28 results found
Ekanem EM, Rücker M, Yesufu-Rufai S, et al., 2021, Novel adsorption mechanisms identified for polymer retention in carbonate rocks, JCIS Open, Vol: 4, Pages: 100026-100026, ISSN: 2666-934X
HypothesisHigh molecular weight polymers are widely used in oilfield applications, such as in chemical enhanced oil recovery (cEOR) technique for hydrocarbon recovery. However, during flow in a porous rock, polymer retention is usually a major challenge, as it may result in the decrease of polymer concentration or lead to plugging of pores with significant permeability reduction and injectivity loss. Hence, an understanding of the retention mechanisms will have a profound effect in optimizing the process of polymer flooding, in particular, for carbonate rocks, which hold more than half of the world's oil reserves. Therefore, in this study, the retention of hydrolysed polyacrylamide (HPAM) polymer, a commonly used chemical for EOR, is investigated during flow in Estaillades carbonate rock.ExperimentsA novel approach of investigating HPAM retention in Estaillades carbonate rock was carried out using Atomic force microscopy (AFM). Since Estaillades carbonate rock is ∼98% calcite, HPAM retention was first characterised on a cleaved flat calcite mineral surface after immersing in HPAM solution. Afterwards, HPAM was flooded in Estaillades carbonate to observe the effect of flow dynamics on the retention mechanisms.FindingsWe find that the dominant mechanism for retention of HPAM on calcite after fluid immersion is polymer adsorption, which we believe is driven by the electrostatic interaction between the calcite surface and the solution. The thickness of the adsorbed layer on calcite is beyond 3 nm suggesting it is not adsorbed only flat on the surface. Different types of adsorbed layers were formed representing trains, and the more extended loops or tails with the largest polymer layer thickness about 35 nm, representing the longer loops or tails. Layers of this thickness will begin to impair the permeability of the rock. However, in Estaillades, thicker adsorbed layers are observed in different regions of the rock surface ranging between 50 and 350 nm. We suggest
Savulescu GC, Rücker M, Scanziani A, et al., 2021, Atomic force microscopy for the characterisation of pinning effects of seawater micro-droplets in n-decane on a calcite surface, Journal of Colloid and Interface Science, Vol: 592, Pages: 397-404, ISSN: 0021-9797
Hypothesis: Roughness is an important parameter in applications where wetting needs to be characterized. Micro-computed tomography is commonly used to characterize wetting in porous media but the main limitation of this approach is the incapacity to identify nanoscale roughness. Atomic force microscopy, AFM, however, has been used to characterize the topography of surfaces down to the molecular scale. Here we investigate the potential of using AFM to characterize wetting behavior at the nanoscale.Experiments: Droplets of water on cleaved calcite under decane were imaged using quantitative imaging QI atomic force microscopy where a force-distance curve is obtained at every pixel.Findings: When the AFM tip passed through the water droplet surface, an attraction was observed due to capillary effects, such that the thickness of the water film was estimated and hence the profile of the droplet obtained. This enables parameters such as the contact angle and contact angle distribution to be obtained at a nanometer scale. The contact angles around the 3-phase contact line are found to be quasi-symmetrically distributed between 10–30°. A correlation between the height profile of the surface and contact angle distribution demonstrates a quasi-proportional relationship between roughness on the calcite surface and contact angle.
Gao Y, Georgiadis A, Brussee N, et al., 2021, Capillarity and phase-mobility of a hydrocarbon gas-liquid system, OIL & GAS SCIENCE AND TECHNOLOGY-REVUE D IFP ENERGIES NOUVELLES, Vol: 76, ISSN: 1294-4475
Yesufu-Rufai S, Rucker M, Berg S, et al., 2020, Assessing the wetting state of minerals in complex sandstone rock in-situ by Atomic Force Microscopy (AFM), Fuel, Vol: 273, Pages: 1-11, ISSN: 0016-2361
Low salinity waterflooding is a low-cost method of enhancing oil recovery although, no consistent concept has been established explaining why some oil-fields show an increase in oil production when the salinity of the injected brine is reduced, while others do not. Various studies were conducted investigating the underlying mechanisms of the ‘low salinity effect’ using different crude oil, brine and rock compositions. Core floods of sandstone rock and analyses of molecular interactions using model systems indicate that clay content may play a dominant role. However, the spatial configuration of the sheet-like clay particles, which may vary from rock to rock, complicate comparisons of these model scenarios with reality.In the present study, we report the development of a pre-screening method using Atomic Force Microscopy (AFM) to assess rock-fluid interactions, which has previously only been used either on artificial model systems or minerals from crushed rock, by exploring the capability to operate in-situ in complex rock without crushing. The orientation of clay particles within a pore of an outcrop sandstone, Bandera Brown, was investigated with AFM and these particles were further assessed for changes in adhesion in brines of differing salinity. The results show a decrease in adhesions between CH3-functionalised AFM tips and the rock surface in low salinity brine, predominantly at the clay edges. This demonstrates that the edges of the clay particles, which may pin the oil phase after wettability alteration and therewith prevent oil from getting produced, lose this capacity when exposed to low salinity brine.
