Brine System Research Articles

Nano-colloid based suspensions and emulsions used as means for enhanced oil recovery

Aqueous solutions of polyphenols extracted from parsley leaves are mixed with solution of ferric chloride hexahydrate to synthesize suspensions of polyphenol-coated iron oxide nanoparticles, which are then used to prepare Pickering oil (n-decane)-in water emulsions. The performance of the nano-colloid suspensions and emulsions as agents of enhanced oil recovery (EOR) is assessed with secondary imbibition tests performed under constant flow rate on a glass-etched pore network, after a drainage / primary imbibition cycle for paraffin oil / brine (0.25M NaCl solution) system. The transient changes of the fluid saturation profile along with the pressure drop across the porous medium are recorded. Comparative analysis of the oil recovery efficiency attained with nano-colloid suspensions of varying iron concentration, and Pickering emulsion, enables us to classify them, and select the most efficient ones for further studies.

Applications and limitations of portable density meter measurements of Na-Ca-Mg-K-Cl-SO4 brines

Knowledge of brine density and mineral saturation states under different temperatures contributes to understanding Earth systems, including dissolution and crystallization of chemical sediments, mixing water bodies with variable density, and mineral resource development and evolution. However, these interpretations often rely on geochemical measurements with low accuracies at high salinities. Here, we test the utility of density measurments to advance understanding of brine geochemistry. We demonstrate the accuracy and limits of determining a brine's density and halite saturation state at multiple temperatures with rapid and relatively inexpensive portable density meter measurements. Density measurements at different temperatures are used to create samples' equations of state, which are used to extrapolate measurements. This methodology presents multiple opportunities. We use brine samples from around the world to show that density and equation of state data provide semi-quantitative information about sample composition and temperature-sensitive mineral precipitation. Importantly, density measurements can be used to evaluate error-prone geochemical measurements. We illustrate applications with brine samples from the Bonneville Salt Flats, a landscape in Utah, USA, that is valued for mineral resources and recreation opportunities. We developed system-scale equations of state for these saline pan samples and their halite-saturated counterparts. We evaluated methodological limitations with duplication tests and by determining if diurnal fluctuations in salinity and halite saturation in a shallow pool's brine and shallow groundwater in contact with a halite crust were detectable. Average daily changes in halite saturation of shallow pool brine of approximately 3 kg m−3 were clearly detected, while diurnal halite saturation fluctuations in the shallow halite crust brine of 0.4 to 0.7 kg m−3 were near method limits. Because of their accuracy, low cost, and applications, portable density meter measurements of brines are invaluable in studying brine systems.

An Overview of the Oil+Brine Two-Phase System in the Presence of Carbon Dioxide, Methane, and Their Mixture

An overview of the molecular simulation studies of the oil+brine two-phase system in the presence of CO2, CH4, and their mixture at geological conditions is presented. The simulation results agreed well with the experimental results and the density gradient theory predictions on the basis of the cubic–plus–association equation of state (CPA EoS) (withDebye–Hückel electrostatic term) and the perturbed chain statistical associating fluid theory (PC-SAFT) EoS. The interfacial tension (IFT) of the alkane+H2O system showed almost a linear increase with an increasing number of carbon atoms in the alkane molecule. These IFTs are approximately equal for linear, branched, and cyclic alkanes. Here, the negative surface excess of the alkanes might explain the increase in the IFTs with an increase in the pressure. The surface excesses of the alkanes increased with decreasing temperature. This may explain the decrease of the slopes in the IFT versus pressure plot with a decrease in the temperature. The IFT behavior of the alkane+water+CH4/CO2 system was found to be similar to that observed for the alkane+water system. The addition of CO2 had a more significant influence on the IFT than the addition of CH4. Here, CH4 and CO2 exhibited a positive surface excess. The negative surface excess of the salt ions probably explains the increase in the IFTs of the alkane+brine system with increasing salt content. The solubilities of CH4 and/or CO2 in the H2O-rich phase of the alkane+brine+CH4/CO2 system increased with decreasing salt content (salting-out effect). The IFT of the aromatic hydrocarbon+H2O system is much lower than that of the alkane+H2O system. The surface excess followed the order o-xylene > ethylbenzene > toluene > benzene for the aromatic hydrocarbon+H2O system. This trend has a direct correlation with the aromatic–aromatic interaction.

