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We report viscous flow properties of a redox-active organic molecule, N-(2-(2-methoxyethoxy)ethyl)phenothiazine (MEEPT), a candidate for non-aqueous redox flow batteries, and two of its radical cation salts. A microfluidic viscometer enabled the use of small sample volumes in determining viscosity as a function of shear rate and concentration in the non-aqueous solvent, acetonitrile, both with and without supporting salts. All solutions tested show Newtonian behavior over shear rates of up to 30 000 s−1, which was rationalized by scaling arguments for the diffusion-based relaxation time of a single MEEPT molecule without aggregation. Neat MEEPT is flowable but with a large viscosity (412 mPa⋅s at room temperature), which is ∼1000 times larger than that of acetonitrile. MEEPT solutions in acetonitrile have low viscosities; at concentrations up to 0.5 M, the viscosity increases by less than a factor of two. From concentration-dependent viscosity measurements, molecular information was inferred from intrinsic viscosity (hydrodynamic diameter) and the Huggins coefficient (interactions). Model fit credibility was assessed using the Bayesian Information Criterion. It is found that the MEEPT and its charged cations are “flowable” and do not flocculate at concentrations up to 0.5 M. MEEPT has a hydrodynamic diameter of around 8.5 Å, which is almost insensitive to supporting salt and state of charge. This size is comparable to molecular dimensions of single molecules obtained from optimized structures using density functional theory calculations. The results suggest that MEEPT is a promising candidate for redox flow batteries in terms of its viscous flow properties.
This paper describes the design, synthesis, and characterization of linear, polar, and non-polar polymethacrylates designed for use as lubricant viscosity index improvers with enhanced shear and anti-wear resistance. The polymers were prepared via Reversible Addition-Fragmentation Chain Transfer (RAFT) to obtain relatively low, narrow, molecular weights, with random polar moieties. The resulting polymers were evaluated as oil solutions to determine their viscosity index, shear stability performance, and antiwear characteristics. The polymers had molecular weights (Mw) ranging from 120-170 kDa, and the resulting viscosity indexes (VIs) in general tracked the Mw. Although the VIs were modest (140-189), all polymers displayed higher values than a commercial product designed for similar applications, both at 2% (w/w) and when kinematic viscosities (KVs) were normalized to the lowest KV100 of ~5cSt. One of the imidazole-containing polymers displayed an anomalously high VI for a low apparent Mw. As hypothesized, many of the polar polymers demonstrated substantial wear reduction compared to the non-polar homopolymers or a commercial benchmark. The low-molecular-weight imidazole-containing polymer produced less than 4% of the wear displayed by the commercial standard. The higher molecular weight polymers containing imidazole, hydroxy group and amino group also produced as little as 10% of the wear shown by the benchmark. The strategy demonstrated the benefit of low, narrow, molecular weight polymers to achieve good shear stability in viscosity modifiers while minimizing wear, rendering them suitable for fluid-power applications.
Capturing carbon dioxide (CO2) from post-combustion gas streams is an energy-intensive process that is required prior to either converting or sequestering CO2. There are a few commercial offerings of 1st and 2nd generation aqueous amine technologies, however the cost of capturing CO2 with these technologies remains high. To decrease costs of capture, researchers are designing efficient solvent systems with the goal of being drop-in replacements for 1st and 2nd generation infrastructure. One approach has seen the development of water-lean solvents that aim to increase efficiency by reducing the water content in solution. Water-lean solvents such as GE’s GAP/TEG are promising technologies, with potential to halve the parasitic load to a coal-fired power plant, only if the intrinsically high solution viscosities and hydrolysis of the siloxane moieties could be mitigated. We present here, an integrated multidisciplinary approach to overhaul the GAP/TEG solvent system at the molecular level to mitigate hydrolysis while also reducing viscosity. We present molecular-level insights into chemical speciation of CO2-containing ions, showing that co-solvents and diluents have a negligible effect on reducing viscosity and are not needed. This finding allowed for the design of singlecomponent siloxane-free diamine derivatives with site-specific incorporation of selective chemical moieties for direct placement and orientation of hydrogen bonding to reduce viscosity. Ultimately, we present new single-component diamine formulations less susceptible to hydrolysis that exhibit up to a 98% reduction in viscosity compared to the initial GAP/TEG formulation.
