High-pressure experimental studies on geo-liquids using synchrotron radiation at the Advanced Photon Source
Abstract not provided
Wang, Yanbin↗
SEARCH · Engineering Papers
Results for “INTERFACIAL TENSION”
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A Review of Major Non-Power-Related Carbon Dioxide Stream Compositions
A critical component in the assessment of long-term risk from geologic sequestration of carbon dioxide (CO2) is the ability to predict mineralogical and geochemical changes within storage reservoirs as a result of rock-brine-CO2 reactions. Impurities and/or other constituents in CO2 source streams selected for sequestration can affect both the chemical and physical (e.g., density, viscosity, interfacial tension) properties of CO2 in the deep subsurface. The nature and concentrations of these impurities are a function of both the industrial source(s) of CO2, as well as the carbon capture technology used to extract the CO2 and produce a concentrated stream for subsurface injection and geologic sequestration. This article reviews the relative concentrations of CO2 and other constituents in exhaust gases from major non-energy-related industrial sources of CO2. Assuming that carbon capture technology would remove most of the incondensable gases N2, O2, and Ar, leaving SO2 and NOx as the main impurities, the authors then summarize the relative proportions of the remaining impurities assumed to be present in CO2 source streams that could be targeted for geologic sequestration. The summary is presented relative to five potential sources of CO2: 1) Flue Gas with Flue Gas Desulfurization, 2) Combustion Stack from Coke Production, 3) Portland Cement Kilns, 4) Natural Gas Combustion, and 5) Lime Production.
Carbon dioxide, CO2 source streams, CO2 impurities↗
Dynamic Wettability Alteration of Calcite, Silica and Illite Surfaces in Subsurface Environments: A Case Study of Asphaltene Self-Assembly at Solid Interfaces
A basic understanding of dynamic wettability alteration at complex solid interfaces in varying fluidic environments representative of the subsurface environments is essential for engineering field-scale strategies to enhance energy recovery while reducing environmental impacts. In this study, we characterize dynamic wettability alteration at solid surfaces (e.g., calcite, silica and illite) resulting from the self-assembly and adsorption of polyaromatic macromolecules known as asphaltenes in heptane and toluene solvents at 200 bar and 313 K using classical molecular dynamics simulations. These conditions are chosen to be representative of the subsurface environments. On adding asphaltenes, the equilibrium contact angles on calcite, silica and illite surfaces which are in the range of 25–34° increased to 69–79°. The adsorption and self-assembly of asphaltene molecules on the solid surfaces and the accumulation on water/hydrocarbon interfaces reduces the spreading distances of water molecules and enhances the hydrophobicity of the solid surfaces. Moreover, the accumulation of asphaltene molecules at the water/liquid hydrocarbon interfaces results in a reduction of the interfacial tension of water/heptane and water/toluene, thus stabilizing the water droplet. The enhanced surface hydrophobicity contributes to the formation of layered structures of heptane and toluene close to the solid surfaces and reduces the self-diffusivities of these molecules close to the surface.
42 ENGINEERING↗
Spatial characterization of heterogeneous nanopore surfaces from XCT scans of Niobrara shale
The multiphase fluid flow through natural and geo-architected nanopore structures is fundamentally controlled by the geometry of such nanopore structures, pore wettability and interfacial tension. Furthermore, multiphase fluid flow through the nanopore structures is compromised when the pore surfaces are heterogeneous, having surface regions of different composition, polarity, and wetting characteristics. In this regard, compositional analysis of the pore channel surface has been a big challenge in the past, since 3D analysis is required. Currently, due to advances in nano X-ray CT, with a voxel resolution of 20 nm, it is possible to identify nanopore network structures and quantify their surface composition in 3D. In this paper, the development of procedures for detailed analysis to quantify the composition of the pore channel surface regions, including the corresponding area, is described using nanoCT images. Image analysis procedures, including preprocessing of the 3D tomographic images, correction for the partial volume effect (PVE), and the use of a new algorithm for determination of pore channel surface composition and area are reported on. Videos of the nanopore structure have been provided as supplementary information to further describe the heterogeneity of the nanopore surfaces.