Yesufu-Rufai S, Marcelis F, Georgiadis A, et al., 2020, Atomic Force Microscopy (AFM) study of redox conditions in sandstones: Impact on wettability modification and mineral morphology, Colloids and Surfaces A: Physicochemical and Engineering Aspects, Vol: 597, Pages: 1-10, ISSN: 0927-7757
Laboratory core flood experiments performed to establish chemical enhanced oil recovery (cEOR) procedures often make use of rock samples that deviate from prevailing conditions within the reservoir. These samples have usually been preserved in an uncontrolled oxidising environment in contrast to reducing reservoir conditions, a discrepancy that affects rock wettability and thus oil recovery. The use of a reducing fluid is a predominant method, particularly regarding iron-bearing minerals, for restoring these samples to representative redox states.In this study, the adhesion of polar (NH2 and COOH) and non-polar (CH3) crude oil components to the pore surfaces of Bandera Brown, an outcrop of similar mineralogy to reservoir sandstones, was investigated using Atomic Force Microscopy to determine the potential of a reducing fluid of Sodium Dithionite in seawater to alter surface wettability. This novel workflow for the observation of redox condition effects illuminates the nanoscopic interaction forces at the rock/fluid interface responsible this phenomenon.The results obtained show that adhesion forces between the oil components and the Bandera Brown surface after treatment with the reducing fluid decreased in the order: NH2 (∼70 %) >COOH (∼36 %) >CH3 (∼3 %), due to diminishing affinity of the surface for the polar functional groups when the oxidation state of iron was altered from iron III to iron II. The morphology of Bandera Brown is noted to be affected as well with some dissolution of the mineral composition within cemented pores observed.The results demonstrate that redox state is indeed important for the assessment of wetting properties of surfaces as measurements performed in oxidising environments may not be representative of reservoir reducing conditions. Also, complete reduction of iron oxides on the mineral surfaces seems unlikely without altering the prevailing pore structure. These findings have relevance not only in EOR cases but can fin
Zheng L, Rucker M, Bultreys T, et al., 2020, Surrogate models for studying the wettability of nanoscale natural rough surfaces using molecular dynamics, Energies, Vol: 13, ISSN: 1996-1073
A molecular modeling methodology is presented to analyze the wetting behavior of natural surfaces exhibiting roughness at the nanoscale. Using atomic force microscopy, the surface topology of a Ketton carbonate is measured with a nanometer resolution, and a mapped model is constructed with the aid of coarse-grained beads. A surrogate model is presented in which surfaces are represented by two-dimensional sinusoidal functions defined by both an amplitude and a wavelength. The wetting of the reconstructed surface by a fluid, obtained through equilibrium molecular dynamics simulations, is compared to that observed by the different realizations of the surrogate model. A least-squares fitting method is implemented to identify the apparent static contact angle, and the droplet curvature, relative to the effective plane of the solid surface. The apparent contact angle and curvature of the droplet are then used as wetting metrics. The nanoscale contact angle is seen to vary significantly with the surface roughness. In the particular case studied, a variation of over 65° is observed between the contact angle on a flat surface and on a highly spiked (Cassie–Baxter) limit. This work proposes a strategy for systematically studying the influence of nanoscale topography and, eventually, chemical heterogeneity on the wettability of surfaces.
