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We present an experimental study of foam-flow characterization inside a 3D granular medium packed in a cell. The foam is formed by coinjecting a surfactant solution and gas inside a cell filled with silica grains. The porous medium is initially saturated with dodecane and water before the gas-surfactant coinjection. To simplify the interpretation of the measurements, a contrast matching methodology has been applied in order to obtain a two phase system regarding the scattering length density values. The combination of transmission and incoherent scattering allows us to estimate the volume fractions of each phase, whereas the coherent scattering is used to estimate the surface to volume ratio S/V related to water-oil and water-gas interfaces. Considering the evolution of S/V ratio, volume fractions and pressure difference, we infer some mechanisms of foam generation and transportation as well as oil removal.

International audience; One of the challenges in the study of foam transport in 3D porous media is having an adequate spatial and temporal resolution, to get a better understanding of the local phenomenon at the pore scale in a non-destructive way. We present an experimental study in which ultra fast X-Ray microtomography is used to characterize the foam trapping while the foam is flowing in a 3D porous medium. A preformed aqueous foam is injected into a rotating cell containing a 3D granular medium made of silica grains. The use of rotating seals allows the cell to rotate continuously at the rate of one revolution per second, compatible with the fast X-ray tomography at SOLEIL synchrotron. We visualize the foam flow and track the trapping of bubbles with an acquisition time of about one second and a spatial resolution of a few microns (pixel size of one micron). This allows us to extract characteristics and reliable statistics about trapped bubbles inside the granular medium and to observe their local behavior. With this setup and technique we access to the dynamics of foam trapping during the flow and the texture variations of the foam in the trapped zones. These local trapping events are well correlated with the macroscopical measurement of the pressure gradient over the cell.

International audience; In this study, three clinopyroxene-enriched upper mantle xenoliths, petrographically classified as wehrlite,were investigated from the Nógrád–Gömör Volcanic Field with the use of X-ray microtomography. Our main goal was toquantify the volume of the glass phase and the vesicles to reveal their three-dimensional distribution. Among the studiedwehrlite xenoliths, one is weakly and two are strongly metasomatized. The two latter wehrlite xenoliths are characterizedby higher modal amount of glass and vesicles, which suggests a genetic connection between glass and concomitantvesicles, and the metasomatic agent. The glass, which was a melt at mantle conditions, forms an interconnected network.This may explain the presence of the electromagnetic anomaly with high electrical conductivity beneath the study area.Our study contributes to the better understanding of melt migration and its metasomatic effect in the lithospheric mantlebeneath monogenetic volcanic fields

Two innovative characterization techniques, Small Angle Neutron Scattering (SANS) and High Resolution Fast X-ray Micro-tomography on a Synchrotron, have been combined to usual coreflood environments and X-Ray CT Scanner measurements in order to describe the texture of a foam flowing in an opaque 3D porous medium. SANS measurements give access simultaneously to the gas saturation and to the amount of gas-liquid interfaces developed per unit volume and therefore to the in situ specific surface area of the foam denoted S/V. In situ texture of the foam flowing in real 3D porous media is therefore measurable. Fast X-Ray micro-tomography 3D images of foam flowing in a porous medium give visual evidence of the presence of gas bubbles in areas where the flow rate is naturally slowed by the trapping phenomena and enable to describe and follow the phenomena of intermittent trapping at the pore scale.

In this work, unstable displacements were conducted using special equipment designed to run in-situ CT-scanner experiments. All the displacements were conducted on a homogeneous Bentheimer sandstone plug, of 10 cm in diameter and 40 cm in length. Digitations (or fingering) have been observed under varying conditions of injection flowrate, displaced fluid viscosity, and core wettability. They have been characterized at both the core scale, using the core average oil saturation and the water breakthrough; and at the local scale, using the local saturations and had-hoc image processing analysis. It was found that the effect of the different flowing conditions on the front digitations could not be interpreted independently. The oil recovery at brine breakthrough showed a good correlation with the viscous fingering number for the water-wet case. However, a different scaling was observed for the oil-wet case. The interplay of the different flowing conditions mitigates the possibility of constructing a unique scaling number to account for all experimental condition. The local saturation monitoring has provided a new insight to characterize the finger shapes and analyze the production mechanisms. It allowed to distinguish two independent contributions to early breakthrough: viscous dominated digitations and capillary dominated digitations. A two-phases diagram has been constructed to plot and compare these contributions for all flowing conditions. Their evolutions show the main production mechanisms during the flooding. We observed that the viscous digitations were not causing phase trapping at core scale: the core is completely swept after breakthrough. For the water-wet case, we found that the local oil recovery of swept zone remained constant before and after breakthrough while for the oil-wet case it is improving during all the water flooding process.