36 MATERIALS SCIENCE↗
Oil effect on CO 2 foam stabilized by a switchable amine surfactant at high temperature and high salinity
Despite the possible detrimental effect of oil on foam displacement processes in CO 2 EOR the effect of oil on dense CO 2 foams has received little attention relative to air foams or low density CO 2 foams. Herein, the effect of both a first contact miscible hydrocarbon (dodecane) and crude oil on CO 2 /water (C/W) foams generated by a switchable surfactant, C 12–14 N(EO) 2 was examined at dense CO 2 conditions at temperatures up to 120 °C (393 K) and 3400 psia (23 MPa). Upon increasing the fractional flow of dodecane, a gradual decrease in foam viscosity was observed as the foam becomes unstable. Since only two phases are present, traditional destabilization mechanisms for three phase oil/gas/water systems based on the entering and spreading are invalid. Therefore, an alternative mechanism is suggested whereby added dodecane strengthen the surfactant tail interactions with the nonaqueous phase (mixture of CO 2 and dodecane) to shift the hydrophilic-CO 2 philic balance (HCB) towards an unstable region. This mechanism is supported by a decrease of the CO 2 –water interfacial tension from ~5 mN/m to 0.5 mN/m for dodecane–water systems at 120 °C and 3400 psia. The effect of crude oil was more profound than for dodecane, whereby rapid destabilization of foam occurred at an oil fractional flow as low as 0.2. In this case, the immiscible portion of the crude oil can enter and spread at the lamellae to destabilize the foam as is evident in positive entering and spreading coefficients. Also, other foam destabilizing parameters such as temperature and capillary pressure were studied in the presence of oil and the results were consistent with those in the absence of oil.
nuclear (including radiation effects), carbon sequ↗
Empirical correlations for prediction of minimum miscible pressure and near-miscible pressure interval for oil and CO 2 systems
Although near-miscible CO 2 flooding has recently received considerable attention, no criteria are available to predict its applicability to a specific reservoir. Evaluating the viability of near-miscible flooding requires experimental exploration of a specific region in pressure–temperature space. The near-miscible pressure field is bounded on one side in P, T space by the MMP (minimum miscible pressure). This paper provides robust empirical correlations to estimate the MMP for both pure and impure CO 2 and for prediction of the near-miscible pressure region for CO 2 -oil. Many slim tube analyses, lacking high density data points, systematically underestimate the MMP, when the near miscible region is not accounted for. They are based on 147 published data sets that include: slim tube experimental determination of MMP; interfacial tension (IFT) between oil and CO 2 ; concentration of solution gas; and purity of the CO 2 . This paper is the first to begin a systematic exploration of the pressure-temperature space within which near-miscible effects characterize CO 2 floods. Our new correlations provide a basis for identifying and investigating the nature of near miscible effects associated with existing CO 2 floods. For a case study of an offshore field we determined that lower and upper pressure boundaries for effective near-miscible flooding, are 0.87 MMP and 1.07 MMP at reservoir temperatures. The proposed model is the first empirical correlation for the prediction of near-miscible pressure region, it will provide the basis for both screening the relative potential of oil reservoirs for economically viable miscible or near-miscible CO 2 -flooding.
