Search

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

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.

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.

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.

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.

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).

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.