Characterizing the thermophysical properties in both fuel and coolant salts are critical in modeling, developing, process optimizing and utilizing molten salt reactors (MSRs), as these properties directly relate to operation metrics and can inform on the selection of candidate salts. The demand for consistent, accurate and publicly available thermophysical property data has become more apparent in recent years as interests have increased from molten salt reactor developers. There are a number of challenges in experimentally measuring properties such as thermal conductivity, viscosity, density and heat capacity , which have led to sparse and often times conflicting data points or molten salts in general. Additionally, there are a number of hazards to consider when synthesizing, storing, using, treating and disposing of molten salts. With the advances in computational capabilities over the last 10 years, the use of atomistic simulations can be implemented to support these efforts. The primary objective of this work is characterize the thermophysical transport properties in a number of molten chloride salts, and in particular NaCl-UCl 3 using ab-initio molecular dynamic (AIMD) simulations. In this binary salt the UCl 3 acts as the primary fissile material and NaCl acts as a carrier salt due with its’ high solubility for actinides A number of studies on the thermophysical properties of NaCl-UCl 3 have been published but there is not a vast amount of viscosity data for this system. In 1975, Desyatnik, et al published a study reporting dynamic viscosities that were calculated from kinematic viscosity measurements, and using the coefficients provided the viscosity in a 70:30 NaCl:UCl 3 mixture is 2.29 cP and 2.88 for a 60:40 mixture. Termini et al. recently reported viscosities in the range of 2.75 – 3 cP for the 63:37 NaCl-UCl 3 mixture in the same temperature range using rolling ball viscosity measurements. Computational viscosity of a similar mixture (64:36) can be obtained from the work Andersson et al. using the reported diffusion coefficients, and the hydrodynamic radius from the pair-radial distribution functions (RDFs). Using Eq (1) (vida infra), the viscosity would be 2.50 cP at 1100K. This is not to say that these values are incorrect due to the varying reported values, but aims to highlight the necessity of this work. The data reported in this ongoing work are computations on a 64:36 mixture of NaCl-UCl 3 at 987K. This work is likely to be expanded into varying concentrations of this mixture along with the inclusion of other salt candidate mixtures.
Organic aerosol (OA) is a complex matrix of various constituents—fresh (primary organic aerosols—POA) and aged via oxidation (secondary organic aerosols—SOA), generated from biogenic, anthropogenic, and biomass burning sources. The viscosity of OA can be critical in influencing new particle formation, reactive uptake processes that impact evaporation-growth kinetics, and the lifetime of particles in the atmosphere. We report this work utilizes a well-defined relationship between volatility and viscosity for pure compounds, which we incorporated within the Weather Research and Forecasting Model coupled to chemistry (WRF-Chem) to simulate the phase state and viscosity of bulk OA during the dry-to-wet transition season (September–October) in the Amazon rainforest during 2014. Our simulations indicate spatial and temporal heterogeneity in aerosol phase state often not captured by global-scale models. We show the strong role of water associated with organic aerosol ($w_s$) as the dominant factor that can be used to quantitatively estimate OA viscosity. Analysis of WRF-Chem simulations across the entire atmospheric column indicates a strong inverse log-linear relationship between $w_s$ and OA viscosity with a correlation coefficient approaching 1, in the background and biomass burning-influenced conditions. At high altitudes where relative humidity (RH) and temperatures are low, our simulations indicate that OA exists in a semisolid-/solid-like phase state, consistent with previous studies. OA hygroscopicity is strongly correlated (ca. –0.8) with OA viscosity at RH ca. 30–50%, but this RH range is found mostly at low OA concentrations and the middle troposphere (ca. 6–10 km altitudes) in our simulated domain. OA hygroscopicity is uncorrelated with viscosity at higher-RH (near surface) and lower-RH (upper troposphere) regimes. At the urban site near surface, where day–night differences in RH are significant, RH is found to drive the phase state. At the background forested site near surface, where day–night RH differences are small, biomass burning-influenced OA is semisolid and a significant OA associated with background conditions is liquid-like. Simulations indicate a long tail of OA viscosity frequency distributions extending in the semisolid/solid regimes over background biogenic-influenced conditions due to the role of low-volatility OA components such as monoterpene oxidation products.
