NaCl Brine Research Articles

CO2 responsive emulsions stabilized with fatty acid soaps in NaCl brine

Similar to the responsive behaviors of emulsions under salt-free conditions, precise control of emulsification and demulsification is also required in some applications under saline conditions, especially in crude oil production and transport. So far, few studies have focused on the preparation of the responsive emulsions under saline conditions. In this study, CO2 responsive emulsions were prepared in the presence of NaCl using a fatty acid soap M-DA as stabilizer. M-DA complex was synthesized through electrostatic interactions between dimeric acid (DA) and Jeffamine (M1000). The droplet size and morphology of the oil–brine emulsions were characterized by dynamic light scattering and transmission electron microscopy, respectively. The oil–brine emulsion maintains high stability under air but completely separates into two phases upon exposure to CO2. NaCl plays a significant role in the CO2-induced demulsification, including salting-out effect and screening of electrostatic repulsion. It is worth noting that in the absence of NaCl, the emulsion remained stable after CO2 bubbling. CO2 responsive emulsions can also be prepared in the presence of other salts, or with other fatty acid soaps, which presents more interesting possibilities for preparation of CO2 responsive emulsions under saline conditions.

Effect of Muscat Oilfield Brine on the Stressed X-70 Pipeline Steel

Electrochemical and slow strain rate tensile tests were performed to understand the corrosion behaviour of X-70 pipeline steel in 3.5% NaCl and Muscat Oilfield brine. Scanning Electron Microscopy (SEM), Atomic Force Microscopy (AFM), and Energy Dispersive X-ray spectroscopy (EDX) were used in the investigation. The results showed that the corrosion rate of X-70 pipeline steel significantly decreased in oilfield brine and increased in saline solution. In the oilfield environment, a fine and compact corrosion film of iron carbonate which reduced the corrosion rate was observed. It was concluded that the iron carbonate film which was formed provided protection and delayed the time to failure of the X-70 pipeline steel compared to the test performed in a 3.5% NaCl environment. This mechanism will be important not only to the petroleum industry but also to the pipeline manufacturing industry in the selection of appropriate material for steel pipe design.

Oil-in-water emulsification of Athabasca bitumen with pyrrolidine solution

This paper presents an experimental study of use of pyrrolidine solutions to induce the oil-in-water (o/w) emulsion of Athabasca bitumen without using synthetic surfactants. Pyrrolidine, an organic alkali, acts not only as an alkali that generates natural surfactants from acidic oil components in bitumen, but also as a cosolvent that improves the fluidity of the o/w emulsions.Experimental results show that the o/w emulsions created by pyrrolidine solutions can result in a large mobility increase of bitumen because of their low viscosity and high bitumen content. O/w emulsions were observed at low pyrrolidine concentrations (below 20 wt% and as low as 0.5 wt%) and low salinities (0 and 1000 ppm). For example, the sample of 0.5 wt% pyrrolidine in 1000-ppm NaCl brine with 7:3 water-oil-ratio showed a single-phase o/w emulsion at all experimental temperatures from 298 K to 373 K. In comparison to the original bitumen, the o/w emulsion was 4–6 orders of magnitude less viscous at 298 K, 2–3 orders of magnitude less viscous at 323 K, and 1–2 orders of magnitude less viscous at 353 K.The affinity of the organic alkali for asphaltic bitumen is important for o/w emulsification at a wide range of temperatures. Pyrrolidine is superior to the other organic alkalis tested, diethylamine and triethylenetetramine, likely because the cyclic structure makes pyrrolidine more compatible with the asphaltic bitumen. The favorable result with pyrrolidine is also confirmed by the Hansen solubility dispersion parameter.

An Experimental Approach to Formulate Lignin-Based Surfactant for Enhanced Oil Recovery

The higher cost of chemical surfactants has been one of the main reasons for their limited used in enhanced oil recovery (EOR) process. Hence, the reason for developing lignin-based surfactant is to lower the cost of chemicals as it does not tie to the price of crude oil as compared to petroleum-based surfactants. Besides, lignin is biodegradable and easily extracted from plant waste. The objectives of this study are to determine the formulations of the lignin-based surfactant for EOR applications and to determine the oil recovery performance of the formulated surfactants through surfactant flooding. The lignin-based surfactants were formulated by mixing the lignin with the amine (polyacrylamide or hexamethylenetetramine) and the surfactant sodium dodecylbenzenesulfonate in a 20,000 ppm NaCl brine. Interfacial tension (IFT) of the formulated lignin-based surfactant is measured at ambient temperature using the spinning drop method. The displacement experiments were conducted at room temperature in glass beads pack holders filled with glass beads, saturated with paraffin and brine. The results of the study showed that the best formulation of lignin-based surfactant is using hexamethylenetetramine as the amine, lignin, and sodium dodecylbenzenesulfonate at 2% total active concentration. The oil recovery and interfacial tension using the lignin amine system is comparable with the commercial petroleum sulfonate system.

