases. The dissolution of CO2 in the oil phase reduced the viscosity of the oil, while dissolution into the water phase markedly changed pH and, thereby, the performance of any charged surface-active agents present in the crude oil.

We report experimental measurements of the dissolution rate of several carbonate minerals in CO

This paper reports a set of experiments carried out to examine asphaltene deposition in a glass microcapillary pipet, as a proxy to asphaltene deposition in reservoir pores. A new capillary-flow experiment was designed to ensure capillary-dominated flow, low inertial forces, negligible dispersion, and insignificant gravity effects, and the end-effect was limited to 0.1% of capillary length. This was achieved by maintaining the flow rates in the range 5 ≤ QT ≤ 60 μL/min. The asphaltene precipitation was induced by bringing into contact a heavy oil sample, diluted with toluene, with a number of different precipitants (n-pentane, n-heptane, and n-octane). The deposition of asphaltene was monitored by imaging the capillary tube and by measuring the pressure drop across it. A new, simple model has been developed to relate the pressure drop to the change in the thickness of the deposited layer and subsequently to the change in permeability. The model indicates that the thickness varies as one over the fourth po...

The spontaneous imbibition of liquid in nanopores of different roughness is investigated using coarse grain molecular dynamics (MD) simulation. The numerical model is presented and the simplifying assumptions are discussed in detail. The molecular-kinetic theory introduced by Blake is used to describe the effect of dynamic contact angle on fluid imbibition. The capillary roughness is modeled using a random distribution of coarse grained particles forming the wall. The Lucas-Washburn equation is used as a reference for analyzing the imbibition curves obtained by simulation. Due to the statistical nature of MD processing, a comprehensive approach was made to average and smooth the data to accurately define a contact angle. The results are discussed in terms of effective hydrodynamic and static capillary radii and their difference as a function of roughness and wettability.

Asphaltenes are known as the "cholesterol" of crude oil. They form nanoaggregates, precipitate, adhere to surfaces, block rock pores, and may alter the wetting characteristics of mineral surfaces within the reservoir, hindering oil recovery efficiency. Despite a significant research effort, the structure, aggregation, and deposition of asphaltenes under flowing conditions remain poorly understood. For this reason, we have investigated asphaltenes, their aggregation, and their deposition in capillary flow using multi-scale simulations and experiments. At the colloid scale, we use a hybrid simulation approach. For the solvent, we used the stochastic rotation dynamics (also known as multi-particle collision dynamics) simulation method, which provides both hydrodynamics and Brownian motion. This is coupled to a coarse-grained molecular dynamics (MD) approach for the asphaltene colloids. The colloids interact through a screened Coulomb potential with varying well depth e. Here, we present results for deposition of asphaltenes in their whole oil in comparison to our previous results on extracted asphaltenes. Imposing a constant pressure drop over the capillary length, we observe that the transient solvent flow rate decreases with an increasing well depth e. We find that the dimensionless conductivity measured in the experiment can be well-matched by simulation results using an interaction potential well depth of 8kBT. This means that extracted asphaltenes are more sticky than asphaltenes in whole oil. The interactions between the mesoscopic asphaltene colloids can be related to atomistic MD simulations. Molecular structures for the atomistic calculations were obtained using the quantitative molecular representation approach. Using these structures, we calculate the potential of mean force (PMF) between pairs of asphaltene molecules in an explicit solvent. We obtain a reasonable fit using a -1/r2 attraction for the attractive tail of the PMF at intermediate distances. We speculate that this is due to the two-dimensional nature of the asphaltene molecules. Finally, we discuss how we can relate this interaction to the mesoscopic colloid aggregate interaction. We assume that the colloidal aggregates consist of nanoaggregates. Taking into account observed solvent entrainment effects, we deduct the presence of lubrication layers between the nanoaggregates, which leads to a significant screening of the direct asphaltene-asphaltene interactions. © 2009 American Chemical Society.