Hydrogeochemical and isotopic signatures elucidate deep subsurface hypersaline brine formation through radiolysis driven water-rock interaction

Geochemical and isotopic fluid signatures from a 2.9–3.2 km deep, 45–55 °C temperature, hypersaline brine from Moab Khotsong gold and uranium mine in the Witwatersrand Basin of South Africa were combined with radiolytic and water–rock isotopic exchange models to delineate brine evolution over geologic time, and to explore brine conditions for habitability. The Moab Khotsong brines were hypersaline (Ca-Na-Cl) with 215–246 g/L TDS, and Cl− concentrations up to 4 mol/L suggesting their position as a hypersaline end-member significantly more saline than any previously sampled Witwatersrand Basin fluids. The brines revealed low DIC (∼0.266–∼1.07 mmol/L) with high (∼8.49–∼23.6 mmol/L) DOC pools, and several reduced gaseous species (up to 46 % by volume H2) despite microoxic conditions (Eh = 135–161 mV). Alpha particle radiolysis of water to H2, H2O2, and O2 along with anhydrous-silicate-to-clay alteration reactions predicted 4 mol/L Cl− brine concentration and deuterium enrichment in the fracture waters over a period > 1.00 Ga, consistent with previously reported 40Ar noble gas-derived residence times of 1.20 Ga for this system. In addition, radiolytic production of 7–26 nmol/(L × yr) H2, 3–11 nmol/(L × yr) O2, and 1–8 nmol/(L × yr) H2O2 was predicted for 1–100μ g/g 238U dosage scenarios, supporting radiolysis as a significant source of H2 and oxidant species to deep brines over time that are available to a low biomass system (102–103 cells/mL). The host rock lithology was predominately Archaean quartzite, with minerals exposed on fracture surfaces that included calcite, pyrite, and chlorite. Signatures of δ18Ocalcite, δ13Ccalcite, Δ33Spyrite,δ34Spyrite and 87Sr/86Sr obtained from secondary ion mass spectrometry (SIMS) microanalyses suggest several discrete fluid events as the basin cooled from peak greenschist conditions to equilibrium with present-day brine temperatures. The brine physiochemistry, geochemistry, and cellular abundances were significantly different from those of a younger, shallower, low salinity dolomitic fluid in the same mine, and both were different from the mine service water. These results indicate the discovery of one of few long-isolated systems that supports subsurface brine formation via extended water–rock interaction, and an example of a subsurface brine system where abiotic geochemistry may support a low biomass microbial community.

Robust graphene oxide hybrid membrane for high-efficiency emulsion separation in high-salt brine systems

Exploring robust membrane with special wettability is of great significance for efficient emulsion separation under harsh environment. Herein, the multifunctional GO@PDA@Ag/PES membrane with rough structure was successfully constructed, which exhibited remarkable emulsion separation and mechanochemical performances in high-salt brine systems. Results showed the separation efficiency for surfactant stabled TBP-in-brine emulsion and actual solvent extraction emulsion can reach up to 99.6 % and 95.2 %, respectively. The GO@PDA@Ag/PES membrane displayed excellent structural stability, which could maintain the superwettability and superhigh separation efficiency even corrosion in acid, alkali and salt environment for 14 days. Surprisingly, the GO@PDA@Ag/PES membrane can withstand 2000 times folds, 100 times abrasion, and 20 times cycles without separation performances reduced. The robust mechanochemical properties can be ascribed to the covalent bond bridged structure crosslinked by polydopamine, and the non-covalent interactions between GO and PES. Importantly, Ag nanoparticles on the surface and embedded in membrane were investigated by XPS, which indicated the different chemical speciation. The hybrid membrane with excellent oil-in-brine emulsion separation performance, corrosion resistance and mechanical stability will have broad prospects in the field of high-salt lake industry.

Simultaneous Prediction of Equilibrium, Interfacial, and Transport Properties of CO2-Brine Systems Using Molecular Dynamics Simulation: Applications to CO2 Storage