The impact of compaction diagenesis on reservoir properties is addressed by means of observations made on five boreholes with different burial histories of the Early Callovian “Dalle Nacree” Formation in the Paris Basin. Petrographic analyses were carried out in order to investigate the rock-texture, pore space type and volume, micro-fabrics, and cement phases. Based on the acquired data, a chronologically ordered sequence of diagenetic events (paragenesis) for each borehole was reconstructed taking the burial history into account. Point counting and a segmentation algorithm (Matlab) were used to quantify porosity, as well as the amounts of grain constituents and cement phases on scanned images of studied thin sections. In addition, four key samples were analyzed by 3D imaging using microfocus X-ray computer tomography. Basin margin grainstones display a different burial diagenesis when compared to basin centre grainstones and wackestones. The former have been affected by considerable cementation (especially by blocky calcite) prior to effective burial, in contrast to the basin centre lithologies where burial and compaction prevailed with relatively less cementation. Fracturing and bed-parallel stylolitization, observed especially in basinal wackestone facies also invoke higher levels of mechanical and chemical compaction than observed in basin marginal equivalents. Compaction fluids may have migrated at the time of burial from the basin centre towards its margins, affecting hence the reservoir properties of similar rock textures and facies and resulting in cross-basin spatial diagenetic heterogeneities.

Comparative study between foams made of a pH sensitive surfactant, nonaoxyethylene oleylether carboxylic acid (AKYPO ® RO 90 VG) and a classical foaming surfactant, sodium dodecyl sulphate (SDS) was realised using simple microfluidic devices in the scope of Enhanced Oil Recovery (EOR). The influence of injecting fluid parameters such as gas and foaming liquid pressure was investigated and discussed in terms of foam morphology, and lamellae stability and curvature radii. The increasing stability of AKYPO ® foam film lamellae by increasing pH is classically explained by the electrostatic repulsive interaction of the double layer in foam film. In other hand, the addition of dodecanol (DOH) on SDS solution seems to have no effect on foam regime and lamellae stability except for high DOH concentration where the foam film shape becomes double bump. The behaviour difference between AKYPO ® and SDS lays on the lamellae shape and stability domain. While SDS lamellae stay unchanged with increasing pressure ratio between the gas and the liquid, AKYPO ® lamellae curvature radius increases which could be related to surfactants solubilities and structure. These results pointed out the relevance of solution physicochemical parameters on foam stability and flowing and help the understanding of flowing foam in EOR context.

Summary Waterflooding is often inefficient in carbonate reservoirs because of the presence of fractures and unfavorable wettability. Oil recovery can be improved by enhancing the following drive mechanisms: Capillary imbibition with wettability modifiers Viscous drive by increasing the pressure gradient in the fracture network Water/oil gravity drainage with low-interfacial-tension (IFT) surfactant formulations that also reduce oil trapping This paper presents an experimental approach that evaluates different chemical-enhanced-oil-recovery (EOR) alternatives on the basis of one or several of the three aforementioned recovery mechanisms. The experiments consist of injecting an aqueous chemical solution or a foam containing chemical additives into an artificially fractured carbonate core. The imbibition is monitored with a recent computed-tomography (CT) scanner allowing the local quantitative monitoring of three phases, including accurate quantification of matrix oil recovery. This paper is mainly focused on the impacts of foaming agents and wettability modifiers (WMs), implemented separately or jointly. The experiments have been conducted on several cores of different permeability, resulting in various permeability contrasts between matrix and fracture. A major result concerns the kinetics of oil recovery by chemical additives that is greatly increased when a viscous drive is applied across the matrix medium by means of the circulation of foam in the fracture. Experiments in fractured cores of different permeabilities indicate that foam does not penetrate the matrix, but drives the chemical aqueous phase into the matrix because of the generated pressure gradient. Detailed analysis of oil-mobilization dynamics is provided. These foam-flow experiments are compared with a former chemical imbibition test on a nonfractured core for further insight into the role played by viscous forces. The comparison of tested recovery scenarios leads to conclusions regarding optimal chemical-EOR strategies for naturally fractured carbonate reservoirs with poor secondary-recovery prognosis.