Experimental investigation of dynamic asphaltene adsorption on calcite packs: The impact of single and mixed‐salt brine films

AbstractIn this study, the dynamic adsorption of asphaltene on a calcite surface is investigated. This study investigates the effect of mixed‐salt brines on asphaltene adsorption. The results of this work can facilitate the understanding of the complex wettability behaviour of carbonate reservoirs. All experiments were performed in porous media, which were sand‐packs filled with calcite powder, to study the influence of the type and concentration of salt on adsorption. The experiments were conducted with asphaltene concentration of 500 mg/L for brines of NaCl, Na2SO4, and a mixture of the two at various ionic strengths. In addition, two tests were performed with an asphaltene concentration of 2000 mg/L to observe the effect of increasing the asphaltene concentration on the adsorption. Moreover, the impact of brine film on asphaltene adsorption was investigated by conducting an additional experiment without brine saturation. The results show that by increasing the ionic strength, asphaltene adsorption increased at first owing to the reduction of electrostatic forces, then it reached its maximum, and it finally decreased as a result of the rise in the hydration force. The results show that in the presence of Na2SO4 brine, the asphaltene adsorption is more than that of the NaCl brine. For the mixed‐salt brine, as the ionic strength was increased, the asphaltene adsorption decreased at first and then it became constant. Furthermore, quadrupling the initial asphaltene concentration increased the adsorption up to 3.4 times. Additionally, the presence of brine film reduced the asphaltene adsorption by ∼80 %.

Age and Origin of Monazite Symplectite in an Iron Oxide-Apatite Deposit in the Adirondack Mountains, New York, USA: Implications for Tracking Fluid Conditions

Monazite crystals, intergrown with allanite, fluorapatite, and quartz from the Cheever Mine iron oxide-apatite (IOA-type) deposit in Essex County, New York, USA, display rare symplectite textures. Electron probe wavelength-dispersive spectrometry (WDS) mapping and major and trace element characterization of these features reveal a natural experiment in fluid-mediated monazite recrystallization. Two types of monazite with symplectite intergrowths have been recognized (Type I and II). Both types of symplectite development are associated with a decrease in HREE, Si, Ca, Th, and Y, but an increase in both La and Ce in monazite. Electron microprobe Th-U-total Pb analysis of Type I monazite with suitable ThO2 concentrations yielded a weighted mean age of 980 ± 5.8 Ma (MSWD: 3.3), which is interpreted as the age of monazite formation and the onset of symplectite development. Both types of monazite formed during a series of reactions from fluorapatite, and possibly britholite, to produce the final assemblage of monazite, allanite, and fluorapatite. Monazite formation was likely a response to evolving fluid conditions, which favored monazite stability over fluorapatite at ca. 980 Ma, possibly a NaCl brine. A subsequent transition to a Ca-dominated fluid may have then promoted the consumption of monazite to produce another generation of allanite and fluorapatite. Our results indicate that recrystallized monazite formed during fluid-mediated processes that, over time, trended towards an increasingly pure end-member composition. Regionally, these data are consistent with a magmatic-origin followed by fluid-mediated remobilization of select phases at subsolidus conditions for the Adirondack IOA deposits.