This study aims to provide accurate simultaneous predictions of crucial properties affecting CO2 storage in saline aquifers with deep microstructural insights using comprehensive molecular dynamics (MD) simulations under actual operating conditions ranges. We investigated the effects of pressure, temperature, and salinity on mutual solubility, interfacial tension (IFT), density, and viscosity of a CO2-brine system over the temperature range of 323.15–393.15 K, pressures up to 30 MPa, and salinity range of 0.98–2.97 mol/kg. Brine was resembled by employing different brine systems like actual reservoirs, including mixed electrolyte solutions containing monovalent and divalent ions. MD model configurations and force fields were validated by experimental data of a CO2-water/NaCl aqueous solution. The maximum average absolute deviations for the solubility, density, and IFT were 5.50, 6.95, and 7.136%, respectively. The simulation results indicated that mutual solubilities of CO2 and water in the CO2-NaCl + KCl solution system are higher than those of CO2-NaCl + CaCl2, while for IFT, the opposite trend is observed. Unlike pressure, salt concentration variations result in considerable density and viscosity changes for all systems. The maximum density and viscosity values are obtained for the brine-containing divalent cations. This study gives insight into the storage process and relates the microstructure effects to solubility, IFT, and viscosity of CO2-brine systems using a single MD model.

The effect of formate brines on the emulsification of ionic, non-ionic, and enzymatic surfactants

Environmental concerns on contamination of subsurface porous media by toxic chemicals have motivated the petroleum industry to replace them with environmentally sustainable (green) and biodegradable alternatives. Green surfactants have emerged such as sugar, enzymatic, and microbial based surfactants. However, their emulsification with different oils and salinity conditions is unknown. In this study, different oil and brine systems are tested to measure interfacial properties, rheology and emulsification of Coco Glucoside (CG), a sugar-derived surfactant; and Greenzyme (GZ), an enzymatic-environmentally friendly surfactant. Emulsification with light and medium crude oil in the presence of sodium chloride and sodium formate brines gave similar results with 10–20 μm average droplet size. However, medium-heavy crude oil with potassium formate produced 98 vol% emulsion with 3–6 μm average droplet size. Most of the emulsions demonstrated a shear thinning behaviour apart from emulsions resulting from Coco Glucoside and medium-heavy crude oil in which a clear Newtonian behaviour was observed.

Insights on CO2 Hydrate Formation and Dissociation Kinetics of Amino Acids in a Brine Solution

CO2 sequestration as hydrates has captured enormous research interest in recent years due to its high storage capacity. However, the slow hydrate formation kinetics poses a strong challenge in its applicability and urges the need for additives (kinetic promoters) to accelerate the hydrate formation kinetics. This study investigates the performance of amino acid solutions in brine (3.3 wt % NaCl) on CO2 hydrate formation and dissociation kinetics. The kinetics of hydrate formation and dissociation was evaluated at varying concentrations (0.2, 0.5, 0.8, and 1 wt %) of l-methionine, l-isoleucine, and l-threonine solutions in brine using a high-pressure hydrate reactor at 4 MPa, and formation temperature of 274.15 K, and a dissociation temperature of 277.15 K. CO2 hydrate formation and dissociation experiments were also conducted using sodium dodecyl sulfate (SDS), pure water, and brine systems as standards for comparison. The findings show that all the studied amino acid systems show hydrate inhibition as compared to the pure water system with 35–41% reduction in CO2 storage capacity. Further, l-methionine exhibited an optimum performance with a slight promotional effect at 0.2 wt % with the lowest induction time (35.6 min) and the highest CO2 uptake (42.08 mol/mmol) among the studied amino acid systems. However, comparing l-methionine with SDS shows less induction time for SDS (28.48 min), indicating kinetic promotion of SDS over l-methionine in the presence of brine. The dissociation kinetics findings reveal the lowest dissociation rate for l-methionine and a prolonged time of CO2 release compared to l-threonine and l-isoleucine, respectively. Nevertheless, all the considered amino acid systems exhibit more inhibition or stability for hydrate dissociation as compared to the pure water system. However, compared to SDS and brine systems, the amino acids l-methionine and l-isoleucine show a slight promotion effect, unlike l-threonine which exhibits strong kinetic inhibition. The results thus suggest that amino acid solutions in brine stabilize hydrate dissociation; however, the CO2 hydrate formation inhibition in brine is quite discouraging for CO2 storage purposes. Instead, applying amino acids in flow assurance could be an additional advantage due to the presence of brine in practical reservoir fluids during production.