International audience; Subduction of carbonated crust is widely believed to generate a flux of carbon into the base of the continental lithospheric mantle, which in turn is the likely source of widespread volcanic and non-volcanic CO2 degassing in active tectonic intracontinental settings such as rifts, continental margin arcs and back-arc domains. However, the magnitude of the carbon flux through the lithosphere and the budget of stored carbon held within the lithospheric reservoir are both poorly known. We provide new constraints on the CO2 budget of the lithospheric mantle below the Pannonian Basin (Central Europe) through the study of a suite of xenoliths from the Bakony-Balaton Highland Volcanic Field. Trails of secondary fluid inclusions, silicate melt inclusions, networks of melt veins, and melt pockets with large and abundant vesicles provide numerous lines of evidence that mantle metasomatism affected the lithosphere beneath this region. We obtain a quantitative estimate of the CO2 budget of the mantle below the Pannonian Basin using a combination of innovative analytical and modeling approaches: (1) synchrotron X-ray microtomography, (2) NanoSIMS, Raman spectroscopy and microthermometry, and (3) thermodynamic models (Rhyolite-MELTS). The three-dimensional volumes reconstructed from synchrotron X-ray microtomography allow us to quantify the proportions of all petrographic phases in the samples and to visualize their textural relationships. The concentration of CO2 in glass veins and pockets ranges from 0.27 to 0.96 wt.%, higher than in typical arc magmas (0–0.25 wt.% CO2), whereas the H2O concentration ranges from 0.54 to 4.25 wt.%, on the low end for estimated primitive arc magmas (1.9–6.3 wt.% H2O). Trapping pressures for vesicles were determined by comparing CO2 concentrations in glass to CO2 saturation as a function of pressure in silicate melts, suggesting pressures between 0.69 to 1.78 GPa. These values are generally higher than trapping pressures for fluid inclusions determined by Raman spectroscopy and microthermometry (0.1–1.1 GPa). The CO2/silicate melt mass ratios in the metasomatic agent that percolated through the lithospheric mantle below the Pannonian Basin are estimated to be between 9.0 and 25.4 wt.%, values consistent with metasomatism either by (1) silicate melts already supersaturated in CO2 before reaching lithospheric depths or (2) carbonatite melts that interacted with mantle peridotite to generate carbonated silicic melts. Taking the geodynamical context of the Pannonian Basin and our calculations of the CO2/silicate melt mass ratios in the metasomatic agent into account, we suggest that slab-derived melts initially containing up to 25 wt.% of CO2 migrated into the lithospheric mantle and exsolved CO2–rich fluid that became trapped in secondary fluid inclusions upon fracturing of the peridotite mineral matrix. We propose a first-order estimate of 2000 ppm as the minimal bulk CO2 concentration in the lithospheric mantle below the Pannonian Basin. This transient carbon reservoir is believed to be degassed through the Pannonian Basin due to volcanism and tectonic events, mostly focused along the lithospheric-scale regional Mid-Hungarian shear Zone.

We report an experimental study of N2-foam injection in a Bentheimer sandstone coupled with X-ray Computed Tomography (CT-scanner). The measurements of pressure drop and gas saturation at different flow rates and foam qualities allowed us to describe the foam dynamics under transient and steady-state flow conditions. The brine displacement by foam shows a transient piston-like displacement pattern taking place in two successive phases. Saturation profiles reveal permanent entrance effects related to the injection procedure, and transient downstream end effects related to the gradual foam build-up. Entrance effects are attenuated with a high foam quality and at low total flow rate. The rheological behavior of foam was studied in terms of apparent foam viscosity and foamed-gas mobility as a function of foam quality and gas interstitial velocity. In the low-quality regime, foam exhibits a shear-thinning behavior that can be modelled by a power function. Furthermore, for a fixed total velocity, the quasi-invariance of strong foam apparent viscosity values is shown to result from the slight increase of trapped gas saturation, within the commonly-admitted assumption of invariant foam texture in the low-quality regime. An increase in gas mobility was observed above a certain value of the foam quality. That transition between low-quality and high-quality regimes was related to a limiting capillary pressure of foam in the porous medium under consideration.

Currently, intraperitoneal (IP) injection of D-luciferin is the preferred method of providing substrate for bioluminescence imaging (BLI); however it has a failure rate of 3–10% due to accidental intestinal injection. The present study evaluates the quality of BLI after subcutaneous (SC) injection of D-luciferin and demonstrates the effectiveness of SC injection in anatomically disparate tumor models. Mice bearing luciferase-expressing tumors underwent BLI after SC or IP injection of D-luciferin. The average time to maximal luminescence was 6 min (range 5–9 min) after SC injection and 8 min (range 5–8 min) after IP injection. Within 7 minutes of injection, SC and IP routes yielded similar luminescence in subcutaneous, intracranial, tongue, and lung xenograft tumor models. In a model of combined subcutaneous and intracranial xenografts, SC injection resulted in proportional luminescence at all sites, confirming that preferential delivery of substrate does not occur. While tumors were occasionally not visualized with IP injection, all tumors were visualized reliably with SC injection. Thus, SC injection of D-luciferin is a convenient and effective alternative to IP injection for BLI in nude mice. It may be a preferable approach, particularly for tumors with weaker signals and/or when greater precision is required.

Foams are among the most promising and cost effective means to alleviate the drawbacks associated with gas-based EOR-processes. The objective of this work is to probe the impact of residual oil saturation on CO2-foam generation and on their flow behavior in porous mediaDesigning a foam-EOR process requires its evaluation and optimisation at laboratory scale using coreflood tests. However, such coreflood tests are usually performed on relatively long core sample, this lead to long time-consuming experiments. In this study are presented results using both long and short coreflood systems. Short coreflood systems (allowing short-duration test) are coupled to a NMR apparatus and to an CT-scanner that allow live and non-invasive measurements of the fluids saturation.In a first part of this work, the efficiencies of two proprietary formulations to generate stable foam in porous media under reservoir conditions and in absence of oil have been compared. We used a coreflood set-up equipped with X-Ray detection to monitor gas propagation inside relatively long core samples. Then, their ability to resist the oil (Dodecane) have been evaluated and compared. The results evidenced two largely different behaviors. One of the two formulations resists the presence of oil up to an oil saturation of 35-40% while the second is destabilized as soon as the oil saturation exceeds 20%. Both formulations were insensitive to oil bellow an oil saturation of 15%. Depending on the application targeted, this laboratory evaluation should be coupled with a detailed economic evaluation to select the formulation to be used.In a second part, we performed co-injection tests using NMR small coreflood set-up and IRM-scanner in absence of oil. They brought more detailed information regarding fluid saturations that help interpreting foam characteristics and flow behavior in porous media.

