Pore‐scale analysis of trapped immiscible fluid structures and fluid interfacial areas in oil‐wet and water‐wet bead packs

The objective of this study is to obtain quantitative evidence of pore‐scale immiscible fluid distribution in oil‐wet and water‐wet porous media using X‐ray computed microtomography. Temporal and spatial saturation profiles, as well as surface and interfacial areas, are thoroughly analyzed through cycles of drainage and imbibition using samples with different wetting characteristics but similar pore structures. The population of individual immiscible fluid structures (‘blobs’) was also evaluated. The specific nonwetting phase surface areas of both porous media are found to be in close correlation with the specific solid surface area. On the other hand, the differing wetting strengths of the two porous media affect the curvature of the fluid–fluid interface and thus the specific meniscus interfacial area of the two porous media. Although the magnitude of the specific meniscus interfacial areas is different, they both trend toward a maximum at wetting phase saturations of 0.35–0.55. The differences in wetting characteristics are also apparent in the blob populations. The number of blobs in the oil‐wet porous media is three times greater than that of the water‐wet porous media at similar saturations; the increase in population is a result of the increase in the amount of smaller blobs inhabiting the smaller pore spaces. The surface areas of individual blobs as a function of the individual blob volumes are found to closely agree with the specific surface area of a sphere at blob volumes below the minimum individual grain volume and with the specific pore space surface area above this volume. These results show how wettability and saturation history influence the distribution of immiscible fluids within the pore space.     

Pore‐scale investigation on stress‐dependent characteristics of granular packs and the impact of pore deformation on fluid distribution

Understanding the effect of changing stress conditions on multiphase flow in porous media is of fundamental importance for many subsurface activities including enhanced oil recovery, water drawdown from aquifers, soil confinement, and geologic carbon storage. Geomechanical properties of complex porous systems are dynamically linked to flow conditions, but their feedback relationship is often oversimplified due to the difficulty of representing pore‐scale stress deformation and multiphase flow characteristics in high fidelity. In this work, we performed pore‐scale experiments of single‐ and multiphase flow through bead packs at different confining pressure conditions to elucidate compaction‐dependent characteristics of granular packs and their impact on fluid flow. A series of drainage and imbibition cycles were conducted on a water‐wet, soda‐lime glass bead pack under varying confining stress conditions. Simultaneously, X‐ray micro‐CT was used to visualize and quantify the degree of deformation and fluid distribution corresponding with each stress condition and injection cycle. Micro‐CT images were segmented using a gradient‐based method to identify fluids (e.g., oil and water), and solid phase redistribution throughout the different experimental stages. Changes in porosity, tortuosity, and specific surface area were quantified as a function of applied confining pressure. Results demonstrate varying degrees of sensitivity of these properties to confining pressure, which suggests that caution must be taken when considering scalability of these properties for practical modeling purposes. Changes in capillary number with confining pressure are attributed to the increase in pore velocity as a result of pore contraction. However, this increase in pore velocity was found to have a marginal impact on average phase trapping at different confining pressures.     

Are rocks still water‐wet in the presence of dense CO2 or H2S?

The various modes of acid gas storage in aquifers, namely structural, residual, and local capillary trapping, are effective only if the rock remains water‐wet. This paper reports an evaluation, by means of the captive‐bubble method, of the water‐wet character in presence of dense acid gases (CO₂, H₂S) of typical rock‐forming minerals such as mica, quartz, calcite, and of a carbonate‐rich rock sampled from the caprock of a CO₂ storage reservoir in the South‐West of France. The method, which is improved from that previously implemented with similar systems by Chiquet et al. (Geofluids 2007; 7 : 112), allows the advancing and receding contact angles, as well as the adhesion behavior of the acid gas on the mineral substrate, to be evaluated over a large range of temperatures (up to 140°C), pressures (up to 150 bar), and brine salinities (up to NaCl saturation) representative of various geological storage conditions. The water‐receding (or gas‐advancing) angle that controls structural and local capillary trapping is observed to be not significantly altered in the presence of dense CO₂ or H₂S. In contrast, some alteration of the water‐advancing (or gas‐receding) angle involved in residual trapping is observed, along with acid gas adhesion, particularly on mica. A spectacular wettability reversal is even observed with mica and liquid H₂S. These results complement other recent observations on similar systems and present analogies with the wetting behavior of crude oil/brine/mineral systems, which has been thoroughly studied over the past decades. An insight is given into the interfacial forces that govern wettability in acid gas‐bearing aquifers, and the consequences for acid gas geological storage are discussed along with open questions for future work.     