Berg S, Gao Y, Georgiadis A, et al., 2020, Determination of critical gas saturation by micro-CT, Pages: 133-150, ISSN: 1529-9074
The critical gas saturation was directly determined using micro-CT flow experiments and associated image analysis. The critical gas saturation is the minimum saturation above which gas becomes mobile and can be produced. Knowing this parameter is particularly important for the production of an oil field that during its lifetime falls below the bubblepoint, which will reduce the oil production dramatically. Experiments to determine the critical gas saturation are notoriously difficult to conduct with conventional coreflooding experiments at the Darcy scale. The difficulties are primarily related to two effects: The development of gas bubbles is a nucleation process which is governed by growth kinetics that, in turn, is related to the extent of pressure drawdown below the bubblepoint. At the Darcy scale, the critical gas saturation at which the formed gas bubbles connect to a percolating path, is typically probed via a flow experiment, during which a pressure gradient is applied. This leads not only to different nucleation conditions along the core but also gives no direct access to the size and growth rate of gas bubbles before the percolation. In combination, these two effects imply that the critical gas saturation observed in such experiments is dependent on permeability and flow rate, and that the critical gas saturation relevant for the (equilibrium) reservoir conditions has to be estimated by an extrapolation. Modern digital-rock-related experimentation and modeling provides a more elegant way to determine the critical gas saturation. We report pressure-depletion experiments in minicores imaged by X-ray computed microtomography (micro-CT) that allowed the direct determination of the connectivity of the gas phase. As such, these experiments enabled the detection of the critical gas saturation via the percolation threshold of the gas bubbles. Furthermore, the associated gas- and oil relative permeabilities can be obtained from single-phase flow simulations of the
Berg S, Gao Y, Georgiadis A, et al., 2020, Determination of Critical Gas Saturation by Micro-CT, PETROPHYSICS, Vol: 61, Pages: 133-150, ISSN: 1529-9074
Rücker M, Bartels W-B, Bultreys T, et al., 2020, Workflow for upscaling wettability from the nano- to core-scales, International Symposium of the Society of Core Analysts
Rucker M, Bartels W-B, Garfi G, et al., 2020, Relationship between wetting and capillary pressure in a crude oil/brine/rock system: From nano-scale to core-scale, Journal of Colloid and Interface Science, Vol: 562, Pages: 159-169, ISSN: 0021-9797
HypothesisThe wetting behaviour is a key property of a porous medium that controls hydraulic conductivity in multiphase flow. While many porous materials, such as hydrocarbon reservoir rocks, are initially wetted by the aqueous phase, surface active components within the non-wetting phase can alter the wetting state of the solid. Close to the saturation endpoints wetting phase fluid films of nanometre thickness impact the wetting alteration process. The properties of these films depend on the chemical characteristics of the system. Here we demonstrate that surface texture can be equally important and introduce a novel workflow to characterize the wetting state of a porous medium.ExperimentsWe investigated the formation of fluid films along a rock surface imaged with atomic force microscopy using ζ-potential measurements and a computational model for drainage. The results were compared to spontaneous imbibition test to link sub-pore-scale and core-scale wetting characteristics of the rock.FindingsThe results show a dependency between surface coverage by oil, which controls the wetting alteration, and the macroscopic wetting response. The surface-area coverage is dependent on the capillary pressure applied during primary drainage. Close to the saturation endpoint, where the change in saturation was minor, the oil-solid contact changed more than 80%.
Lin Q, Bijeljic B, Krevor SC, et al., 2019, A New Waterflood Initialization Protocol With Wettability Alteration for Pore-Scale Multiphase Flow Experiments, Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description, Vol: 60, Pages: 264-272, ISSN: 1529-9074
Rücker M, Bartels WB, Singh K, et al., 2019, The Effect of Mixed Wettability on Pore-Scale Flow Regimes Based on a Flooding Experiment in Ketton Limestone, Geophysical Research Letters, Vol: 46, Pages: 3225-3234, ISSN: 0094-8276
© 2019. The Authors. Darcy-scale multiphase flow in geological formations is significantly influenced by the wettability of the fluid-solid system. So far it has not been understood how wettability impacts the pore-scale flow regimes within rocks, which were in most cases regarded as an alteration from the base case of strongly water-wet conditions by adjustment of contact angles. In this study, we directly image the pore-scale flow regime in a carbonate altered to a mixed-wet condition by aging with crude oil to represent the natural configuration in an oil reservoir with fast synchrotron-based X-ray computed tomography. We find that the pore-scale flow regime is dominated by ganglion dynamics in which the pore space is intermittently filled with oil and brine. The frequency and size of these fluctuations are greater than in water-wet rock such that their impact on the overall flow and relative permeability cannot be neglected in modeling approaches.