Buffer Models for pH and Acid Changes Occurring in Cucumber Juice Fermented with Lactiplantibacillus pentosus and Leuconostoc mesenteroides

The pH changes that occur during the fermentation of vegetables by lactic acid bacteria depend on the production of weak acids and on the buffering of the fermentation medium. Undefined buffering components of fermentation media make estimates of pH from acid production difficult. The objective of this research was to develop buffer models for a model cucumber fermentation brine system linking pH changes to acid concentrations. A novel titration method was used to measure buffer capacity in cucumber juice medium made from three grades of pickling cucumbers based on diameter. Fermentation of juice made from cucumbers of different sizes resulted in differences in fermentation biochemistry. The results of modeling indicated that the pH of the medium after 24 and 48 h of fermentation by heterolactic Leuconostoc mesenteroides and homolactic Lactiplantibacillus pentosus could be predicted from acid concentrations based on the measured buffer capacity of the corresponding unfermented medium. The differences for all observed and predicted pH values of the fermentation samples, based on measured acid concentrations, had a root mean square error of 0.064 pH units. The buffer models included a quantitative measure of the effect on pH of the malolactic reaction caused by the lactic acid bacteria. These models may have application for assessing the influence of a variety of lactic acid bacteria buffering reactions on pH and fermentation ecology by linking pH to fermentation acid concentrations.

Recovery of lithium from salt‐lake brine by liquid–liquid extraction using TBP‐FeCl3 based mixture solvent

AbstractIn this study, a complete cyclic process was developed for the lithium extraction from high‐concentration salt‐lake brine by using a high flash point, low water solubility, and low toxicity diluent mixed with the TBP‐FeCl3‐based organic solvent. The process was composed of four sections, including extraction, scrubbing, stripping, and regeneration. The optimal conditions for each section were determined first. Then, a 13‐stage cyclic extraction process was designed and validated experimentally for the high lithium concentration brine, which reached 8.612 g/L. By using the diluent at the optimized conditions, the overall recovery of lithium was higher than 96%. The stripping liquid contained 38.87 g/L Li+, while all the ratios of impurities of sodium, potassium, and magnesium to lithium were less than 0.1. The aims of enrichment and purification of Li+ from the complicated brine system were achieved by the developed extraction process with little Fe loss, which provided the technical support for the development of the salt‐lake lithium resource.

Volumetric properties of the binary aqueous system lithium metaborate from 283.15 to 363.15 K and 101 kPa: Experimental and thermodynamic model

Volume properties of salt lake solution are of great significance in constructing the thermodynamic model of the salt lake brine system and promote the comprehensive utilization of salt lake resources. In this paper, LiBO2(aq) densities from 0.08083 to 0.75731 mol·kg−1 were determined experimentally at 5 K temperature intervals from 283.15 to 363.15 K and 101 kPa using a precise digital vibrating-tube densimeter. The apparent molar volume (Vϕ) and the thermal expansion coefficient (α) were derived based on the experimental data. The 3D diagrams of the apparent molar volume and the thermal expansion coefficient against molality and temperature were demonstrated. According to the Pitzer thermodynamic model of apparent molar volume of electrolyte, the Pitzer single-salt parameters βMX(0)ν, βMX(1)ν, βMX(2)ν,CMXν of LiB(OH)4 and their temperature-dependence coefficients (p = Co + C1lnT/298.15 + C2(T-298.15) + C3/(620-T) + C4/(T-227) were established for the first time. A comparison between the predictive and experimental data indicates that the experimental data and the parameters obtained in this work are reliable.

Effects of Various Solvents on Adsorption of Organics for Porous and Nonporous Quartz/CO2/Brine Systems: Implications for CO2 Geo-Storage

The underground geo-storage of carbon dioxide (CO2) is an essential component of the carbon capture and sequestration value chain. The success of CO2 containment depends on the wetting state of the rock, which controls the mechanism of fluid flow and distribution. The presence of organic acids in the storage formation introduces a considerable effect on the wettability of the rock/CO2/brine system under various temperature and pressure conditions. Despite the previous studies on this topic, the impact of the substrate pores, the rock surface roughness, and the solvents used to prepare the organic acid solution under various temperatures and pressures has not yet been elucidated. In the present study, the contact angles of non-porous quartz and porous Fontainebleau quartz are measured in CO2/brine systems at various pressures of 0.1–20 MPa and temperatures of 298 and 323 K. In addition, various solvents are used to prepare the stearic acid solution in order to assess their influence on the adsorption of organics for porous and non-porous quartz/CO2/brine systems. The results clearly indicate that n-decane is the most effective solvent for solubilizing the stearic acid to attain full wettability of the substrate by CO2 due to its polar compatibility with the stearic acid. Generally, the porous aged Fontainebleau quartz exhibits higher contact angles than the aged non-porous quartz at higher pressures, and the unaged Fontainebleau surfaces demonstrate water wettability, with a wide range of advancing and receding contact angles of less than 90°. However, when the pressure is increased to 15 and 20 MPa in the CO2/brine system, the contact angles of the Fontainebleau quartz are higher than those of pure quartz. These results suggest that the surface roughness of the rock merely amplifies the inherent surface chemistry and original wettability of the rock if surface conditions are hydrophobic.