Gas breakthrough experiments on pelitic rocks: comparative study with N2, CO2 and CH4

The capillary‐sealing efficiency of intermediate‐ to low‐permeable sedimentary rocks has been investigated by N₂, CO₂ and CH₄ breakthrough experiments on initially fully water‐saturated rocks of different lithological compositions. Differential gas pressures up to 20 MPa were imposed across samples of 10–20 mm thickness, and the decline of the differential pressures was monitored over time. Absolute (single‐phase) permeability coefficients (k_abs), determined by steady‐state fluid flow tests, ranged between 10^?22 and 10^?15 m². Maximum effective permeabilities to the gas phase k_eff(max), measured after gas breakthrough at maximum gas saturation, extended from 10^?26 to 10^?18 m². Because of re‐imbibition of water into the interconnected gas‐conducting pore system, the effective permeability to the gas phase decreases with decreasing differential (capillary) pressure. At the end of the breakthrough experiments, a residual pressure difference persists, indicating the shut‐off of the gas‐conducting pore system. These pressures, referred to as the ‘minimum capillary displacement pressures’ (P_d), ranged from 0.1 up to 6.7 MPa. Correlations were established between (i) absolute and effective permeability coefficients and (ii) effective or absolute permeability and capillary displacement pressure. Results indicate systematic differences in gas breakthrough behaviour of N₂, CO₂ and CH₄, reflecting differences in wettability and interfacial tension. Additionally, a simple dynamic model for gas leakage through a capillary seal is presented, taking into account the variation of effective permeability as a function of buoyancy pressure exerted by a gas column underneath the seal.     

Wettability alteration of caprock minerals by carbon dioxide

One of the critical factors that control the efficiency of CO₂ geological storage process in aquifers and hydrocarbon reservoirs is the capillary‐sealing potential of the caprock. This potential can be expressed in terms of the maximum reservoir overpressure that the brine‐saturated caprock can sustain, i.e. of the CO₂ capillary entry pressure. It is controlled by the brine/CO₂ interfacial tension, the water‐wettability of caprock minerals, and the pore size distribution within the caprock. By means of contact angle measurements, experimental evidence was obtained showing that the water‐wettability of mica and quartz is altered in the presence of CO₂ under pressures typical of geological storage conditions. The alteration is more pronounced in the case of mica. Both minerals are representative of shaly caprocks and are strongly water‐wet in the presence of hydrocarbons. A careful analysis of the available literature data on breakthrough pressure measurements in caprock samples confirms the existence of a wettability alteration by dense CO₂, both in shaly and in evaporitic caprocks. The consequences of this effect on the maximum CO₂ storage pressure and on CO₂ storage capacity in the underground reservoir are discussed. For hydrocarbon reservoirs that were initially close to capillary leakage, the maximum allowable CO₂ storage pressure is only a fraction of the initial reservoir pressure.     

Precipitation patterns formed by self‐organizing processes in porous media

We compare laboratory and field examples of self‐organized mineral precipitates in porous media. Laboratory tests of silver chromate precipitation in glass beads and glass bead/gel mixtures produce structures such as periodic banding and mm‐size spherules. These are morphologically similar to the varied forms of iron oxide precipitates in the Jurassic Navajo Sandstone, Utah USA, that preserve records of former fluid redox boundaries in a porous and permeable sandstone. Experimental studies of periodic precipitates in porous media can provide valuable insight for understanding the diagenetic history of similar precipitates in natural environments.     

Experimental investigation of carbon dioxide trapping due to capillary retention in saline aquifers

Capillary trapping is a physical mechanism by which carbon dioxide (CO₂) is naturally immobilized in the pore spaces of aquifer rocks during geologic carbon sequestration operations, and thus a key aspect of estimating geologic storage potential. Here, we studied capillary trapping of supercritical carbon dioxide (scCO₂), and the effect of initial scCO₂ saturation and flow rate on the storage/trapping potential of Berea sandstone. We performed two‐phase, scCO₂‐brine displacements in two samples, each subject to four sequential drainage–imbibition core‐flooding cycles to quantify end‐point saturations of scCO₂ with the aid of micro‐ and macro‐computed tomography imaging. From these experiments, we found that between 51% and 75% of the initial CO₂ injected can be left behind after the brine injection. We also observed that the initial scCO₂ saturation influenced the residual scCO₂ saturation to a greater extent than the rate of brine injection under the experimental conditions examined. In spite of differences in the experimental conditions tested, as well as those reported in the literature, initial and residual saturations were found to follow a consistent relationship.     