We present simulations of two-phase flow using the Rothman and Keller colour gradient Lattice Boltzmann method to study viscous fingering when a “red fluid” invades a porous model initially filled with a “blue” fluid with different viscosity. We conducted eleven suites of 81 numerical experiments totalling 891 simulations, where each suite had a different random realization of the porous model and spanned viscosity ratios in the range $$M\in [0.01,100]$$ M ϵ [ 0.01 , 100 ] and wetting angles in the range $$\theta _w\in [180^\circ ,0^\circ ]$$ θ w ϵ [ 180 ° , 0 ° ] to allow us to study the effect of these parameters on the fluid-displacement morphology and saturation at breakthrough (sweep). Although sweep often increased with wettability, this was not always so and the sweep phase space landscape, defined as the difference in saturation at a given wetting angle relative to saturation for the non-wetting case, had hills, ridges and valleys. At low viscosity ratios, flow at breakthrough is localized through narrow fingers that span the model. After breakthrough, the flow field continues to evolve and the saturation continues to increase albeit at a reduced rate, and eventually exceeds 90% for both non-wetting and wetting cases. The existence of a complicated sweep phase space at breakthrough, and continued post-breakthrough evolution suggests the hydrodynamics and sweep is a complicated function of wetting angle, viscosity ratio and time, which has major potential implications to Enhanced Oil Recovery by water flooding, and hence, on estimates of global oil reserves. Validation of these results via experiments is required to ensure they translate to field studies.
Polymer rheology can have either a positive or a negative effect on polymer flooding performance under varied circumstances. Many researchers have studied the effect of polymer rheology in a vertical well, but no field scale studies have been conducted to investigate whether polymer rheology is beneficial to polymer flooding in heavy oil reservoirs developed by horizontal wells. In this paper, we conducted a numerical simulation study to examine the effect of HPAM polymer rheology on a polymer flooding pilot, which is the first-ever project conducted on a heavy oil reservoir from Alaska North Slope (ANS) developed by horizontal wells. Three rheology types were considered in the study including the apparent viscosity measured during coreflooding of using a HPAM polymer, the bulk viscosity measured with a viscometer, and a Newtonian flow model. The results suggest that using the bulk viscosity in simulation underestimates the conformance control and the water-oil-ratio reduction capability of the HPAM polymer solution. When the apparent viscosity is used, the incremental oil and sweep were largely increased, and the optimal recovery period of polymer flooding was extended greatly, especially for the heterogeneous formations. Therefore, the rheology type of polymer plays a significant role in the incremental oil recovery and injection profile of the horizontal well system given the pilot test conditions. This study has provided practical guidance to field operators for the ongoing polymer flooding pilot on ANS and will also provide valuable information for other polymer projects conducted in similar conditions.
The thermophysical characterization of molten chloride and fluoride salts is a key interest for the development of advanced molten salt nuclear reactors. Viscosity is one thermophysical property of interest; a high-accuracy understanding of this property is necessary for modeling the thermal energy transfer and mass flow rate for a given molten salt system. Only a few methods have consistently been used to measure the viscosity of molten chloride and fluoride salt systems, and large discrepancies have been observed in the literature between independent studies of nearly identical salt systems. As such, exploration of novel measurement methods or implementations may allow for further validation, improved measurement accuracy, and overall improved understanding about optimal approaches for measuring molten salt viscosity. Here, in this study, a novel implementation of the rolling ball viscometry method was used to measure the viscosity of a 44/56 mol % mixture of NaCl–KCl within a temperature range of 714–838 °C, with the intent to demonstrate the feasibility of this technique for molten salt viscosity measurement cross-validation. The purity of this salt was confirmed through laser-induced breakdown spectroscopy. Measured viscosities were approximately 1.3–1.0 cP within this temperature range, and the overall uncertainty was 10.8%, which was determined through Gaussian error propagation. The results agree reasonably well with measured viscosities of similar NaCl–KCl mixtures in the literature (within 2%–20% depending on the temperature and study), although the experimental error in some of these comparative studies may be significant.
Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drops from the injection well to the polymer front may act as a pressure modification or barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity. This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Analytical and numerical methods are used to address this issue. We examine the relevance of the pressure modification concept for a wide variety of circumstances, including oil viscosities ranging from 10 cp to 1650 cp, vertical wells versus horizontal wells, single versus multiple layered reservoirs, permeability contrast, and crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multizoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors intervene. For multizoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. This work is particularly relevant to viscous oil reservoirs where polymer viscosities are substantially lower than the oil viscosity.
Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drop from the injection well to the polymer front may act as a pressure barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity (and even sweep efficiency in some cases). This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Both analytical and numerical methods are used to address this issue. We examine the relevance of the pressure barrier concept for a wide variety of circumstances, including oil viscosities ranging from 10-cp (like at Daqing, China) to 1650-cp (like at Pelican Lake, Alberta), vertical wells (like at Tambaredjo, Suriname) versus horizontal wells (like at Milne Point, Alaska), single versus multiple layered reservoirs, permeability contrast, and with versus with crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multi-zoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors (like fracture extension) intervene. For multi-zoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. The relevance of our findings is applied to operations for several existing polymer floods. This work is particularly relevant to viscous-oil reservoirs (like Pelican Lake and others) where the injected polymer viscosities are substantially lower than the oil viscosity
Optimization of molding parameters at different filling stages requires that the characteristics of low-viscosity feedstocks must be properly known. In this study, the influence of the particle size (3, 7, and 12 μm) and powder morphology (gas- and water-atomized) was quantified using different feedstock formulations based on a 17-4 PH stainless steel powder, all combined with the same binder system. The specific heat capacity, viscosity, and segregation levels were assessed using a differential scanning calorimeter, a rotational rheometer, and a thermogravimetric analyzer, respectively. It was then shown that the feedstock prepared with the gas-atomized powder exhibits a higher specific heat capacity value when compared to a water-atomized powder (i.e., Cp varying from 0.6 to 0.3 J/g K, respectively). It was also shown that the feedstock viscosity profiles and the intensity of segregation both depend significantly on the powder shape and size used in the feedstock formulation. For short processing times (e.g., < 1 min spent in molten state), a feedstock formulated with coarse gas-atomized powder can be considered to be the best candidate for an injection process because its viscosity and segregation potential are relatively low (with a viscosity varying from 0.5 to 2 Pa s, and a volume fraction of powder close to 60 vol.%). Following this, the moldability index was used to predict that coarser water-atomized powder (i.e., 12 versus 7 μm) will not have a significant effect on the molding properties, and can be seen as a potential means of decreasing shrinkage during sintering without impacting the injection properties. For very long processing times, the magnitude of segregation remains insignificant for feedstock formulated with fine powder (i.e., a volume fraction of powder remaining close to 60 vol.%). However, this important gain (i.e., no segregation) comes with a significant increase in viscosity varying from 2 to 10 Pa s, resulting in a decrease in the molding properties.
This work investigates the rheology and stability of nanoparticle-stabilized CO 2 foams under reservoir conditions (high temperature and high pressure) for fracturing applications. The effects of different parameters on foam apparent viscosity and foam stability were experimentally investigated including the effects of nanoparticle concentration, salinity, foam quality (Γ), shear rate and temperature. The power law model was applied to calculate foam apparent viscosity owing to its pseudo-plastic behavior, and the changes of foam heights over time were used to evaluate foam stability. Results showed that the CO 2 foam apparent viscosity featured a mountain-shaped curve versus Γ, with the peak apparent viscosity obtained at 70% foam quality. The increase of salinity (up to 11%) in the continuous phase improved both foam stability and rheology. Higher nanoparticle concentration could contribute to better foam stability, but there was a threshold concentration, above which the foam apparent viscosity remained stabilized. The CO 2 foam stabilized by nanoparticles displayed a shear-thickening behavior as the experiment flow rate increased from 6 mL/min to 18 mL/min. Further studies showed that as the total flow rate increased, the CO 2 foam became finer-textured with better stability. Elevated temperatures could undermine foam apparent viscosity and long-term stability. The results of this study could provide guidelines as to the design of foam fracturing systems for field applications.