Summary To predict the effects of stress on rock permeability, the authors propose an integrated approach based on an extended rock characterization, an experimental investigation of pressure dependency of directional rock permeabilities and finally a pore-scale simulation of this dependency using equivalent pore network extracted from microtomography analysis. This study has been conducted on two analog reservoir rock types: the high-permeability Bentheimer Sandstone and a dual-porosity bioclastic carbonate, the Estaillades Limestone, having an intermediate permeability. Compression tests have been conducted using a new triaxial cell specially designed to measure directional permeabilities along and transverse to direction of maximum stress application. We measured the pressure dependency of porosity, directional permeabilities, compressibilities, and elastic moduli of the tested samples. We also performed computed microtomography (CMT) imaging of the rock samples, from which we extracted the poral skeletons and the associated characteristics lengths. Then, we calculated the macroscopic transport properties using Pore Network Modeling (PNM) based on the real pore geometry. We included a model of pressure dependence of pore and throat sizes based on pressurized cavity models derived from elasticity theory to simulate the evolution of porosity and permeability with pressure. First, we show that the experimental determination of the evolution of directional permeabilities under hydrostatic and deviatoric loading is feasible. Finally, we show that the PNM coupled with μ-tomography can be a promising tool to forecast the evolution of transport properties under stresses representative of reservoir conditions, at the condition of integrating more advanced pore-scale compaction models.

Among various ways to extend the lifetime of mature fields, chemical EOR processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR as the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. However, a wide variety of surfactants can now be considered for EOR, among which products that alter the matrix wettability. The present paper deals with that recovery strategy and compares it with other strategies based on viscous drive enhancement. Comparison is based on the physical and numerical interpretation of original representative experiments. The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs has been quantified thanks to X-ray CT-scanning and NMR measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves could be inferred from in-situ fluid saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, representative drive conditions of a fractured reservoir were imposed between the end-faces of a plug, in order to account for the possibly-significant contribution of fracture viscous drive to matrix oil recovery. These experiments were carefully analyzed and their numerical modeling was initiated with a simulation software that takes into account the multiple effects of surfactant presence on rock-fluids systems, including rock wettability modification and water-oil interfacial tension reduction. Model capability to reproduce experimental results is quite satisfactory provided that the evolution of capillary pressures in the presence of additives is sufficiently characterized. A few sensitivity studies underline also the necessity of disposing of a completely-documented physico-chemical data set to minimize modeling uncertainties in view of reliable recovery kinetics optimization. In summary, the present paper provides an original quantitative description of chemical EOR process in neutral to oil-wet fractured reservoirs. This work calls for further development in order to specify the conditions on chemical additives and recovery process implementation that satisfy economic viability.

High Resolution 3D Reconstructions of Rocks and Composites — Ten µm resolution 3D representations of different media, were obtained with a laboratory computer microtomograph develo - ped from an electron microprobe column. From the original electron microprobe, only minor modifica - tions have been required, indeed several of the utilities of the microprobe have been used to ensure high resolution radiography (2 µm). The impact of the electron beam focused onto a thin film is used to form a "point" X-ray source and the radiographic image of the sample is acquired on a CCD camera. A speci - men rotation mechanism allows multiple radiograph acquisition and reconstruction of the X-ray attenua - tion 3D cartography. Since X-ray attenuation is directly related to density and atomic number, the microscanner provides 3D cartographs of the different phases present in the sample. System perfor - mances have been evaluated on various samples, mainly rocks and composites. Comparison with scan - ning electron micrographs was used when possible to validate the reconstructions. Results are mostly qualitative but already show the potential of the technique in describing 3D connectivity and topology of pore networks or 3D orientation of fibres in composites.

Much has been already done and written on the effect of wettability and spreading in three-phase displacement properties and efficiency. However, a direct visualization of the impact of these parameters in the distribution of the three fluids (water–oil–gas) within the pore space and consequently on the recovery mechanisms has been lacking. The objective of this paper is to obtain at the pore scale the necessary information to interpret the macroscopic behavior and to predict ultimate oil recovery for well controlled wetting and spreading conditions. To this end cryo-scanning electron microscopy (cryo-SEM) observations are performed in water-wet and oil-wet Fontainebleau sandstone plugs for spreading and non-spreading conditions. It is demonstrated that cryo-SEM can be used as a tool to study at the pore scale the fluid distributions and efficiency of oil recovery processes involving three phases. It is also proved that in a real porous medium both wettability and spreading affect gas injection efficiency by controlling three-phase distributions at the pore level and phase connectivity.

We propose a correction of the transmitted intensities in X-ray microscopy allowing improved quantification for polychromatic sources, particularly in tomographic reconstruction. The correction is based on the application of Beer's law for each energy present in the source spectrum. Knowledge of the source spectrum and the average specimen composition are used. The correction is demonstrated on a chemically homogeneous specimen (a glass capillary filled with glass beads) and on a polyphasic oil reservoir rock sample. In the former, detection of 20 μm defects is demonstrated. In the latter, different minerals, quartz, feldspath and kaolinite, can be discriminated and their distributions mapped.