Toward a mechanistic understanding of wettability alteration in reservoir rocks using silica nanoparticles

Traditional concepts of simple liquid spreading may not apply to nanoparticle-fluids. Most investigations pertaining to the wettability alteration of solid surfaces due to the presence of nanoparticles in the fluid are oversimplified, i.e. nanoparticles dispersed in DI-water and smooth, homogeneous, and clean surfaces have been used. From a practical enhanced oil recovery (EOR) point of view, the nanoparticles must be dispersed in either seawater or high salinity formation water containing diverse types and concentrations of ions. These ions interact with the electrostatic properties of the nanoparticles. Likewise, the oil phase may contain many surface active components like asphaltene and naphthenic acids which can interact with nanoparticles at oil-water and oil-rock interface. In reality, the rock sample is a heterogeneous, non-smooth, mixed-wet substrate with a diverse mineralogical composition. The electrical charge of minerals can vary when contacted with an ionic fluid. This can alter the electrostatic repulsion between substrate and nanoparticles and consequently the substrate can either attract or repel charged particles, including nanoparticles. Hence, the role of nanoparticles must be evaluated considering multicomponent complex fluids and real formation rock. Despite numerous reports regarding the wettability alteration of reservoir rock from oil-wet to water-wet by nanoparticles, some inherent limitations in the wettability alteration experiments prevent conclusions about the performance of nanoparticles in practical complex conditions. For instance, the wettability alteration by nanoparticles is often determined by contact angle measurements. In this method, the substrates are either aged with (immersed in) nanoparticle-fluids before conducting the experiments or contacted with nanoparticle-fluids before attachment of the oil droplet on the rock surface. Hence, in both cases, before initiating the contact angle measurements, the nanoparticles would already exist at the oil-rock interface possibly giving inaccurate measurements. The objective of this work is to investigate the mechanism of wettability alteration by silica nanoparticles pre-existing on the rock interface (conventional contact angle measurements) and using a new displacement contact angle method to better mimic the scenario of injecting a nanoparticle fluid into the reservoir already containing formation brine. The impact of pre-existing nanoparticles at the oil-rock interface (in the conventional contact angle measurements) on the contact angle measurements are examined for simple (n-decane, NaCl brine, and pure substrates) and complex (crude oil, seawater, and reservoir rock) systems on various wetting conditions of substrates (water-wet and oil-wet). The nanoparticles are dispersed in seawater using our H+ protected method [1]. Then, the effect of surface and nanoparticle charge on the contact angle is evaluated by adjusting the aqueous phase salinity. We also differentiate between the disjoining pressure mechanism and diffusion of silica nanoparticles through the oil phase by testing the attachment of nanoparticles on the rock surface.

Predicting the phase behavior of hydrogen in NaCl brines by molecular simulation for geological applications

Hydrogen is targeted to have a significant influence on the energy mix in the upcoming years. Its underground injection is an efficient solution for large-scale and long-term storage. Furthermore, natural hydrogen emissions have been proven in several locations of the world, and the potential underground accumulations constitute exciting carbon-free energy sources. In this context, comprehensive models are necessary to better constrain hydrogen behavior in geological formations. In particular, solubility in brines is a key-parameter, as it directly impacts hydrogen reactivity and migration in porous media. In this work, Monte Carlo simulations have been carried out to generate new simulated data of hydrogen solubility in aqueous NaCl solutions in temperature and salinity ranges of interest for geological applications, and for which no experimental data are currently available. For these simulations, molecular models have been selected for hydrogen, water and Na+and Cl−to reproduce phase properties of pure components and brine densities. To model solvent-solutes and solutes-solutes interactions, it was shown that the Lorentz-Berthelot mixing rules with a constant interaction binary parameter are the most appropriate to reproduce the experimental hydrogen Henry constants in salted water. With this force field, simulation results match measured solubilities with an average deviation of 6%. Additionally, simulation reproduced the expected behaviors of the H2O + H2 + NaCl system, such as the salting-out effect, a minimum hydrogen solubility close to 57 °C, and a decrease of the Henry constant with increasing temperature. The force field was then used in extrapolation to determine hydrogen Henry constants for temperatures up to 300 °C and salinities up to 2 mol/kgH2O. Using the experimental measures and these new simulated data generated by molecular simulation, a binary interaction parameter of the Soreide and Whiston equation of state has been fitted. The obtained model allows fast and reliable phase equilibrium calculations, and it was applied to illustrative cases relevant for hydrogen geological storage or H2natural emissions.