Vat photopolymerization (VP) and direct ink write (DIW) additive manufacturing (AM) provide complex geometries with precise spatial control employing a vast array of photo-reactive polymeric systems. Although VP is recognized for superior resolution and surface finish, DIW provides versatility for higher viscosity systems. However, each AM platform presents specific rheological requirements that are essential for successful 3D printing. First, viscosity requirements constrain VP polymeric materials to viscosities below 10 Pa s. Thus, this requirement presents a challenging paradox that must be overcome to attain the physical performance of high molecular weight polymers while maintaining suitable viscosities for VP polymeric materials. Second, the necessary rheological complexity that is required for DIW pastes requires additional rheological measurements to ensure desirable thixotropic behavior. Further, this manuscript describes the importance of rheological measurements when designing polymeric latexes for AM. Latexes effectively decouple the dependency of viscosity on molecular weight, thus enabling high molecular weight polymers with low viscosities. Photo-crosslinking of water-soluble monomers and telechelic oligomeric diacrylates in the presence of the latex enables the fabrication of a scaffold, which is restricted to the continuous aqueous phase and effectively surrounds the latex nanoparticles enabling the printing of otherwise inaccessible high molecular weight polymers. Rheological testing, including both steady and oscillatory shear experiments, provides insights into system properties and provides predictability for successful printing. This perspective article aims to provide an understanding of both chemical functionality (photo- and thermal-reactivity) and rheological response and their importance for the successful design and evaluation of VP and DIW processable latex formulations.
A significant effort was invested in the past to develop and refine mathematical models that relate the composition of nuclear waste glasses with their properties, such as viscosity, electrical conductivity, or chemical durability. However, less attention has been paid to the formulation of the melter feed itself, such as the chemical form and the particle size of the glass forming and modifying additives (GFMA), which have a significant effect on the feed-to-glass conversion process during melting. To address this issue, we systematically changed the mineral composition of a simulated low-activity waste melter feed and inspected its melting behavior. When substituting minerals with corresponding oxides and hydroxides, we found that different alumina sources (kyanite, gibbsite, boehmite, or corundum) had the strongest effect on the feed melting process, whereas the sources of Ca, Mg, and Zr had little effect. Further, the x-ray diffraction analysis showed that the alumina sources differ in their dissolution kinetics: early dissolving alumina sources, such as gibbsite (Al(OH) 3 ) and boehmite (AlO(OH)), increase the transient glass-forming melt viscosity at early stages, when gases still evolve, causing extended foaming, whereas alumina sources that dissolve at high temperatures, such as kyanite (Al 2 SiO 5 ) and corundum (Al 2 O 3 ), keep the transient glass-forming melt viscosity low and lead to a faster foam collapse. Using viscosity-composition relationship to estimate the viscosity of transient glass-forming melts in the primary foaming range, we found that the primary foam began to collapse at 360 to 800 Pa s, and fully collapsed between 65 and 260 Pa s. This result agrees with our previous studies, according to which the glass-forming melt viscosity at the cold cap foam bottom ranged from 24 to 85 Pa s.
Lithium-ion battery cathode slurries have a microstructure that depends sensitively on how they are processed due to carbon black's (CB) evolving structure when subjected coating flows. While polyvinylidene difluoride (PVDF), one of the main components of the cathode slurry, plays an important role in modifying the structure and rheology of CB, a quantitative understanding is lacking. In this work, we explore the role of PVDF in determining the structural evolution of Super C65 CB in N-methyl-2-pyrrolidinone (NMP) with rheo-electric measurements. We find that PVDF enhances the viscosity of NMP resulting in a more extensive structural erosion of CB agglomerates with increasing polymer concentration and molecular weight. We also show that the relative viscosity of all suspensions can be collapsed by the fluid Mason number (Mnf), which compares the hydrodynamic forces imposed by the medium to cohesive forces holding CB agglomerates together. Using simultaneous rheo-electric measurements, we find at high Mnf, the dielectric strength (Δε) scales with Mnf, and the power-law scaling can be quantitatively predicted by considering the self-similar break up of CB agglomerates. The collapse of the relative viscosity and scaling of Δε both suggest that PVDF increases the hydrodynamic force of the suspending medium without directly changing the CB agglomerate structure. These findings are valuable for optimizing the rheology of lithium ion battery cathode slurries. We also anticipate that these findings can be extended to understand the microstructure of similar systems under flow.