Thermodynamic study of capillary pressure curves based on free energy minimization

This paper presents a new method for pore level network simulation of the distribution of two immiscible phases in a permeable medium. The method requires that the Helmholtz free energy of the system — the medium and the two phases contained within the pore space — be a minimum at all saturation states. We describe the method here and show some typical results from a computer algorithm that implements it. The results include (i) an explanation of the ‘scanning’ behaviour of capillary pressure curves based wholly on the free energy minimization, (ii) predictions of capillary pressure at arbitrary wetting states, including negative capillary pressures, and (iii) illustrations of how the minimized free energy changes along the scanning curves. The method also predicts the known dependency of the capillary pressure on the pore size distribution and interfacial tension. The current work is restricted to two‐dimensional networks, but the free energy minimization appears to be generalizable to three dimensions and to more than two fluid phases. Moreover, functions generated through the minimization, specifically contact areas between the medium surface and the phases, appear to have applications predicting other multiphase petrophysical properties.     

Multiphase flow simulation through porous media with explicitly resolved fractures

Accurate simulation of multiphase flow in fractured porous media remains a challenge. An important problem is the representation of the discontinuous or near discontinuous behaviour of saturation in real geological formations. In the classical continuum approach, a refined mesh is required at the interface between fracture and porous media to capture the steep gradients in saturation and saturation‐dependent transport properties. This dramatically increases the computational load when large numbers of fractures are present in the numerical model. A discontinuous finite element method is reported here to model flow in fractured porous media. The governing multiphase porous media flow equations are solved in the adaptive mesh computational fluid dynamics code IC‐FERST on unstructured meshes. The method is based on a mixed control volume – discontinuous finite element formulation. This is combined with the P_N+1DG‐P_NDG element pair, which has discontinuous (order N+1) representation for velocity and discontinuous (order N) representation for pressure. A number of test cases are used to evaluate the method's ability to model fracture flow. The first is used to verify the performance of the element pair on structured and unstructured meshes of different resolution. Multiphase flow is then modelled in a range of idealised and simple fracture patterns. Solutions with sharp saturation fronts and computational economy in terms of mesh size are illustrated.     

Gas breakthrough experiments on fine-grained sedimentary rocks

The capillary sealing efficiency of fine‐grained sedimentary rocks has been investigated by gas breakthrough experiments on fully water saturated claystones and siltstones (Boom Clay from Belgium, Opalinus Clay from Switzerland and Tertiary mudstone from offshore Norway) of different lithological compositions. Sand contents of the samples were consistently below 12%, major clay minerals were illite and smectite. Porosities determined by mercury injection lay between 10 and 30% while specific surface areas determined by nitrogen adsorption (BET method) ranged from 20 to 48 m² g ^{? 1}. Total organic carbon contents were below 2%. Prior to the gas breakthrough experiments the absolute (single phase) permeability (k_abs) of the samples was determined by steady state flow tests with water or NaCl brine. The k_abs values ranged between 3 and 550 nDarcy (3 × 10^?21 and 5.5 × 10^?19 m²). The maximum effective permeability to the gas‐phase (k_eff) measured after gas breakthrough on initially water‐saturated samples extended from 0.01 nDarcy (1 × 10^?23 m²) up to 1100 nDarcy (1.1 × 10^?18 m²). The residual differential pressures after re‐imbibition of the water phase, referred to as the ‘minimum capillary displacement pressures’ (P_d), ranged from 0.06 to 6.7 MPa. During the re‐imbibition process the effective permeability to the gas phase decreases with decreasing differential pressure. The recorded permeability/pressure data were used to derive the pore size distribution (mostly between 8 and 60 nm) and the transport porosity of the conducting pore system (10^‐5–10^‐2%). Correlations could be established between (i) absolute permeability coefficients and the maximum effective permeability coefficients and (ii) effective or absolute permeability coefficients and capillary sealing efficiency. No correlation was found between the capillary displacement pressures determined from gas breakthrough experiments and those derived theoretically by mercury injection.     