42 ENGINEERING↗
The effect of original and initial saturation on residual nonwetting phase capillary trapping efficiency
Injection of supercritical carbon dioxide (CO 2 ) into geological formations is a strategy for both atmospheric greenhouse gas reduction (climate change mitigation) and enhanced oil recovery. To understand CO 2 trapping efficiency, the capillary trapping behaviors that immobilize subsurface fluids were analyzed at the pore-scale using pairs of proxy fluids representing the range of in situ nonwetting and wetting fluid properties encountered in geologic storage reservoirs. The pairs of fluids were cycled through imbibition and drainage processes using a flow cell apparatus containing a sintered glass bead column. Computed x-ray microtomography (microCT) was used to identify immobilized nonwetting fluid after imbibition and drainage events. From microCT images, the trapped residual (post-secondary imbibition) nonwetting phase was spatially correlated to both the original (post-primary imbibition) and the initial (post-primary drainage) nonwetting phase; this relationship is referred to here as the original saturation dependence (SO-dependence) and initial saturation dependence (SI-dependence), respectively. Significant trends of decreasing SO- and SI-dependence with increasing wetting and nonwetting fluid phase viscosities were observed. This finding implies that the amount of CO 2 injected and ultimately trapped is dependent on the nonwetting phase (e.g. oil or gas) already present in the formation, as well as on the manner in which supercritical CO 2 is initially injected, which are factors not considered in current trapping models. To explore the potential effect that varying viscosity and interfacial tension (IFT) might have on this process, we report on a variety of fluid pairs with different viscosities and IFT.
42 ENGINEERING↗
Carbon dioxide-in-oil emulsions stabilized with silicone-alkyl surfactants for waterless hydraulic fracturing
The design of surfactants for CO 2 /oil emulsions has been elusive given the low CO 2 -oil interfacial tension, and consequently, low driving force for surfactant adsorption. Here our hypothesis is that waterless, high pressure CO 2 /oil emulsions can be stabilized by hydrophobic comb polymer surfactants that adsorb at the interface and sterically stabilize the CO 2 droplets. The emulsions were formed by mixing with an impeller or by co-injecting CO 2 and oil through a beadpack (CO 2 volume fractions (φ) of 0.50–0.90). Emulsions were generated with comb polymer surfactants with a polydimethylsiloxane (PDMS) backbone and pendant linear alkyl chains. The C 30 alkyl chains are CO 2 -insoluble but oil soluble (oleophilic), whereas PDMS with more than 50 repeat units is CO 2 -philic but only partially oleophilic. The adsorbed surfactants sterically stabilized CO 2 droplets against Ostwald ripening and coalescence. The optimum surfactant adsorption was obtained with a PDMS degree of polymerization of ~88 and seven C 30 side chains. The emulsion apparent viscosity reached 18 cP at a φ of 0.70, several orders of magnitude higher than the viscosity of pure CO 2 , with CO 2 droplets in the 10–150 µm range. These environmentally benign waterless emulsions are of interest for hydraulic fracturing, especially in water-sensitive formations.
37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
Viscoelastic necking dynamics between attractive microgels
Hypothesis: Microgels can deform and interpenetrate and display colloid/polymer duality. The effective interaction of microgels in the collapsed state is governed by the interplay of polymer–solvent interfacial tension and bulk elasticity. A connecting neck is shown to mediate microgel interaction, but its temporal evolution has not been addressed. Here we hypothesize that the necking dynamics of attractive microgels exhibits liquid-like or solid-like behavior over different time and length scales. Experiments: We simulate the merging and pinching of attractive microgels with different crosslinking densities in explicit solvent using dissipative particle dynamics. The temporal coalescence dynamics of microgels is investigated and compared with simple liquid and polymeric droplets. We model the neck growth on long time scales using Maxwell model of polymer relaxation and compare the theoretical prediction with simulation data. The mechanical strength of the neck is characterized systematically via simulated pinch-off of microgels by steered molecular dynamics. Findings: We evidence a crossover in the coalescence dynamics reflecting the viscoelastic signature of microgels. In contrast to the common knowledge that viscoelastic materials respond elastically on short time scales, the early expansion of the microgel neck exhibits a linear behavior, similar to the viscous coalescence of liquid droplets. However, the late regime with arrested dynamics resembles sintering of solid particles. Through an analytical model relating microgel dynamics to neck growth, we show that the long-term behavior is governed by stress relaxation of the polymers in the neck region and predict an exponential decay in the rate of growth, which agrees favorably with the simulation. Different from coalescence, the thread thinning in microgel breakup primarily highlights its polymeric characteristics.