The correlation of the steady-state gas/water relative permeabilities of porous media with gas and water capillary numbers

The steady-state gas,krg, and water,krw, relative permeabilities are measured with experiments of the simultaneous flow, at varying flow rates, of nitrogen and brine (aqueous solution of NaCl brine) on a homogeneous sand column. Two differential pressure transducers are used to measure the pressure drop across each phase, and six ring electrodes are used to measure the electrical resistance across five segments of the sand column. The electrical resistances are converted to water saturations with the aid of the Archie equation for resistivity index. Bothkrwandkrgare regarded as power functions of water, Caw, and gas, Cag, capillary numbers, the exponents of which are estimated with non-linear fitting to the experimental datasets. An analogous power law is used to express water saturation as a function of Caw, and Cag. In agreement to earlier studies, it seems that the two-phase flow regime is dominated by connected pathway flow and disconnected ganglia dynamics for the wetting fluid (brine), and only disconnected ganglia dynamics for the non-wetting fluid (gas). The water saturation is insensitive to changes of water and gas capillary numbers. Each relative permeability is affected by both water and gas capillary numbers, with the water relative permeability being a strong function of water capillary number and gas relative permeability depending strongly on the gas capillary number. The slope of the water relative permeability curve for a gas/water system is much higher than that of an oil/water system, and the slope of the gas relative permeability is lower than that of an oil/water system.

Effect of boiling on the acidity of hydrothermal solutions

Natural seawater and H2O–NaCl solutions were equilibrated along the two-phase (liquid–vapor) curves between 150 and 390 °C to re-examine the effect of liquid–vapor phase separation on element fractionations between saline brines and vapor phases. The experimental setup allows vapor and brine to be sampled separately at in situ P–T conditions. Experimental vapor pressure is constrained by temperature and the electrolyte concentration of the brines. With increasing temperature, dissolved electrolytes react with increasing temperature to hydroxides and HCl, in both seawater and H2O–NaCl solutions. The extent of hydrolysis is more pronounced in seawater than in H2O–NaCl solutions because seawater contains, in addition to NaCl, a range of other electrolytes capable of hydrolysis. Associated HCl has a great affinity to fractionate to the vapor phase when phase separation occurs. At 365 °C, halite-saturated vapor phases have a pH25 (pH after condensation to 25 °C) of 1.8 (seawater) and 2.8 (H2O–NaCl brines). Our data suggest that boiling of hydrothermal solutions followed by mixing of vapor condensates with seawater can impose pH25 values as acidic as the most acidic natural hydrothermal solutions vented on the ocean floor.

The effect of saturation conditions on fracture performance of different soundless cracking demolition agents (SCDAs) in geological reservoir rock formations

Fracture stimulation using soundless cracking demolition agents (SCDAs) is a potential alternative technique to induce high-density fractures in sedimentary reservoir-rock as an auxiliary technique to improve the efficiency of enhanced oil and gas recovery efficiencies. However, to date, its application has been limited to fracture stimulation in dry rock masses. Therefore, using modified SCDAs, which can be used for underwater rock fracturing, a series of experiments was conducted to investigate the fracturing performance of SCDAs in saturated rock masses. 18 coarse-grained sandstone specimens were saturated in water, oil, and NaCl brine and fractured using three different SCDA types: a standard SCDA (S1), and two modified for underwater application (S2) and accelerated reaction rate (S3). Then, the fractured samples were scanned in the Australian Synchrotron, and the fractures were quantified using Avizo 9.0.1. The fracture initiation time and the total fracture network length and volume were found to be dependent on the saturated pore fluid of rock. Water saturation of samples increased the fracture initiation time by 16.5%, 24.1% and 13.68% for S1, S2, and S3 type SCDAs respectively and reduced the fracturing potential of SCDA by 59.5%, 32.49% and 66.67% compared to dry samples. This reduction was less apparent in oil-saturated samples as the high pore fluid viscosity of oil-saturated samples aid fracturing, which is explained by the Poiseuille equation. Increasing salinity in the saturation fluid from 0% to 12.5% was favourable for the fracturing efficiency of SCDAs because of the formation of CaCl2 in the pore fluid, which accelerates the reaction of SCDA. Fracture orientation also changed depending on the saturation fluid, which was again governed by the variation in reaction rate in SCDAs under different saturation conditions.