Lutz-Bueno V, Arboleda C, Leu L, et al., 2018, Model-free classification of X-ray scattering signals applied to image segmentation, Journal of Applied Crystallography, Vol: 51, Pages: 1378-1386, ISSN: 0021-8898
In most cases, the analysis of small-angle and wide-angle X-ray scattering(SAXS and WAXS, respectively) requires a theoretical model to describe thesample’s scattering, complicating the interpretation of the scattering resultingfrom complex heterogeneous samples. This is the reason why, in general, theanalysis of a large number of scattering patterns, such as are generated by time-resolved and scanning methods, remains challenging. Here, a model-freeclassification method to separate SAXS/WAXS signals on the basis of theirinflection points is introduced and demonstrated. This article focuses on thesegmentation of scanning SAXS/WAXS maps for which each pixel correspondsto an azimuthally integrated scattering curve. In such a way, the samplecomposition distribution can be segmented through signal classification withoutapplying a model or previous sample knowledge. Dimensionality reduction andclustering algorithms are employed to classify SAXS/WAXS signals according totheir similarity. The number of clusters,i.e.the main sample regions detected bySAXS/WAXS signal similarity, is automatically estimated. From each cluster, amain representative SAXS/WAXS signal is extracted to uncover the spatialdistribution of the mixtures of phases that form the sample. As examples ofapplications, a mudrock sample and two breast tissue lesions are segmented.
Bartels W-B, Rucker M, Berg S, et al., 2017, Fast X-Ray Micro-CT Study of the Impact of Brine Salinity on the Pore-Scale Fluid Distribution During Waterflooding, PETROPHYSICS, Vol: 58, Pages: 36-47, ISSN: 1529-9074
Leu L, Georgiadis A, Blunt MJ, et al., 2016, Multiscale description of shale pore systems by scanning SAXS and WAXS microscopy, Energy & Fuels, Vol: 30, Pages: 10282-10297, ISSN: 1520-5029
The pore space of shales and mudrocks ranges from molecular dimensions to micrometers in length scale. This leads to great variation in spatial characteristics across many orders of magnitude, which poses a challenge for the determination of a representative microscopic pore network for such systems. Standard characterization techniques generally provide volume-averaged properties while high-resolution imaging techniques do not assess a representative range of pore sizes because of limitations in the spatial resolution over the field of view. Due to this complexity, open questions remain regarding the role of the pore network in retention and transport processes, which in turn control oil and gas production. Volume-averaged but spatially resolved information is obtained for pores of size from 2 to 150 nm by applying scanning small- and wide-angle X-ray scattering (SAXS and WAXS) microscopy. Scattering patterns are collected in a scanning microscopy mode, such that microvoxels are sampled sequentially, over a total of 2 × 2 mm2 raster area on specifically prepared thin sections with a thickness of 10–30 μm. Spatially resolved variations of porosity, pore-size distribution, orientation, as well as mineralogy are derived simultaneously. Aiming at a full characterization of the shale pore network, the measurements and subsequent matrix porosity analysis are integrated in a multiscale imaging workflow involving FIB-SEM, SEM, and μ-CT analysis.