42 ENGINEERING↗
Carbon dioxide/water foams stabilized with a zwitterionic surfactant at temperatures up to 150 °C in high salinity brine
According to the article, stabilization of CO 2 -in-water (C/W) foams with surfactants at high temperature and high salinity conditions is challenging given limitations in the solubility and thermal stability of surfactants, particularly for surfactants other than anionic ones. Here we show that a single zwitterionic surfactant, cetyl betaine (CH 3 (CH 2 ) 15 N + (CH 3 ) 2 CH 2 COO - ), stabilizes viscous C/W foam (>15 cP) in crushed limestone (76-Darcy) at a temperature up to 150 °C and over a wide range in salinity up to 22% total dissolved solids (TDS) at superficial velocity of 940 ft/day. According to liquid chromatography mass spectrometry (LC/MS), cetyl betaine has high thermal stability with negligible chemical degradation after incubation at 135 °C for 30 days. Interfacial tension (IFT) at the C/W interface was reduced significantly from ~37 mN/m to <5 mN/m with the addition of 0.08 mmol/L of cetyl betaine. Relative to ionic surfactants, the relatively weak electrostatic repulsion between the local charges in the headgroup is shown to produce strong adsorption at the C/W interface (~134 Å2/molecule), resulting in generation of viscous foam (~6 cP) even in pure water without added salt. At a low superficial velocity of 6 ft/day (shear rate 45 s -1 ) in a beadpack, foam was still formed with cetyl betaine. Static adsorption of cetyl betaine on carbonates was on the order of 1 mg/m 2 , and core flood test also proved that cetyl betaine could stabilize viscous C/W foam (>20 cP) within 6 pore volumes of injection at 120 °C. The surfactant stabilized viscous C/W foam at low oil fractions and broke in the presence of large fractions of oil, both of which are desirable in CO 2 mobility control and oil displacement. The ability to form foams at high temperatures and over a wide range in salinity is important for various practical applications including CO 2 enhanced oil recovery, fracturing with energized fluids and CO 2 sequestration.
nuclear (including radiation effects), carbon sequ↗
Pore-scale modelling of multiphase reactive flow: application to mineral dissolution with production of CO 2
A micro-continuum approach is proposed to simulate the dissolution of solid minerals at the pore scale in the presence of multiple fluid phases. The approach employs an extended Darcy–Brinkman–Stokes formulation that accounts for the interfacial tension between the two immiscible fluid phases and the moving contact line at the mineral surface. The simulation framework is validated using an experimental microfluidic device that provides time-lapse images of the dissolution dynamics. The set-up involves a single-calcite crystal and the subsequent generation of CO 2 bubbles in the domain. The dissolution of the calcite crystal and the production of gas during the acidizing process are analysed. We then show that the production of CO 2 bubbles during the injection of acid in a carbonate formation may limit the overall dissolution rate and prevent the emergence of wormholes.