Cryo-SEM has become a powerful tool to show the distribution of oil and brine in cores, which may be highly influenced by wettability properties. Previous studies have shown special affinity between kaolinite and oil after aging. The present work clarifies the behaviour of illite- or kaolinite-bearing cores, and compares with the measurements made at the plug scale (`bulk' measurements). After aging, fibrous illite has still no affinity for oil, kaolinite has an affinity for oil, but platy illite behaves more like kaolinite. However, a minimal quantity of kaolinite-like surfaces is needed to change the wettability of the bulk sample towards oil-wetness. The `bulk' wettability depends thus, although not linearly, on the nature, morphology, amount and distribution of clay, but one cannot ignore phenomena occurring at larger scales such as trapping. A qualitative agreement is found between the amount of oil and brine, depending on the state of saturation, and the bulk measurements (wettability index, Swi, Sor).

Conversion of an electron microprobe for use as an x‐ray microtomograph is described. Only minor modifications are required, indeed several of the utilities of the microprobe can be used to ensure high resolution radiography and tomography. System performance was evaluated by analysis of glass fiber reinforced polymer composites and of a carbonate reservoir rock. Individual glass fibers of 10 and 20 μm diameter are clearly visible in the former. In the latter, comparison with scanning electron micrographs shows reliable reconstruction of external morphology. In addition, internal pore structure can be studied a posteriori using the tomography data. Spatial resolutions in radiography of better than 3 μm and in tomography of 10 μm have been demonstrated. Further improvements to the detector system and increased data handling capacity are possible to achieve 1 μm resolution tomographic images.

Standard reservoir evaluations are based on Archie's law relating the average water saturation to the average electrical resistivity by ${R}_{\mathrm{ind}}={S}_{w}^{\ensuremath{-}2}$. However, especially in the case of complex heterogeneous carbonates, deviation from Archie's law is observed and generally attributed to factors affecting the percolation or disconnectedness of the different phases (wetting films, microporosity, macropores) assuring electrical conductance. Pore-network models (PNM's) in combination with high-resolution computed microtomography (\ensuremath{\mu}-CT) constitute a very effective tool to investigate the influence of the geometry and topology of the porous media on the spatial distribution of the conductive phase, and therefore on the shape of the resistivity index curve. An extended version of the classical PNM applicable to dual-porosity systems is presented. It combines the classical pore-network modeling applied on the macroporous space with the macroscopic properties of the microporous phase, supposing that the two pore systems act in parallel. Three-dimensional images provide information on the connectedness of the microporous phase, which is then included in the simulations. Electrical behavior of sandstone and two carbonates presenting distinct resistivity index curves were simulated and compared to measurements. Both Archie and ``non-Archie'' behavior were correctly reproduced, and the curve shape was explained considering percolation of the different phases.

In this paper we present a new experimental setup combining laboratory high resolution computed micro-tomography (MCT) with a flow microcell specially designed to reproduce in-situ multiphase flow experiments and monitor the fluid distribution at the pore scale. The objective is to describe the fluid saturations and distribution at different steps of the capillary pressure cycle (drainage and imbibition) while maintaining the sample under pressure in the cell to avoid fluid re-distribution. Experiments have been performed on a monomodal sandstone where the total porosity is resolved by the MCT. We compared successfully the saturation profiles calculated from the mean grey level of the 2D cross sections and the saturation profiles calculated by 3-phase image segmentation. The two above mentioned methods can be combined in bimodal pore systems to evaluate the fluid saturations in both micro (unresolved) and macro (resolved) porosity. Finally, we describe the distribution of each fluid at the different steps of the drainage-imbibition cycle and the influence of the pore geometry and interfacial tension on the oil trapping.

A signal loss is generally reported in electron probe microanalysis (EPMA) of porous, highly divided materials like heterogeneous catalysts. The hypothesis generally proposed to explain this signal loss refers to porosity, roughness, energy losses at interfaces, or charging effects. In this work we investigate by Monte Carlo simulation all these physical effects and compare the simulated results with measurements obtained on a mesoporous alumina. A program using the PENELOPE package and taking into account these four physical phenomena has been written. Simulation results show clearly that neither porosity nor roughness, nor specific energy losses at interfaces, nor charging effects are responsible for the observed signal loss. Measurements performed with analysis of carbon and oxygen lead to a correct total of concentration. The signal loss is thus explained by a composition effect due to a carbon contamination brought by the sample preparation and to a lesser extent by a stoichiometry of the porous alumina different from a massive alumina. For this kind of high specific surface porous sample, a little surface contamination layer becomes an important volume contamination that can produce large quantification errors if the contaminant is not analyzed.