Berg S, Rücker M, Ott H, et al., 2016, Connected pathway relative permeability from pore-scale imaging of imbibition, Advances in Water Resources, Vol: 90, Pages: 24-35, ISSN: 1872-9657
Pore-scale images obtained from a synchrotron-based X-ray computed micro-tomography (µCT) imbibition experiment in sandstone rock were used to conduct Navier–Stokes flow simulations on the connected pathways of water and oil phases. The resulting relative permeability was compared with steady-state Darcy-scale imbibition experiments on 5 cm large twin samples from the same outcrop sandstone material. While the relative permeability curves display a large degree of similarity, the endpoint saturations for the µCT data are 10% in saturation units higher than the experimental data. However, the two datasets match well when normalizing to the mobile saturation range. The agreement is particularly good at low water saturations, where the oil is predominantly connected. Apart from different saturation endpoints, in this particular experiment where connected pathway flow dominates, the discrepancies between pore-scale connected pathway flow simulations and Darcy-scale steady-state data are minor overall and have very little impact on fractional flow. The results also indicate that if the pore-scale fluid distributions are available and the amount of disconnected non-wetting phase is low, quasi-static flow simulations may be sufficient to compute relative permeability. When pore-scale fluid distributions are not available, fluid distributions can be obtained from a morphological approach, which approximates capillary-dominated displacement. The relative permeability obtained from the morphological approach compare well to drainage steady state whereas major discrepancies to the imbibition steady-state experimental data are observed. The morphological approach does not represent the imbibition process very well and experimental data for the spatial arrangement of the phases are required. Presumably for modeling imbibition relative permeability an approach is needed that captures moving liquid-liquid interfaces, which requires viscous and capillary forces si
Leu LD, Georgiadis A, Blunt MJ, et al., 2016, Bridging pore and macroscopic scale - Scanning SAXS-WAXS microscopy applied to shales, Pages: 18-21
The determination of fabric and pore structure of shales remains a challenging task which is mainly due to the wide range of pore sizes (and shapes) ranging from molecular dimensions to microns. High resolution imaging techniques fail to provide information over representative regions of interest, while more conventional characterization techniques may only assess volume averaged properties of the pore systems. Thus, open questions remain regarding the effects of the multi-scale pore network of shales in the retention and transport of hydrocarbons during unconventional production processes. We apply scanning small- and wide-angle X-ray scattering (SAXS and WAXS) microscopy to obtain averaged but detailed information from the micro- and meso-pore structures of shales. By combining SAXS/WAXS with raster-scanning microscopy, we obtain local scattering information from 1-100 nm-size pores in micrometer-size volumes over a large (2 x 2) mm2 scanning area. We derive porosity, pore size distribution and orientation, as well as mineralogy of specially prepared thin section samples, covering length scale ranges of nm to submicrons and from microns to millimeters, with a gap that can potentially be closed The method further enables the linking of porosity to shale matrix components, which is integrated in a multi-scale imaging workflow involving μCT, and SEM/EDX analysis, aimed at allowing for the full pore network characterization of shales.
Armstrong RT, Ott H, Georgiadis A, et al., 2014, Subsecond pore-scale displacement processes and relaxation dynamics in multiphase flow, Water Resources Research, Vol: 50, Pages: 9162-9176, ISSN: 0043-1397
With recent advances at X‐ray microcomputed tomography (μCT) synchrotron beam lines, it is now possible to study pore‐scale flow in porous rock under dynamic flow conditions. The collection of four‐dimensional data allows for the direct 3‐D visualization of fluid‐fluid displacement in porous rock as a function of time. However, even state‐of‐the‐art fast‐μCT scans require between one and a few seconds to complete and the much faster fluid movement occurring during that time interval is manifested as imaging artifacts in the reconstructed 3‐D volume. We present an approach to analyze the 2‐D radiograph data collected during fast‐μCT to study the pore‐scale displacement dynamics on the time scale of 40 ms which is near the intrinsic time scale of individual Haines jumps. We present a methodology to identify the time intervals at which pore‐scale displacement events in the observed field of view occur and hence, how reconstruction intervals can be chosen to avoid fluid‐movement‐induced reconstruction artifacts. We further quantify the size, order, frequency, and location of fluid‐fluid displacement at the millisecond time scale. We observe that after a displacement event, the pore‐scale fluid distribution relaxes to (quasi‐) equilibrium in cascades of pore‐scale fluid rearrangements with an average relaxation time for the whole cascade between 0.5 and 2.0 s. These findings help to identify the flow regimes and intrinsic time and length scales relevant to fractional flow. While the focus of the work is in the context of multiphase flow, the approach could be applied to many different μCT applications where morphological changes occur at a time scale less than that required for collecting a μCT scan.
Armstrong RT, Georgiadis A, Ott H, et al., 2014, Critical capillary number: Desaturation studied with fast X- ray computed microtomography, GEOPHYSICAL RESEARCH LETTERS, Vol: 41, Pages: 55-60, ISSN: 0094-8276
Georgiadis A, Berg S, Makurat A, et al., 2013, Pore-scale micro-computed-tomography imaging: Nonwetting-phase cluster-size distribution during drainage and imbibition, Physical Review E, Vol: 88, ISSN: 1539-3755
We investigated the cluster-size distribution of the residual nonwetting phase in a sintered glass-bead porousmedium at two-phase flow conditions, by means of micro-computed-tomography (μCT) imaging with pore-scaleresolution. Cluster-size distribution functions and cluster volumes were obtained by image analysis for a range ofinjected pore volumes under both imbibition and drainage conditions; the field of view was larger thanthe porosity-based representative elementary volume (REV). We did not attempt to make a definition for atwo-phase REV but used the nonwetting-phase cluster-size distribution as an indicator. Most of the nonwettingphasetotal volume was found to be contained in clusters that were one to two orders of magnitude larger thanthe porosity-based REV. The largest observed clusters in fact ranged in volume from 65% to 99% of the entirenonwetting phase in the field of view. As a consequence, the largest clusters observed were statistically notrepresented and were found to be smaller than the estimated maximum cluster length. The results indicate thatthe two-phase REV is larger than the field of view attainable by μCT scanning, at a resolution which allows forthe accurate determination of cluster connectivity.