bio-inspired, mechanical behavior, carbon sequestr↗
Dissolving Nonionic Surfactants in CO 2 to Improve Oil Recovery in Unconventional Reservoirs via Wettability Alteration
CO 2 injection is a promising method for enhanced oil recovery (EOR) in unconventional shale reservoirs. Here, in this work, we postulate that CO 2 EOR may be improved by the dissolution of surfactants into CO 2 . Although CO 2 is a relatively good solvent for oil, we show that CO 2 and Eagle Ford oil are immiscible at compositions above 70 wt % CO 2 , even at pressures as high as 62 MPa. The presence of a CO 2 –oil interface at reservoir conditions indicates that the addition of a surfactant has the potential to improve oil recovery–via wettability alteration from oil-wet to CO 2 -wet, CO 2 –oil interfacial tension (IFT) reduction, or both. Three nonionic surfactants (branched tridecyl ethoxylate Indorama SURFONIC TDA-9, branched nonylphenol ethoxylate Indorama SURFONIC N-100, and linear dodecyl ethoxylate Indorama SURFONIC L12-6) were evaluated for CO 2 -solubility, shale wettability alteration, effect on CO 2 –oil IFT, ability to generate CO 2 –oil foams, and ability to increase oil extraction from Eagle Ford, Mancos, and Bakken shale cores. Each surfactant dissolved in CO 2 up to 1 wt % at pressures and temperatures commensurate with CO 2 EOR. CO 2 -dissolved surfactants did not significantly affect CO 2 –oil IFT or generate CO2–oil foams, but they did induce a dramatic change in the contact angle of an oil droplet on an oil-aged shale chip in CO 2 from strongly oil-wet (11°) toward intermediate CO 2 –oil wettability (82°) (at 80 °C, 27.6 MPa). The branched tridecyl ethoxylated surfactant, SURFONIC TDA-9, afforded the highest oil recovery in core soaking experiments–75%, compared to 71% by pure CO 2 . Analysis of oil extracts by gas chromatography revealed that heavier oil components were produced when the surfactant was added to CO 2 . These results indicate that CO 2 -dissolved surfactants may increase oil recovery from shale by wettability alteration from oil-wet toward CO 2 -wet.
04 OIL SHALES AND TAR SANDS↗
Segregation of Amphiphilic Polymer-Coated Nanoparticles to Bicontinuous Oil/Water Microemulsion Phases
Polymer-coated nanoparticles are interfacially active and have been shown to stabilize macroscopic emulsions of oil and water, also known as Pickering emulsions. However, prior work has not explored the phase behavior of amphiphilic nanoparticles in the presence of bicontinuous microemulsions. Here, we show that properly designed amphiphilic polymer-coated nanoparticles spontaneously and preferentially segregate to the bicontinuous microemulsion phases of oil, water, and surfactant. Mixtures of hydrophilic and hydrophobic chains are covalently grafted onto the surface of oxidized carbon black nanoparticles. By sulfating hydrophilic chains, the polymer-coated nanoparticles are stable in the aqueous phase at salinities up to 15 wt % NaCl. These amphiphilic, negatively charged polymer-coated nanoparticles segregate to the bicontinuous microemulsion phases. Here, we analyzed the equilibrium phase behavior of the nanoparticles, measured the interfacial tension, and quantified the domain spacing in the presence of nanoparticles. Lastly, this work shows a novel route to the design of polymer-coated nanoparticles which are stable at high salinities and preferentially segregate to bicontinuous microemulsion phases.
37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
Extracting Natural Biosurfactants from Humus Deposits for Subsurface Engineering Applications
Environmentally benign, economical, and effective surfactants and additives are needed in engineering subsurface energy recovery processes. Biosurfactants have some advantages over chemically synthesized surfactants, but the high costs of microbial-biosynthesis limit their applications in subsurface engineering. In this work, we propose to use naturally occurring biosurfactants contained within Earth's readily available and inexpensive humus deposits for subsurface engineering applications. We collected humus samples of different types from four different regions, and developed a simple method for extracting natural biosurfactant (NBS) using only four common chemicals. The average NBS extraction yields are 16 ± 3% of the raw humus. No significant differences in elemental composition and functional group chemistry were found among the NBS extracted from humus of different origins, suggesting that any humus deposit can be used for NBS extraction. Measurements of interfacial tensions between air-water and supercritical (sc) CO 2 -water interfaces indicate that the NBS is a highly effective surfactant. NBS has good foaming ability. Preliminary tests with only 0.5 mass % NBS in the aqueous phase (no other additives) yielded scCO 2 -in-water foams of 83% foam quality. The apparent viscosity of 13 cP measured at a shear rate of 2320 s -1 indicates that much higher viscosities are achievable at lower shear rates. Finally, these results suggest that NBS merits further research and development for potential applications in subsurface energy production.