Abstract Reservoir rocks often present complex pore-structures involving multiple porosity systems with various interconnectivity patterns. These pore-systems, from microporosity to vugs/fissures, drastically affect petrophysical properties. This is particularly true for electrical properties (formation factor and resistivity index) for which both the amount and spatial distribution of microporosity plays a crucial role. Pore network models (PNM) are well suited to calculate petrophysical properties of rocks from pore space structure information. The predictability of such models depends on the accuracy with which the complex geometry and topology of the pore network are described. This complex fine structure of the pore network can be captured by high resolution Computed Micro-Tomography (µ-CT). The aim of the present work is to combine a dual pore network approach with the µ-CT information to simulate specific electrical behaviour of a set of selected rocks. The dual PNM combines transport properties of the microporosity (capillary pressure and resistivity index of the microporosity which is considered to be homogeneous) with the deterministic pore network modelling of the macroporosity. µ-CT is used both to extract some properties of the microporosity and to build the equivalent macropore network. Formation factors, and resistivity indices are simulated and compared to measurements. The experimentally observed specific electrical behaviours of rocks are reproduced and interpreted. Introduction Carbonate fields are expected to dominate production through the next years (over 50% of today world reserves) so it becomes a priority for industry to better understand carbonate behaviour. However evaluating reservoir using standard resistivity interpretation [1, 20] generally fails in carbonates which have complex pore structures [9]. The cementation and saturation exponents (m and n) sometimes vary dramatically from the conventionally assumed value of 2 [4, 10, 12]. Understanding how rock properties depend on the pore structure is thus necessary for an optimal recovery strategy. Many research efforts have focussed on the relationship between the porous structure and the electrical properties using theoretical models such as effective medium and percolation theories [21, 26] or numerical models based on 3D reconstructed image and stochastic network [2, 16, 19]. These models work well for rocks with a homogeneous matrix. The development of µ-CT facility gives the opportunity to go further in the complexity of rocks in terms of structure. In recent works, 3D images of the actual structure of bimodal carbonate rocks associated with the random walk technique [13] or finite element modelling [17] have been used to assess the electrical properties. These studies show the direct impact of the spatial distribution of the microporosity on the formation factor and the resistivity index. The objective of the present work is to investigate the effect of pore architecture on electrical properties calculated with a dual-porosity pore network model used in drainage conditions. At first, we carry out 3D µ-CT imaging, Pc, formation factor and resistivity index measurements during drainage on a set of sandstone and carbonate rocks. We additionally explain a methodology to assess microporosity properties from 3D images by three phase segmentation. Then we describe the use of a dual-pore network model taking into account both the actual resolved macropore space and the spatial distribution of the microporous phase. Finally, we present a parametric study to evaluate the impact of the local heterogeneity pattern of the microporous phase.

We experimentally study the electrical transport in partially water-saturated pore network. The porous medium under investigation is a Fontainebleau sandstone, characterized by x-ray tomography. We show the existence of two electrical conductivity regimes. At high water saturation, the electric resistivity follows a well-known Archie law. Below a water saturation ${S}_{w}\ensuremath{\sim}0.2$, a strong negative deviation from this Archie law is observed. We attribute this transition to the existence of ``a thick liquid film,'' assuring the ionic conduction in the low saturation regime. A numerical simulation is proposed to confirm this scenario. Two possible protocols are used to distribute the brine phase in the pore network of a three-dimensional microtomography image. The first one is based on a minimization of the interfacial energy. The second takes into account a quasistatic capillary displacement. The classical random-walk algorithm is used to compute the electric conductivity at various water saturations. Without the ``thick film,'' both of the two fluid-placing protocols show a disconnectedness transition of the brine phase when ${S}_{w}l0.2$. Adding this ``film'' to solid surface, the electrical continuity is maintained. The bending down trend is correctly reproduced, showing that in this range, the electric response cannot be described by a power law as usual.

Reservoir rocks often present complex pore-structures involving multiple porosity systems with various interconnectivity patterns. These pore-systems, from microporosity to vugs/fissures, drastically affect petrophysical properties. This is particularly true for electrical properties (formation factor and resistivity index) for which both the amount and spatial distribution of microporosity plays a crucial role.

Carbonate rocks often present complex pore-structures involving multiple porosity systems with various interconnectivity degrees. These pore-systems, from microporosity to vugs/fissures, drastically affect petrophysical properties. Pore network models are well suited to calculate petrophysical properties of rocks from pore space structure information. The predictability of such models depends on the accuracy with which the complex geometry and topology of the pore network are captured. Computed MicroTomography (μCT) produces 3D images of the porous medium at the micron scale thus giving the opportunity to describe quantitatively and with a high precision the geometrical and topological characteristics of the 3D pore space. By providing a full description of pore space connectivity and geometry, such studies promise to improve both the understanding of diagenetic overprint and predictability of pore network models used to calculate petrophysical properties of these porous media.This methodology is applied to a set of rocks with various heterogeneity degrees from the Tengiz buildup (Precaspian Basin). The Tengiz central platform contains a succession of cyclic shallow water deposits ranging from Famennian to Bashkirian in age. The distribution of reservoir rock-types in this depositional zone is determined by a combination of primary deposition and burial diagenetic modification and includes spatial variations of both porosity enhancing as well as porosity filling effects. A pilot study using pore-network modeling from μ-CT imagery of several selected samples resulted in spatial pore and pore-throat size distributions, level and type of pore interconnectivity. Porosity, permeability and capillary pressure were calculated from μ-CT analyses and show a close match with those derived from measurements. Most strikingly, μ-CT allowed the extraction of 3Ddistribution of pore type and connectivity as well as cement types, information essential to reservoir quality assessment but very difficult to reconstruct using the classic petrographic approach. These models can be used for rock-typing, up scaling, to extrapolate petrophysical properties to uncored wells and to investigate new phenomena like evolution of properties due to dissolution/precipitation inherent in CO2 injection.