The aggregation and deposition of colloidal asphaltene in reservoir rock is a significant problem in the oil industry. To obtain a fundamental understanding of this phenomenon, we have studied the deposition and aggregation of colloidal asphaltene in capillary flow by experiment and simulation. For the simulation, we have used the stochastic rotation dynamics (SRD) method, in which the solvent hydrodynamic emerges from the collisions between the solvent particles, while the Brownian motion emerges naturally from the interactions between the colloidal asphaltene particles and the solvent. The asphaltene colloids interact through a screened Coulomb potential. We vary the well depth ecc and the flow rate v to obtain Peflow » 1 (hydrodynamic interactions dominate) and Re « 1 (Stokes flow). In the simulations, we impose a pressure drop over the capillary length and measure the corresponding solvent flow rate. We observe that the transient solvent flow rate decreases when the asphaltene particles become more "sticky". For a well depth ecc = 2kBT, a monolayer deposits on the capillary wall. With an increasing well depth, the capillary becomes totally blocked. The clogging is transient for ecc = 5kBT, but appears to be permanent for ecc = 10-20kBT. We compare our simulation results with flow experiments in glass capillaries, where we use extracted asphaltenes in toluene, reprecipitated with n-heptane. In the experiments, the dynamics of asphaltene precipitation and deposition were monitored in a slot capillary using optical microscopy under flow conditions similar to those used in the simulation. Maintaining a constant flow rate of 5 µL min-1, we found that the pressure drop across the capillary first increased slowly, followed by a sharp increase, corresponding to a complete local blockage of the capillary. Doubling the flow rate to 10 µL min-1, we observe that the initial deposition occurs faster but the deposits are subsequently entrained by the flow. We calculate the change in the dimensionless permeability as a function of time for both experiment and simulation. By matching the experimental and simulation results, we obtain information about (1) the interaction potential well depth for the particular asphaltenes used in the experiments and (2) the flow conditions associated with the asphaltene deposition process. © 2008 American Chemical Society.

Recently there has been a great deal of attention, from researchers both in academia and in industry, focused on the rheological properties of solutions of viscoelastic wormlike micelles formed by surfactants. It is particularly vital to understand the properties of these solutions with regard to their flow in porous media, given their application to the recovery of hydrocarbons from subterranean formations. In this study a realistic mesoscopic Brownian dynamics model has been utilized to investigate the flow of viscoelastic surfactant (VES) fluid through individual pores with sizes of around one micron. In particular the influence of micelle size, pore geometry and flow rate on the ability of worms to pass through the pores was studied. The ways in which these parameters influence the conformational properties of the worms and the spatial distribution of micelles inside the simulation cell was also investigated. Despite the observation that the density and length distributions became non-uniform at higher scission energy, the distribution of breaking and fusion events remained spatially uniform. This journal is © The Royal Society of Chemistry.

We use displacement encoding pulsed field gradient (PFG) nuclear magnetic resonance to measure Fourier components S(q) of flow displacement distributions P(zeta) with mean displacement (zeta) for Newtonian and non-Newtonian flows through rocks and bead packs. Displacement distributions are non-Gaussian; hence, there are finite terms above second order in the cumulant expansion of ln(S(q)). We describe an algorithm for an optimal self-consistent cumulant analysis of data, which can be used to obtain the first three (central) moments of a non-Gaussian P(zeta), with error bars. The analysis is applied to Newtonian and non-Newtonian flows in rocks and beads. Flow with shear-thinning xanthan solution produces a 15.6+/-2.3% enhancement of the variance sigma(2) of displacement distributions when compared to flow experiments with water.

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

Carbon dioxide (CO2) flooding by immiscible gas drive is being increasingly used for Enhanced Oil Recovery (EOR) operations to address the challenging recovery of heavy crude oils. CO2 may trigger the precipitation and deposition of asphaltene, which may lead to a decrease in the crude oil recovery efficiency due to reduced permeability and porosity of the reservoir rock. Asphaltene deposition is currently one of the costliest technical challenges in the petroleum industry. Further research is required on identifying the conditions that will cause the onset of asphaltene precipitation with CO2 and the subsequent amount of asphaltene precipitated. In our work we have investigated the relationship between the mass of precipitated asphaltene from a heavy crude oil (API = 9.3) and the mass of a precipitant in crude oil/hydrocarbon and crude oil/supercritical CO2 systems. The experiments were carried out in a high pressure/high temperature filtration cell, filled with crude oil and the precipitant CO2. The use of a filtration cell is a precise method to determine the amount of precipitated asphaltene by any precipitant. The solubility of CO2 in the crude oil was measured at various pressures at 50 °C using a high-pressure mixing vessel connected to a syringe pump. The onset point was quantified in terms of the Hildebrand solubility parameter, which has previously been shown[1] to reconcile the behaviour of different hydrocarbon precipitants for an oil/hydrocarbon system. Precipitation induced by CO2 has a quantitatively different behaviour from precipitation induced by hydrocarbon systems; however, for the first time we were able to interpret the data by measuring the solubility of CO2 in oil and thereby estimate the system solubility parameter. This approach can then be used to predict the amount of precipitated asphaltene for various mixtures. The results will help to understand asphaltene behaviour in EOR operations in more detail as it is yet not fully identified how heavy crude oil asphaltene behave in reservoir rocks under precipitating conditions. [1] Wang J. and Buckley J. S. (2003) Energy and Fuels, 17, 1445-1451.