An Experimental Study of Emulsion Phase Behavior and Viscosity for Athabasca Bitumen/Diethylamine/Brine Mixtures

Summary Water is the most dominant component in steam-based oil-recovery methods, such as steam-assisted gravity drainage (SAGD). The central question that motivated this research is whether in-situ bitumen transport in SAGD can be substantially enhanced by generating oil-in-water emulsion, in which the water-continuous phase acts as an effective bitumen carrier. As part of the initial stage of the research project, the main objective of this paper is to present the ability of organic alkali to form oil-in-water emulsions that are substantially less viscous than the original bitumen. Diethylamine (DEA) was used as the organic alkali in this research. Experimental studies were conducted for emulsion phase behavior and viscosity for mixtures of Athabasca bitumen, DEA, and sodium chloride (NaCl) brine. Experimental variables included brine salinity, alkali concentration, water/oil ratio (WOR), temperature, and sample-aging time. The phase-behavior study indicated that conditions conducive to oil-in-water emulsions are low alkali concentrations at salinities less than 1,000 ppm. For example, a single phase of oil-in-water emulsion was observed for 0.5, 1.0, 2.0, and 5.0 wt% DEA with WOR of 7:3 with no NaCl. The emulsion for 0.5 wt% DEA, 1,000 ppm NaCl, and WOR of 7:3 was a single-phase oil-in-water emulsion at temperatures up to 403 K at 35 bar. At lower temperatures, 323 and 298 K, flocculation of emulsions in these samples resulted in the separation between the bitumen-rich and water-rich oil-in-water emulsions. However, essentially all bitumen content was measured from the bitumen-rich oil-in-water emulsion. The oil contents in these emulsions were more than 70 vol% at 298 K and 57 vol% at 323 K. Viscosities of these oil-in-water emulsions ranged between 85 and 115 cp at 1.0 seconds–1 and between 31 and 34 cp at 10.0 seconds–1, at 323 K. At 298 K, they ranged between 105 and 250 cp at 1.0 seconds–1 and between 48 and 74 cp at 10.0 seconds–1. Results in this research show that, compared with the original bitumen, bitumen-rich oil-in-water emulsions were less viscous by three to four orders of magnitude at 298 K, and less viscous by two orders of magnitude at 323 K.

Geochemistry of brines in Vendian deposits of the Siberian platform

Results of the geochemical studies on natural brines from regional Vendian reservoirs (Lower-Danilov, Tira, Nepa and Vilyuchan) of the Siberian platform are presented. TDS values of the studied groundwaters and brines range from 17.3 to 583.1 g/dm3, where brines with salinity 280 – 400 g/dm3 are predominant. Brines identified within the Ayan, Bratsk, Balaganka, Upper Chona, Shamanka and other areas, have the highest TDS values.The most widely spread brines belong to five chemical types of Cl Na to Cl Ca composition. TDS concentrations vary widely from 197 to 580 g/dm3 in the Lower Danilov and Tira horizons, and from 170 to 470 g/dm3 in the lower-sitting Nepa and Vilyuchan horizons. Na Cl brines whose TDS concentration reaches the halite precipitation phase should be assigned to infiltration-formed brines on account of salt rock leaching, while strongly metamorphosed brines (S > 300) mostly of Cl and Ca Cl Ca-Mg composition – to sedimentogenic type accounting for those descended from Cambrian salt-bearing deposits, thereby largely explaining the phenomenon of inverse hydrogeochemical zonality in subsalt horizons. The third genetic type, of Cl Ca-Na composition, is rooted in the processes of mixing sodium and calcium types of brines.

Analysis of the use of environmentally friendly corrosion inhibitors for mild steel in a carbon dioxide saturated chloride solution via experimental design

In the oil and gas industry, carbon dioxide (CO2) gas dissolved in produced fluids can cause both general and localized corrosion of carbon steel pipelines due to the speciation of carbonic acid. To mitigate corrosion, the injection of inhibitors into the production fluid is one of the most commonly used methods. However, recent changes in regulations has resulted in a requirement for the development of new corrosion inhibitors that conform to European regulations. This paper presents a full two‐level factorial experimental design approach to study individual effects of environmentally friendly classed inhibitor components (phosphate ester, imidazoline, and quaternary amine derivatives) as combined inhibitors and their interactive effects on carbon steel corrosion processes in CO2‐saturated 3.5 wt.% NaCl brine. Through the application of in situ electrochemical monitoring, post‐test interferometry, and scanning electron microscopy (SEM) it was possible to determine the influence of each component within the blends and their effect on both general and localized corrosion. Based on 24 h experiments, the phosphate ester derivative reduced general corrosion rate in all blends; imidazoline derivatives reduced the uniform corrosion rate only when it was at the high level in the blend; and the quaternary amine derivative promoted pitting on the surface.