Seismic Response of Rolling Isolation Systems with Concave Friction Distribution

This article attempted to improve the isolation performance of a rolling isolation system by assuming that the rolling friction force gradually and linearly increased with the relative displacement between the isolator and the ground. After the rolling isolation system under different ground motions was calculated by a numerical analysis method, it obtained more regular results than that of other uneven friction distributions. Results shows that the considered concavely distributed friction force can not only dissipate the earthquake energy, but also change the structural natural period. These functions improve the seismic isolation efficiency of the structural relative displacement in comparison with the general uniform distribution of rolling friction coefficient.     

Structure of grain boundaries in wet,synthetic polycrystalline,statically recrystallizing halite – evidence from cryo‐SEM observations

It is well known from nature and experiments that the presence of brine strongly affects the microstructural evolution and the mechanical and transport properties of halite. Existing interpretations of the grain boundary structure in deformed, wet, salt samples annealed statically at room temperature are based on indirect evidence from reflected light microscopy and conventional scanning electron microscopy. This paper presents direct observations of fluid‐filled grain boundaries using the cryogenic‐scanning electron microscope (cryo‐SEM) in which the grain boundary fluids were frozen before breaking the samples. The rapid cooling transforms the brine into two phases, i.e. ice and hydrohalite, which are easily recognized from characteristic segregation patterns. We studied samples of wet, synthetic, polycrystalline halite annealed under static conditions at room temperature. In coarse‐grained samples, fine‐scale segregation patterns were observed at the boundaries of the primary recrystallizing grains. These points indicate the existence of fluid films with a thickness in the range of 30 nm, but the finer scale structure of the fluid remains unknown. In fine‐grained samples, the distribution and reorganization of fluids with annealing time is recorded by the combination of contact healing and successive accumulation of fluids in triple junction tubes. The contact healing is attributed to the small initial grain size, such that the fluid film necks down by accumulating the fluids into previously existing triple junctions via neck growth. Electron backscatter diffraction measurements of both primary and secondary recrystallized grains indicate that they are euhedral, i.e. the grain growth morphology is controlled by the anisotropy of the grain boundary energy of the growing grain, which results in planar growth faces.     

Experimental study of the effect of variation in in‐situ stress on capillary residual trapping during CO2 geo‐sequestration in sandstone reservoirs

During a geo‐sequestration process, CO₂ injection causes an increase in reservoir pore pressure, which in turn decreases the reservoir net effective stress. Changes in effective stress can change all the reservoir and cap‐rock properties including residual saturations. This article presents the results of an experimental work carried out to understand the potential change in the volumes of residually trapped CO₂, while the porous medium tested underwent change in the net effective stress under in‐situ reservoir conditions of pore pressure and temperature. The experimental results obtained show that an initial 1725 psi (11.9 MPa) decrease in the net effective pressure caused 1.4% reduction in the volumes of residually trapped CO₂, while another 1500 psi (10.3 MPa) reduction caused a further 3.2% drop in the residual saturation of CO₂.     

COLOURED OPAQUE GLASS BEADS OF THE MEROVINGIANS*

Monochrome coloured opaque glass beads of the Merovingians have been examined by different analytical methods. A large number of mostly unprepared beads have been measured by X‐ray fluorescence analysis. X‐ray diffraction was used for the identification of the crystalline colouring and opacifying pigments, and electron probe micro‐analysis as well as scanning electron microscopy were applied to study the composition and the microstructure of a white, brown, green, orange and yellow glass bead. After subtracting the content of colouring oxides of the glass beads and normalizing the residual values to 100% an identical soda‐lime‐glass matrix was obtained. The origin of the colouring metal oxides is discussed.     

Study of coal gas wettability for CO2 storage and CH4 recovery

To quantify and rank gas wettability of coal as a key parameter affecting the extent of CO₂ sequestration in coal and CH₄ recovery from coal, we developed a contact angle measuring system based on a captive gas bubble technique. We used this system to study the gas wetting properties of an Australian coal from the Sydney Basin. Gas bubbles were generated and captivated beneath a coal sample within a distilled water‐filled (pH 5.7) pressurised cell. Because of the use of distilled water, and the continuous dissolution and shrinkage of the gas bubble in water during measurement, the contact angles measured correspond to a ‘transient receding’ contact angle. To take into account the mixed‐gas nature (CO₂, CH₄, and to a lesser extent N₂) of coal seam gas in the basin, we evaluated the relative wettability of coal by CH₄, CO₂ and N₂ gases in the presence of water. Measurements were taken at various pressures of up to 15 MPa for CH₄ and N₂, and up to 6 MPa for CO₂ at a constant temperature of 22°C. Overall, our results show that CO₂ wets coal more extensively than CH₄, which in turn wets coal slightly more than N₂. Moreover, the contact angle reduces as the pressure increases, and becomes < 90° at various pressures depending on the gas type. In other words, all three gases wet coal better than water under sufficiently high pressure.     