CO2 for Enhanced Oil Recovery (EOR) purposes has been injected into reservoirs since the 1970’s, which has seen an increase in the recovery of residual oil. However, the possible deposition of asphaltenes is one of the costliest problems the oil industry has to deal with. Despite significant research, asphaltene deposition under flowing conditions remains barely understood (Gonzalez et al. 2008, Seifried et al. 2013). Further research is required to identify the conditions that will cause the onset of asphaltene precipitation with CO2 and the subsequent amount of asphaltene precipitated.

Summary Injection of carbon dioxide into deep saline aquifers results in an acidic solution that can react with the reservoir rocks, especially carbonate minerals, with consequent changes in the porosity and permeability of the formation. Numerous factors control the extent and rate of these processes and in this paper we present a fundamental experimental and modelling study of the kinetics and equilibria of the underlying chemical reactions.

Many fields of Earth sciences benefit from the knowledge of mineral formation temperatures. For example, carbonates are extensively used for reconstruction of the Earth’s past climatic variations by determining ocean, lake, and soil paleotemperatures. Furthermore, diagenetic minerals and their formation or alteration temperature may provide information about the burial history of important geological units and can have practical applications, for instance, for reconstructing the geochemical and thermal histories of hydrocarbon reservoirs. Carbonate clumped isotope thermometry is a relatively new technique that can provide the formation temperature of carbonate minerals without requiring a priori knowledge of the isotopic composition of the initial solution. It is based on the temperature-dependent abundance of the rare 13C–18O bonds in carbonate minerals, specified as a Δ47 value. The clumped isotope thermometer has been calibrated experimentally from 1 °C to 70 °C. However, higher temperatures that are relevant to geological processes have so far not been directly calibrated in the laboratory. In order to close this calibration gap and to provide a robust basis for the application of clumped isotopes to high-temperature geological processes we precipitated CaCO3 (mainly calcite) in the laboratory between 23 and 250 °C. We used two different precipitation techniques: first, minerals were precipitated from a CaCO3 supersaturated solution at atmospheric pressure (23–91 °C), and, second, from a solution resulting from the mixing of CaCl2 and NaHCO3 in a pressurized reaction vessel at a pressure of up to 80 bar (25–250 °C). The calibration lines of both experimental approaches overlap and agree in the slopes with theoretical estimates and with other calibration experiments in which carbonates were reacted with phosphoric acid at temperatures above 70 °C. Our study suggests a universal Δ47-T calibration (T in K, Δ47 in ‰): Δ 47 = 0.98 ( ± 0.01 ) · ( - 3.407 · 10 9 / T 4 + 2.365 · 10 7 / T 3 - 2.607 · 10 3 / T 2 - 5.880 / T ) + 0.293 ( ± 0.004 ) This new Δ47-T calibration (given in the absolute reference frame), that extends the experimentally calibrated temperature range for clumped isotopes to 250 °C, can be applied to carbonates that grew at intermediate temperatures (20–250 °C).

The effect of shear on electrical conductivity (rheo-conduction) is studied to give information about particle behaviour in suspensions. Past work is reviewed, and expressions are derived for the rheo-conduction of a suspension of nonconducting spheroids in a conducting matrix for current flow, parallel and normal to the suspension flow direction. A simple apparatus to study rheo-conduction in pipe flow is described, and measurements of steady and time-dependent effects are reported for various suspensions of colloidal particles. Suspensions of anisometric rod- and platelike particles at low concentrations showed rheo-conductive changes of sign, magnitude and relaxation that were consistent with the particle shape, concentration and interactions. The rheo-conductive response decreased with increasing volume fraction for platelike kaolinite particles, attributed to orientational jamming. Spherical latex particles gave unexpected rheo-conductive changes consistent with shear disruption of a conductive network of particles. It is concluded that rheo-conduction measurements are a useful adjunct to conventional rheometry.