Radiolytic H2 production on Noachian Mars: Implications for habitability and atmospheric warming

Protected from harmful radiation, subfreezing temperatures, and low pressures, subsurface rock-hosted habitats provide potentially sustainable refugia for microbial ecosystems inside small rocky planets, such as Mars. For many chemolithotrophic communities on Earth, water–rock alteration reactions have been shown to produce the key electron donors and acceptors necessary to sustain microbial life on geologic timescales. Here we quantitatively demonstrate that radiolysis likely generated concentrations of dissolved H2 capable of sustaining microbial communities in the subsurface of Noachian Mars (3.7–4.1 Gyr ago). When considering an environment with H2O groundwater, dissolved H2 concentrations reach up to ∼55 mM in a cold early Mars climate scenario and ∼35 mM in a warm early Mars climate scenario; whereas when considering an environment with eutectic NaCl brine groundwater, dissolved H2 concentrations reach up to ∼85 mM in a cold early Mars climate scenario and ∼45 mM in a warm early Mars climate scenario. Specifically within the subsurface habitable zone, dissolved H2 concentrations range from ∼50–55 mM for a cold climate scenario with H2O groundwater. For a warm climate scenario with H2O groundwater, dissolved H2 concentrations within the subsurface habitable zone range from ∼1–30 mM. For a cold climate scenario with eutectic NaCl brine groundwater, dissolved H2 concentrations within the subsurface habitable zone range from ∼65–85 mM. For a warm climate scenario with eutectic NaCl brine groundwater, dissolved H2 concentrations within the subsurface habitable zone range from ∼1-40 mM. Radiolysis likely produced [1.3–4.8] × 1010 moles H2 per year globally during the Noachian depending on the assumed porosity and groundwater composition. Radiolytic H2, and CH4 derived from radiolytic H2, can be locked in hybrid clathrate hydrates within the cryosphere and released by large impacts, volcanism, or obliquity variations. This process could warm the Noachian climate to above-freezing temperatures, and we predict that ∼1–8 warming events would be possible during the Noachian and Hesperian solely from radiolytically produced H2. We demonstrate that the region immediately beneath the cryosphere, termed the subcryospheric highly-fractured zone (SHZ), likely contained dissolved H2 concentrations and temperatures suitable for life regardless of the background climate scenario, making it the most consistently habitable environment on ancient Mars in terms of reductant availability. Material from this zone can be exposed by faulting and in the ejecta and uplifts of impacts, making the SHZ a crucial astrobiological target for testing the subsurface biosphere hypothesis.

Integration of membrane distillation (MD) and solid hollow fiber cooling crystallization (SHFCC) systems for simultaneous production of water and salt crystals

A novel hybrid system of integrating membrane distillation (MD) and solid hollow fiber cooling crystallization (SHFCC) has been successfully developed for simultaneous production of fresh water and inorganic salt crystals from NaCl brine solutions. Porous PVDF hollow fiber membranes consisting of PTFE particles were spun for the MD subsystem, while non-porous PVDF hollow fibers were fabricated as heat exchangers for the SHFCC subsystem. To optimize the operation parameters, the Taguchi's method was utilized for experiment design including three key factors; namely, feed temperature (Tf), distillated amount (Wd) and water amount to wash away the scallant (Ww). Several response factors were experimentally investigated and their signal-to-noise ratios of each response were calculated to identify the optimal settings of control factors. As a result, the best combined parameters to maximize the crystal harvest took place at Wd = 14 g and Tf = 50 °C. Narrowly distributed NaCl crystals with a small mean size of 35–45 µm were successfully generated by the hybrid system, and a relatively long-term MD-SHFCC operation of 15 cycles was conducted to verify the system stability and feasibility. The 15-cycle experiments exhibited an impressive average MD water flux of about 8 kg/m2 h and continuous production of distillate water with a high purity (a NaCl concentration of 0.01 g/L) and NaCl salt crystals with a yield of 64 g per kg feed.