The saturation profiles are routinely measured during Special Core Analysis (SCAL experiments). Several ways exist to use this information in the inversion procedure of the relative permeability data. To date, the local saturation profiles are either included in a global objective function that is minimized during the inversion process, or smoothed and used as input data in the simulation, which leads to non smoothed simulated pressure drop. None of these methods permit to reproduce the local saturation fluctuations that are measured during coreflooding experiments. Our approach has the advantage to take benefit from these fluctuations to characterize the petrophysical properties for a given rock-type. In this paper, the methodology is first recalled and illustrated on a synthetic case. It is based on upscaling techniques applied in reservoir simulation. Both the stabilized and transient saturation profiles are analyzed to evaluate the local properties. The quality of the history matching is significantly improved. In addition, both kr and Pc-curves are obtained from only one experiment and the variability of these parameters with the heterogeneity is also investigated. This estimated interval of confidence for kr and Pc can be very useful to perform uncertainty studies at the reservoir scale. The Pc-curve interval of confidence determined with this method on a carbonate sample, is in good agreement with the variability observed with several centrifuge experiments performed on sister plugs. Finally an alternative approach derived of the heterogeneous method is proposed, which allows a very quick acquisition of all the information relative to kr and Pc during a multi-rate flow experiments.

Heterogeneous catalysts are of primary importance for many industrial processes. Catalysts are frequently obtained by including small amounts of active species on a porous carrier having a very high specific surface. For design and optimization purposes, electron probe micro analysis (EPMA) is routinely used in our laboratory. With EPMA, the sample is irradiated by a monoenergetic keV electron beam. X-ray Bremsstrahlung and characteristic photons are then selected by either an energy dispersive spectrometer (EDS) or a wavelength dispersive spectrometer (WDS). The characteristic line intensity (of relaxation of inner-shell ionisation photons) of the unknown sample is measured as well as the intensity of this same line emerging from a standard of a well known composition. Correction procedures are applied to achieve a quantification of the elements. Yet when traditional EPMA correction procedures are processed for our porous alumina samples, unrealistically low total composition are observed. The alumina porous samples (porosity ≈ 68%, specific surface ≈ 250m2/g, pore size ≈ 10 nm) emit about 10% less photons on Al Kα line than a massive sample of same composition.

This paper presents the rock image analysis equipment and methods available in the IFP. These images are either digital core sample images recorded at a macroscopic scale or images obtained with an electron microscope (STEM, SEM). We also show how one can study flow in porous media by the use of a medical scanner. In conclusion we expose the problems encountered and the developments that one can expect using these techniques., Cette publication présente les moyens et les méthodes d'analyse d'images de roches à l'IFP. Ces images sont soit des images numériques de carotte de forage enregistrées à l'échelle macroscopique, soit des images issues d'un microscope électronique (MEB ou MEBT). Nous montrons également comment l'écoulement de fluides dans les milieux poreux peut être étudié par un scanner médical. Nous concluons par les difficultés rencontrées dans l'utilisation de ces techniques et les développements espérés., Bieber Marie-Thérèse, Lallemand Claude, Rosenberg Elisabeth, Zinsner Bernard. Le traitement numérique d'images de roches à l'Institut Français du Pétrole. Digital processing of rock images in the Institut Français du Pétrole. In: Sciences Géologiques. Bulletin, tome 41, n°2, 1988. Traitements d'images et objets géologiques. pp. 233-240.

We examine the influence of the sample porosity on the X-ray emission from mesoporous alumina bombarded with kilovolt electrons. Experimental results show that there is a loss of X-rays (Al Kα and O Kα) from those samples when compared to a fully dense mono-crystalline alumina (sapphire), which depends on the X-ray line, the measurement time and the embedding medium. Both geometrical and charging effects may be responsibl e for this signal loss. Monte Carlo simulations of the X-ray intensity emitted from porous alumina, using different models to describe sample porosity, show that the geometrical effect of porosity itself cannot account for the X-ray loss. Charge trapping effect and/or its combination with porosity is therefore expected to be the major cause of the signal loss.