The viscosity of heavy crude oils strongly affects their producibility and recovery from oil reservoirs. Thus, the viscosity of heavy crude oils with dissolved gases at different shear rates is valuable knowledge for heavy crude oil exploitation. However, most publications only present viscosity measurements at one specific shear rate, and only a few papers in the literature have reported the rheological measurements over a range of shear rates. In this study, viscosity measurements of CO2-saturated heavy crude oils were performed as a function of the shear rate, at a temperature of 25 °C and pressures up to 220 bar. The experimental apparatus is a unique circulation system, which is able to measure the viscosity of CO2-saturated mixtures. A novel high-pressure rheometer with a flow-through Couette geometry was developed to measure the viscosity at a range of shear rates. The experimental results show that the addition of CO2 to heavy crude oil at the given temperature and pressures reduces the viscosity ...

We describe the recent development of lattice-Boltzmann (LB) and particle tracing computer simulations to study flow and reactive transport in porous media. First, we have extended our codes to measure both flow and solute transport from LB calculations directly on pore space images obtained from micro-CT scanning. We consider rocks with increasing degree of heterogeneity: a bead pack, Bentheimer sandstone and Portland carbonate. A novel scheme is proposed to predict probability distributions for molecular displacements using the LB method to calculate both the flow field and solute dispersion. We find excellent agreement with PFG-NMR experiments and quantify the degree of heterogeneity by integrating over the stagnant peaks in the propagator distributions. Second, we validate our LB model for multi-phase flow by calculating capillary filling and capillary pressure in model porous media. Then we extend our models to realistic 3D pore space images and observe the calculated capillary pressure curve in Bentheimer sandstone to be in agreement with experiment. A new process based algorithm is introduced to determine the distribution of wetting and non-wetting phases in the pore space, as a starting point for relative permeability calculations. The Bentheimer relative permeability curves for both drainage and imbibtion are found to be in good agreement with experimental data. These LB simulations can be used for the prediction of multi-phase flow properties in pore space images; as potential element of Special Core AnaLysis (SCAL); and for Enhanced Oil Recovery (EOR) operations. Third, we introduce a GPU algorithm for large scale LB calculations, offering greatly enhanced computing performance in comparison with CPU calculations. Finally, we propose a new hybrid method to calculate reactive transport on pore space images. First, we calculate the flow field using LB and initialise tracer particles in the porous medium. Then we carry out particle advection using a 2nd order predictor-corrector scheme, particle diffusion using a random walk followed by reaction. We simulate the dissolution of a sphere under quiescent conditions in good agreement with the analytical solution. Then we calculate the dissolution of a cylinder in channel flow and observe preliminary agreement with experimental observations. This opens the way to calculating the dissolution of pore space images in direct comparison with micro-CT imaging experiments, for matrix acidizing and CCS operations. It is concluded that the LB method is a powerful tool for calculating flow and reactive transport directly on rock pore space images.

Abstract Injection of CO2 into the subsurface is of interest for CO2 storage and enhanced oil recovery (EOR). There are, however, major unresolved questions around the multiphase flow physics and reactive processes that will take place after CO2 is injected, particularly in carbonate rock reservoirs. For example, the wetting properties of CO2-brine-rock systems will impact the efficiency of EOR operations and CO2 storage but reported contact angles range widely from strongly water-wet to intermediate wet. Similar uncertainties exist for properties including the relative permeability and the impact of chemical reaction on flow. In this presentation we present initial results from laboratory studies investigating the physics of multiphase flow and reactive transport for CO2-brine systems. We use traditional and novel core flooding techniques and x-ray imaging to resolve uncertainties around the CO2-brine contact angle, relative permeability, residual trapping, and feedbacks between chemical reaction and flow in carbonate rocks. Introduction Uncertainty around CO2 storage and EOR may be significantly reduced from a greater understanding of the fundamental physics of fluid flow and reactive transport that control rock-brine-CO2 interaction in the subsurface. The combination of unique multiphase flow properties and significant reactivity in the CO2-brine-carbonate rock system has major impacts on the injection, flow and immobilization of CO2 in the subsurface. These unique properties must be accurately characterized to reduce major uncertainties for CO2 storage and EOR in carbonate rocks. Observations of reservoir condition multiphase flow and reactive transport properties for the CO2-brine-carbonate rock system are provided including wetting properties, capillary pressure, relative permeability and residual trapping. A methodology is presented for utilizing a combination of novel and traditional core-flooding and imaging techniques for a comprehensive characterization of carbonate reservoir rock.