Rheo-NMR of transient and steady state shear banding under shear startup

In this work, shear band formation following shear startup as a function of flow protocol is investigated in the wormlike micelle (WLM) system of 6 wt. % cetylpyridinium chloride and sodium salicylate in 0.5M NaCl brine in a Couette Rheo-nuclear magnetic resonance (NMR) shear cell. Many applications using WLM solutions occur under time dependent conditions; however, shear banding under time dependent flow protocols is not as well characterized. 1D velocity profiles across the 1 mm fluid gap are recorded every 1 s after shear startup using Rheo-NMR velocimetry and used to evaluate shear banding characteristics, including the shear rates in the low and high shear band, the interface position, and the apparent wall slip as a function of time. The velocity, and therefore the shear banding characteristics, exhibits large temporal fluctuations following an abrupt startup to 12 s−1. Data were decomposed into an average and fluctuation about the average in order to extract the characteristic time scales for the transition of the flow from transient to steady state. In addition, the Fourier transform of time autocorrelation functions was used to quantify the fluctuation frequencies themselves, which are related to the apparent slip at the inner rotating wall and the presence of flow instabilities. This analysis has the potential to allow a 1D measurement to provide information about the 3D flow. Shear startup experiments were also performed for flow protocols with and without preshear. Preshear resulted in different magnitudes of the timescales and a shift in the frequencies of the fluctuation of all shear banding characteristics, emphasizing the importance of shear history on the flow behavior of these WLM solutions.

Novel Alkyl-Amine Surfactants for CO2 Emulsion Assisted Enhanced Oil Recovery

Novel CO2-soluble surfactants are designed for generating stable CO2 emulsion/foam at high temperature (110 °C) and high salinity (220 g/L NaCl). The novel surfactants only consist of alkyl chains and amine heads without any fluorine, silicon, or poly alkyl-oxide groups and outperform the surfactants in literature regarding the solubility, thermal stability, and emulsifying ability in harsh conditions. 0.2 wt % of the novel surfactants are soluble in 220 g/L NaCl brine at pH ≤ 8 from 20 to 120 °C and are soluble in CO2 at high temperature (110 °C) and relatively low pressure (91 bar). The surfactants are thermally stable at 110 °C and pH = 4 under anaerobic conditions. Strong CO2 emulsion can be readily generated in bulk and in porous media at 25–110 °C and 150 bar. Unlike the common surfactants in literature, the performance of the novel surfactants can be profoundly enhanced by salinity and temperature. The strategy for designing these novel molecules and tuning the surfactant formulation for emulsion-a...

Clathrate hydrate formation in NaCl and MgCl2 brines at low pressure conditions

Hydrate-based desalination (HBD) has been developed to obtain fresh water from seawater in an economic and environmental sustainable manner. As a low-pressure hydrate former for the HBD process, chlorodifluoromethane (R22) hydrates were formed in the pressure range of 1–6 bar under brine environments, aqueous NaCl and MgCl2 solutions. Synchrotron X-ray diffraction and Raman spectroscopy measurements revealed that the R22 hydrates formed with NaCl and MgCl2 show structure I and enclathration of R22 molecules into the large cages. These results also confirmed that the salt ions cannot be encaged in the gas hydrate framework, reflecting the ion exclusion behavior for HBD above the eutectic of water and hydrated salts. The formation kinetics of R22 clathrate hydrate in the presence of salts show that both the initial growth rate and pressure drop of the R22 hydrates heavily depend on the salinity of aqueous solutions. A new theoretical approach adopting the transient time-dependent apparent rate constant of hydrate formation with salts was proposed to predict the formation kinetics of R22 hydrates under brine environments, which was in good agreements with the experimental results. These results provide good information for separating ionic compounds from aqueous solutions by hydrate-based separation processes.

Origin of saline springs in Yanjing, Tibet: Hydrochemical and isotopic characteristics

The Yanjing region of Tibet is famous for its saline springs and salt deposits. It is located between the Qiangtang and Lanping-Simao basins that also have saline springs and salt-bearing strata. The hydrochemical and stable water and C-13 isotopes of saline springs, hot springs, surface waters and rocks from Yanjing are reported and compared with data from those basins. Results indicate that 1) the saline springs are high TDS, Na-Cl type waters and brines with unusually high K contents that indicate interaction with evaporite minerals; 2) for the saline springs from Yanjing, the circulation depth is moderate, 3–4 km, and the Late-Triassic strata (T3b) are considered as the salt bearing strata and the aquifer; 3) the hot springs are of two distinct geochemical types, Na·Ca-HCO3 type waters with higher temperature, and Na·Ca-SO4 waters with somewhat higher TDS content; and 4) all waters are of meteoric origin or have a large meteoric component. Furthermore, the lithofacies' evolution of the salt-bearing belt from Lanping-Simao to Qiangtang, and the affinities of Yanjing with these two basins, are also discussed, and it is concluded that the saline water in Yanjing has a good utilization prospect with regard to sylvite.