Fluid injection and surface deformation at the KTB location: modelling of expected tilt effects

This investigation is indented to explore the relationship between changes in pore fluid pressure and deformation of the land surface induced by a large‐scale injection experiment at the KTB site. Deformation will be monitored by ASKANIA borehole tiltmeters at five locations. During the year 2003, a network of borehole tiltmeters was installed, data transmission links established and tested, and recording of tilt data started. Our first main interest was to receive data sets of all stations well before the injection experiment to start in May 2004, to be able to evaluate local site effects. Thus, the separation of injection‐induced effects will be more reliable. Principal 3D numerical modelling (poro‐elastic modelling and investigations, using the finite element method, FEM) of poro‐elastic behaviour showed that significant tilt amplitudes can be expected during controlled fluid injection. Observed deformation will be investigated within the framework of the fluid flow behaviour and resulting deformation. Two models have been used: a coupled hydro geomechanical finite element model (abaqus ) and, as a first step, also a multi‐layered poro‐elastic crust (poel ). With the numerical model two effects can be quantified: (i) the deformation of the upper crust (tilt measurements) and (ii) the spatial distribution and the changes of material properties in the KTB area. The main aim of the project is to improve the knowledge of coupled geomechanic–hydraulic processes and to quantify important parameters. Thus, the understanding of fracture‐dominated changes of the hydrogeological parameters will be enhanced, geomechanical parameter changes and the heterogeneity of the parameter field quantified. In addition, the induced stress field variation can be explained, which is believed to be mainly responsible for the increase of local seismic activity. Here, we introduce the tiltmeter array at the KTB site, the modelling for a poro‐elastic crust and the preliminary FEM modelling.     

Pliocene sand injectites from a submarine lobe fringe during hydrocarbon migration and salt diapirism: a seismic example from the Lower Congo Basin

Large‐scale conical and saucer‐shaped sand injectites have been identified in the Upper Miocene sediments of the Lower Congo Basin. These structures are evidenced on the 3D high‐resolution seismic data at about 600 ms TWT (two‐way traveltime) beneath the seabed. The conical and saucer‐shaped anomalies range from 20 to 80 m in height, 50 to 300 m in diameter, and 10 to 20 ms TWT in thickness. They are located within a sedimentary interval of about 100 m in thickness and are aligned over 20 km in dip direction (NE‐SW), above the NW margin of an underlying Upper Miocene submarine fan. We have interpreted the conical and saucer‐shaped anomalies as upward‐emplaced sand injectites sourced from the Upper Miocene fan because of their discordant character, the postsedimentary uplifting of the sediments overlying the cones and saucer‐shaped bodies, the alignment with the lateral fringe of the Upper Miocene submarine fan, and the geological context. Sand injection dates from the Miocene–Pliocene transition (approximately 5.3 Ma). The prerequisite overpressure to the sand injection process may be due to the buoyancy effect of hydrocarbons accumulated in the margins of the fan. Additionally, overpressure could have been enhanced by the lateral transfer of fluids operating in the inclined margins of the lobe. The short duration of sand injection and the presence of many sandstone intrusions suggested that the process of injection was triggered by an event, likely due to a nearby fault displacement related to diapiric movements. This is the first time that sand injectites of seismic scale have been described from the Lower Congo Basin. The localized nature of these injectites has led to a change in the migration path of fluids through the sedimentary cover. Consequently, the sand intrusions are both evidence and vectors of fluid migration within the basin fill.     