32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗
High Pressure Infiltration/Expulsion of Aqueous NaCl in Planar Hydrophobic Nanopores
Pressure-driven permeation of water in a poorly wettable material results in a conversion of mechanical work into surface free energy representing a new form of energy storage, or absorption. When water is replaced by a concentrated electrolyte solution, the storage capacity of a nanoporous medium becomes comparable to high-end supercapacitors. The addition of salt can also reduce the hysteresis of the infiltration/expulsion cycle. Our molecular simulations provide a theoretical perspective into the mechanisms involved in the process, and underlying structures and interactions in compressed nanoconfined solutions. Specifically, we consider aqueous NaCl in planar confinements of widths of 1.0 nm and 1.64 nm and pressures of up to 3 kbar. Open ensemble Monte Carlo simulations utilizing fractional exchanges of molecules for efficient additions/removal of ions have been utilized in conjunction with pressure-dependent chemical potentials to model bulk phases under pressure. Confinements open to these pressurized bulk, aqueous electrolyte phases show reversibility at narrow pore sizes and irreversibility in wider ones, consistent with experiment, as well as strong hysteresis at both pore size. The addition of salt results in significant increases in the solid/liquid interfacial tension in narrower pores and associated infiltration and expulsion pressures. Furthermore, these changes are consistent with strong desalination effects at the lower pore size observed irrespective of external pressure and initial concentration.
25 ENERGY STORAGE↗
All-Atom Molecular Dynamics Study of Water–Dodecane Interface in the Presence of Octanol
In this work, classical atomistic molecular dynamics (MD) simulations were performed to investigate the structural properties of octanol at water/dodecane interface. Multiple combinations of simulation conditions and force fields were employed in order to :obtain high fidelity interfacial structure. The analysis of noncovalent interactions shows that the convergence of interfacial octanol distribution requires a simulation time scale larger than 100 ns. Finite size effect diminishes with increasing dimension of simulation box both laterally and vertically. In the largest simulated systems with vanishing finite size effect, the additive CHARMM force field shows similar interfacial aggregation behavior with the DRUDE polarizable model. Self-assembly of octanol molecules at water/oil interface is observed, expected to reduce;the free energy barrier between water phase and oil phase. This work provides an MD simulation benchmark for structural study of complex liquid/liquid interface with cosurfactant reducing interfacial tension between two immiscible phases.
Qiao, Baofu↗
Probing Structural Reconstruction of Metal Nanoparticles under Annealing and Water Vapor Conditions: A Theoretical Study
Knowing the structural reconstruction of metal nanoparticles (NPs) under working conditions is of great importance to catalytic processes. Here, using Wulff construction combined with density functional theory (DFT) and molecular dynamics (MD) simulation, we investigated truncated octahedron-based Rh and Ir NPs (3.5, 5.5, and 9.5 nm in size) with different morphology for their structural reconstruction under annealing and water vapor conditions. Our MD results show that the NPs with lower average atomic coordination number ($\overline{CN}$) of surface atoms have lowered structural transformation inertness and thermal stability, resulting in more severe structural transition especially for smaller-sized NPs and Ir NPs. Under water vapor conditions, the competition between the interfacial tension ($γ^{\overline{int}}_{hkl}$) of (111) and (110) facets plays a major role in driving the shape evolution of Rh and Ir NPs by minimizing the total surface tension. It is revealed that annealing in vacuum/water vapor condition is an irreversible/reversible process on Rh and Ir NPs. We identified that the total adsorbate–metal ($γ^{\overline{int}}_{hkl}$) can serve as a key stability parameter for describing the potential energy surface of adsorbate–metal NP system in a variable gaseous environment (P, T).
36 MATERIALS SCIENCE↗