Georgiadis A, Berg S, Maitland G, et al., 2012, Pore-Scale Micro-CT Imaging: Cluster Size Distribution during Drainage and Imbibition, 6TH TRONDHEIM CONFERENCE ON CO2 CAPTURE, TRANSPORT AND STORAGE, Vol: 23, Pages: 521-526, ISSN: 1876-6102
Georgiadis A, Maitland G, Trusler JPM, et al., 2011, Interfacial Tension Measurements of the (H<sub>2</sub>O + <i>n</i>-Decane + CO<sub>2</sub>) Ternary System at Elevated Pressures and Temperatures, JOURNAL OF CHEMICAL AND ENGINEERING DATA, Vol: 56, Pages: 4900-4908, ISSN: 0021-9568
Georgiadis A, Llovell F, Bismarck A, et al., 2010, Interfacial tension measurements and modelling of (carbon dioxide plus <i>n</i>-alkane) and (carbon dioxide plus water) binary mixtures at elevated pressures and temperatures, JOURNAL OF SUPERCRITICAL FLUIDS, Vol: 55, Pages: 743-754, ISSN: 0896-8446
Georgiadis A, Maitland G, Trusler JPM, et al., 2010, Interfacial Tension Measurements of the (H<sub>2</sub>O + CO<sub>2</sub>) System at Elevated Pressures and Temperatures, JOURNAL OF CHEMICAL AND ENGINEERING DATA, Vol: 55, Pages: 4168-4175, ISSN: 0021-9568
Pentland CH, Iglauer S, El-Maghraby R, et al., 2010, Immiscible Displacements and Capillary Trapping in CO2 Storage, Amsterdam, 10th International Conference on Greenhouse Gas Control Technologies
Georgiadis A, 2001, Interfacial Tension of Aqueous and Hydrocarbon Systems in the Presence of Carbon Dioxide at Elevated Pressures and Temperatures
The interfacial tension of partially miscible phases, containing H2O andhydrocarbons in the presence of CO2 at elevated pressures and temperatures,has been studied within the context of producing cleaner fossil fuelsby simultaneously tackling greenhouse gas emissions. This is a most relevantproperty inuencing the multiphase reservoir ows associated withenhanced oil recovery (EOR), and carbon capture and storage (CCS). Themain core of the thesis focuses on the experimental investigation of thedependence of interfacial tension on pressure and temperature, for variousmixtures of pure substances relevant to oil- eld conditions and uids. Forthis purpose, a high pressure high temperature (HPHT) apparatus, comprisinga view cell, high pressure capillary tubing connections, and appropriateuid delivery syringe pumps, was used over an operating temperaturerange of (298 to 473)K and at pressures up to 60MPa. The apparatusimplemented the pendant drop method, well suited for the accuratedetermination of uid/liquid interfacial tensions at elevated pressures andtemperatures, linked to a computer-aided drop shape analysis (DSA) system.Measurements were made over a wide range of conditions for the twophasesystems (H2O+CO2), (n-decane+CO2), (n-dodecane+CO2), (n-hexadecane+CO2), (H2O+n-decane) and (H2O+[n-decane+CO2]). Thedi erent isotherms recorded for each system demonstrated systematic trendswith increasing pressure, while the decrease of interfacial tension with temperatureobserved at ambient pressures was usually reversed at elevatedpressures. For the (H2O+CO2) system in particular, the pressure dependenceof interfacial tension demonstrated abrupt changes at certain conditions,associated with the onset of the liquid or supercritical states, abovewhich the interfacial tension was less sensitive to changes in both pressureand temperature. This was not the case for the (n-alkane+CO2) systems,where the interfacial tension reduced with increasing pressure, vanishing asthe two phases be
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