Carbon capture and storage (CCS) has been recognised as the best possible means for effective management of CO2 generated from industrial activities. The study of porosity and permeability has been given prime importance since it governs the storage or in other words prevents leakage of CO2 into the other formations and back into atmosphere. It has been depicted that such interaction of injecting CO2 leads to salt precipitation, which in turn affect the porosity and permeability of the rock. Hence, it becomes essential to investigate the interactions amongst the rock-brine (water) present in the reservoir and CO2. The location of the salt precipitants depends on the competition of advective and capillary forces on the aqueous fluid phase transporting brine to the drying front [1, 2]. In our study, we consider drying process of reservoir brine that takes place in fractured porous media. Initially, CO2 starts to dry the matrix-fracture interface. The deposition of salt at the exposed fracture face driven by capillary flow of the liquid phase in the porous matrix could cause a seal to develop and reduce the storage capacity of an aquifer which in certain circumstances could lead to a reduction in the fracture permeability. Dry out experiments of different solutions are carried out on cores with one face exposed to represent a fractured system. The morphology and the exact location of the precipitate at the fracture-matrix interface on the pore scale require imaging. These images are used in numerical to calculate the permeability reduction in our samples due to salt precipitation and compare the predictions to experimental measurements on the salt deposits [3]. REFERENCES 1.Peysson, Y., Bazin, B., Magnier, C., Kohler, E., and Youssef, S., “Permeability alteration due to salt precipitation driven by drying in the context of CO2 injection” Energy Procedia, (2011), 4: 4387-4394. 2.Ott, H., de Kloe, K., Marcelis, F., and Makurat, A., “Injection of supercritical CO2 in brine saturated sandstone: Pattern formation during salt precipitation” Energy Procedia, (2011), Volume 4, Pages 4425-4432 3.Yang, J., Boek, E.S., “A comparison study of multi-component Lattice Boltzmann models for flow in porous media applications”, Computers & Mathematics with Applications, Volume 65, Issue 6, March 2013, Pages 882-890, ISSN 0898-1221

More than 50% of the world's hydrocarbons reserves are contained in carbonate reservoirs. Carbonate rocks have a very complicated and heterogeneous porous structure in comparison with sandstone reservoir rock [1]. To understand the transport processes in any porous medium, we need to enhance our knowledge of the geometry and topology of the porous media [2]. Our understanding of porous carbonate rocks in this respect is still very limited in comparison with sandstones. In the last few years, pore scale studies have revolutionised the fundamental understanding of complex fluid flow processes in the field of groundwater remediation, oil industry and environmental issues related to carbon storage and capture. Therefore, in this work we present advances in several multi-scale imaging techniques to obtain 2D and 3D images at pore scale (voxel size 1- 10µm) using Confocal Laser Scanning Microscopy (CLSM)and Micro CT imaging as shown in Figure 1 . We will also discuss a novel technique of CLSM to obtain 2D images with a large field of view, including advantages and limitations for scanning porous carbonate rocks. We then describe approaches to extract statistical information about total, macro and micro-porosity from 2D large field of view CLSM and validate the results using Mercury Intrusion Porosimetry (MICP). In this work, using the image processing techniques for different phase segmentation, we study the effect of scanned resolution images on porosity and permeability using Lattice Boltzmann simulation and pore network modelling. Finally, we describe the recent development of lattice-Boltzmann (LB) simulations for the prediction of multi-phase flow properties in complex carbonate pore space images; as potential element of Special Core Analysis (SCAL); and for Enhanced Oil Recovery (EOR) operations. We introduce a GPU algorithm for large scale LB calculations, offering greatly enhanced computing performance in comparison with CPU calculations.

Gas-to-solid heat transfer coefficients measured in moving beds of solid particles are an order of magnitude smaller than those predicted by conventional correlations which work well for fixed beds. The authors have elsewhere proposed a cause: gas flow in moving beds involves gross channelling which falsifies the plug-flow heat transfer analysis which yields the coefficients. In the present work, end effects have been removed from measured gas RTDs using a Fourier Transform technique applied to data from beds of different lengths. This refinement of the data analysis reveals gas RTDs for moving beds to be characteristically bimodal, conclusively demonstrating the predicted channelling. Radial profiles of axial gas velocities have also been measured, using the time-of-flight of tracer gas pulses injected and sampled at known radial positions in the packing. Two distinct channels are identified: an annular zone near the bed wall of thickness six to ten particle diameters, and a cylindrical zone in the bed centre where the gas velocity is higher, by a factor of some 1.14–1.25, than that in the annulus. A simple model of flow and heat transfer is used to show that the degree of channelling observed is of the correct order of magnitude to account for the erroneous heat transfer coefficients reported.