Cementation and the hydromechanical behavior of siliciclastic aquifers and reservoirs

Progressive cementation and lithification significantly influence the mechanical and hydrologic properties of granular porous media through elastic stiffening and permeability reduction. We use published data that quantify the effect of grain‐bridging cement distribution in granular porous media at the grain scale to investigate the influence of variable cement content on the competing roles of hydrologic and mechanical effects on fluid flow and deformation at the reservoir scale. The impact of quartz overgrowths in natural samples was quantified using a bond‐to‐grain ratio, allowing a geologically meaningful interpretation of percent cement in conceptual models of quartz cementation. An increase in the bond‐to‐grain ratio from 1 to 2.2 (~1–15% cement by volume) results in a 1.4‐fold increase in Young's modulus and an ~1000‐fold decrease in permeability. The hydromechanical properties of a suite of variably cemented natural samples are used as input into two‐dimensional, kilometre‐scale, axially symmetric poroelastic models of an isotropic confined aquifer. Models isolating the hydrologic and mechanical effects of cementation indicate that the hydrologic properties dominate the overall mechanical response, controlling both the volume and magnitude of deformation. Incorporation of changes in hydrologic properties due to cementation is therefore essential to capturing the first‐order physics of coupled aquifer behavior.     

Quantifying secondary migration efficiencies

Exploration success relies on properly risking the hydrocarbon system relevant for each prospect. Accurate risking of secondary migration efficiencies has been difficult due to lack of simple procedures that relate rock properties such as permeability and entry pressures to migration velocities, oil stringer heights and saturations. In order to achieve improved estimates of charge probabilities, equations for the secondary migration process are formulated based upon the Darcy flow and buoyancy conditions. An analytical solution of the formulated equations is shown, making it possible to construct charts for efficiently assessing the column height of secondary migration hydrocarbon stringers. The average oil (hydrocarbon) saturation of the migrating stringer can be computed, making it easy to compute the permeability related, secondary migration losses. Inputs to the chart are hydrocarbon flow‐rates and flow‐path width, hydrocarbon viscosity and density, carrier bed dip, permeability and entry pressures. Outputs are stringer heights, hydrocarbon saturation, relative permeability, migration velocities and migration losses. A procedure for including the new equations into existing basin scale fluid flow simulators is outlined and a Java applet for calculating the properties is described. The Java applet is useful for sensitivity studies, and can also be used to test results from basin simulators with the new migration efficiency equations. The analytical solution suggests that many published methods for calculating hydrocarbon migration in fluid flow simulators will over‐estimate hydrocarbon saturations and therefore losses. Calculated migration velocities will also be too low.     

Experimental study of aqueous fluid infiltration into quartzite: implications for the kinetics of fluid redistribution and grain growth driven by interfacial energy reduction

To investigate the kinetics of interfacial energy‐driven fluid infiltration, experiments were carried out in a quartzite–water system at 621–925°C and 0.8 GPa. Infiltration couples were made by juxtaposing presynthesized dry quartzite cylinders and fluid reservoirs. The infiltration process was confirmed by the presence of pores at the quartzite grain edges. As predicted from theoretical considerations and previous experiments, wetting fluids such as pure water and NaCl aqueous solution infiltrated into quartzite, whereas nonwetting CO₂‐rich fluids did not. Newly precipitated quartz layers at the surfaces of the infiltrated sample proved that infiltration took place by a dissolution–precipitation mechanism. The enhancement of grain growth by fluid infiltration was observed over the entire range of experimental temperatures. The fluid fraction, gauged by the porosity of the run products, increases at the infiltration front and then decreases towards the fluid reservoir to form a high‐porosity zone with a maximum porosity of 2.3–2.9%. As infiltration proceeds, the high‐porosity zone advances like a travelling wave. This porosity wave is probably caused by a grain curvature gradient resulting from preferential grain growth in the infiltrated part of the quartzite, perhaps combined with other factors. The infiltration kinetics were modelled with a steady‐state diffusion model over the high‐porosity zone. The solubility difference between dissolving and precipitating grains was deduced to be 2 × 10^?2?3 × 10^?1 wt %. The experimentally obtained infiltration rate of aqueous fluid in the steady‐state diffusion regime (2 ± 0.5 × 10^?8 m sec^?1 at 823°C) is much faster than the estimated metamorphic fluid flux rates, so that interfacial energy‐driven fluid redistribution in quartz‐rich layers could significantly contribute to the fluid flux in high‐grade metamorphism, at least over a short distance. Cathodoluminescence observations of the run products revealed that the grain growth of quartzite in the presence of fluid proceeds extensively, which would promote the chemical equilibration between fluid and rock more effectively than would volume diffusion in quartz crystals.