Mechanical effects are of great importance during reservoir production and induce sensible changes of the transport properties. This work focuses on the forecast of the change of porosity and permeabilities of reservoir rocks submitted to hydrostatic and deviatoric stress states representative of the field conditions. To predict these evolutions, we need to perform flow experiments with representative stress conditions. Our triaxial cell was designed to achieve this purpose and allows the measurement of permeabilities in the directions along and transverse to the principal direction of stresses. A good knowledge of the rock microstructures is also fundamental to choose the correct set of parameters for the simulation tools, and the input from our micro scanner facility is therefore of great importance. Using our directional permeability triaxial apparatus, we applied different stress paths to sandstones and carbonates samples and the evolutions of porosity and permeabilities were monitored during loading. We performed a microstructural analysis of these rocks using Mercury Porosimetry and Computed Micro Tomography imaging. From the 3D reconstructions, we extracted the poral network skeletons and the associated pore and throat size distributions. Then we performed two kinds of pore network modeling, one based on the real pore geometry and another based on a statistical description, to calculate the macroscopic transport properties. We included a model of pressure dependence of pore and throat sizes, based on deformation of porous inclusions in the framework of elasticity theory, to simulate the evolution of the transport properties with pressure. This model requires the knowledge of the elastic moduli of the rocks which were determined experimentally from the compression experiments. We show that the experimental determination of the evolution of directional permeabilities under hydrostatic and deviatoric stress conditions is feasible. The pressure dependences can be of valuable importance and therefore influence of mechanical effects should be investigated in experimental transport studies. Finally, we show that pore network modeling associated with CMT imaging can be used to forecast the pressure evolution of transport properties and therefore to understand the reservoir response to production.

Foam has long been used as a mobility control agent in Enhanced Oil Recovery (EOR) processes to enhance sweep efficiency and overcome gravity segregation, viscous fingering and gas channeling, which are gas-related problems when the latter is injected alone in the reservoir. However, the systematic use of foam in reservoir engineering requires more in-depth knowledge of its dynamics in porous media. The literature shows two types of experimental approaches based either on petrophysical studies carried out on 3D porous systems and based on pressure measurements, or on microfluidic studies that allow direct visualization of foam flow but are limited to 1D or 2D model systems. The research investigated in this thesis aims to bridge the gap between these two approaches. The proposed strategy is to characterize in situ the foam flow in 3D porous media with techniques providing a wide range of temporal and spatial resolutions. A coreflood setup giving access to classical petro-physical measurements was developed and then coupled to different observation cells designed specifically for each characterization instrument. First, an X-ray CT scanner was used to describe and visualize the foam flow at the core scale. The rheological behavior of foam on this scale was studied as a function of the injection conditions such as gas velocity and foam quality. Secondly, Small Angle Neutron Scattering (SANS) was used to probe the foam structure in situ during the flow, on a wide length scale, up to three orders of magnitude in size. In situ foam texture (size and density of bubbles and lamellae) was measured for different foam qualities and at different propagation distances from the injection point. A comparison to the geometric characteristics of the porous medium was also realized. Thirdly, High Resolution Fast X-ray Micro-tomography on a Synchrotron was used to visualize the foam flow at the pore scale. This allowed to confirm visually some foam characteristics measured with SANS and to investigate on local intermittent gas trapping and mobilization. This study is an important step in the multi-scale characterization of foam flow in 3D porous media and provides some answers to certain generally accepted assumptions., L’utilisation de la mousse en récupération assistée du pétrole (Enhanced Oil Recovery, EOR) présente un avantage indéniable par rapport à l’injection du gaz seul pour pallier les problèmes de ségrégation gravitaire et de digitations visqueuses. Son utilisation systématique en ingénierie du réservoir nécessite des connaissances plus approfondies sur son comportement en milieu poreux. La littérature montre deux types d’approches expérimentales basées soit sur des études pétrophysiques effectuées sur des systèmes poreux 3D et basées sur des mesures de pressions intégrées sur l’ensemble du milieu poreux, soit sur des études micro-fluidiques qui permettent une visualisation directe de l’écoulement mais qui sont limitées à des systèmes modèles dans des géométries à 1 ou 2 dimensions. L’objectif de cette thèse est de faire le pont entre ces deux approches. La stratégie proposée consiste à caractériser in situ l’écoulement de la mousse dans des milieux poreux 3D à différentes échelles, en utilisant des techniques complémentaires permettant d’accéder à une large gamme de résolutions spatiale et temporelle. Un environnement instrumenté donnant accès aux mesures pétro-physiques classiques a été développé puis couplé à différentes cellules d’observation conçues spécifiquement pour chaque instrument de caractérisation. Dans un premier temps, un scanner X a été utilisé pour décrire et visualiser les écoulements de la mousse à l’échelle de la carotte. La rhéologie de la mousse à cette échelle a pu être étudiée en fonction des conditions d’injections comme la vitesse interstitielle du gaz et la qualité de mousse. Dans un deuxième temps, la technique de diffusion des neutrons aux petits angles (SANS) a permis de sonder la texture de la mousse en écoulement sur trois ordres de grandeurs en taille. Des informations in situ sur la texture de la mousse en écoulement (taille et densité des bulles et des lamelles) ont pu être mesurées pour différentes qualités de mousse puis en fonction de la distance au point d’injection. Une comparaison avec les caractéristiques géométriques du milieu poreux a également été effectuée. Dans un troisième temps, la micro-tomographie X rapide haute résolution sur Synchrotron a été utilisée pour visualiser la mousse en écoulement à l’échelle du pore. Cette technique a permis de confirmer de visu certaines caractéristiques de la mousse mesurées par SANS et de décrire en sus les effets d’intermittence du piégeage de la mousse. Cette étude constitue une étape importante de la caractérisation multi-échelle de l’écoulement des mousses en milieux poreux 3D et apporte des éléments de réponse à certaines hypothèses admises.