Impact of Brine on Disjoining Pressure and Rock Wettability of Oil, Brine, and Mineral Systems

The alteration of rock wettability is essential for improving the efficiency of low-salinity water flooding. However, the fundamental understanding of this process remains unclear. In this paper, an extended Derjguin–Landau–Verwey–Overbeek (DLVO) theoretical model was applied to study the effects of cation types, brine concentrations, and mineral types on rock wettability in an oil–brine system. The zeta potential was measured to analyze the electric double layer. The oil–rock contact angles were tested to evaluate the wettability. The disjoining pressure was also estimated to analyze the rock wettability changes. The divalent cation showed a greater ability to compress the electric double layer. The lower concentrations of cations led to a thicker water film, promoting the detachment of oil from the rock surface. Clay minerals showed a greater impact on the wettability of rocks than quartz. This study improves the fundamental understandings of alteration of wettability in brine, oil, and rock systems and elucidates the mechanisms of disjoining pressure effects on low-salinity water flooding while shedding some light on improving the performance of low-salinity water flooding.

Carbonated Water Injection in Oil-Wet Carbonate Rock Samples: A Pore-Scale Experimental Investigation of the Effect of Brine Composition

Research into the application of carbonated water injection (CWI) for oil recovery has primarily focused on sandstone reservoirs. Therefore, characteristic pore-scale mechanisms that principally depend on the injected brine composition in oil-wet carbonates are still poorly understood. This study uses a pore-scale approach that incorporates core flooding with microcomputed tomography (micro-CT) imaging to investigate underlying mechanisms during CWI with different brine compositions and salinities in oil-wet carbonate rocks. The results reveal that mere carbonation of brine deficient in potential determining ions (PDIs)─Ca2+, Mg2+, and SO42–─does not improve the oil displacement efficiency in oil-wet carbonates. Particularly, certain pore-scale phenomena─wettability reversal and interfacial tension (IFT) reduction─that control the oil displacement efficiency do not significantly change toward desirable states. Extant oil-wet conditions were maintained as we observed a marginal reduction in the average in situ contact angle. In addition, the equilibrium oil–brine IFT was similar to that of oil–brine systems characterized by high brine salinity. Contrarily, enriching low-salinity seawater, containing definite amounts of PDIs, with CO2 promoted superior oil recovery within all pore-size groups with an overall incremental value as high as 24%. This enhanced performance was evidenced by a dominance of wettability reversal to near-neutral states, which created a more favorable capillary pressure required for pore-level displacements. Wettability alteration originated from the reduction in electrostatic attraction between oil–brine and brine–rock interfaces through surface adsorption of SO42– ions in low-pH environments. These observations establish wettability reversal aided by PDIs as the overriding pore-scale oil-recovery mechanism in oil-wet carbonates during CWI.

Effect of organic acids on CO2-rock and water-rock interfacial tension: Implications for CO2 geo-storage

A small concentration of organic acid in carbon dioxide (CO2) storage formations and caprocks could significantly alter the wettability of such formations into less water-wet conditions, decreasing the CO2-storage potential and containment security. Recent studies have attempted to infer the influence of the organic acid concentration on the wettability of rock–CO2–brine systems by measuring advancing and receding contact angles. However, no studies have investigated the influence of organic acid contamination on CO2-storage capacities from rock-fluid interfacial tension (IFT) data because solid-brine and solid-CO2 IFT values cannot be experimentally measured. Equilibrium contact angles and rock-fluid IFT datasets were used to evaluate the viability of CO2 storage in storage rocks and caprocks. First, the contact angles of rock in brine-CO2 systems were measured to compute Young's equilibrium contact angles. Subsequently, rock-brine and rock-gas IFT values at CO2 geo-storage conditions were computed via a modified form of Neumann's equation of state. For two storage-rock minerals (quartz and calcite) and one caprock mineral (mica), the results demonstrated high CO2-brine equilibrium contact angles at high pressure (0.1–25 MPa) and increasing concentrations of stearic acid (10−5 to 10−2 mol/L). Rock-brine IFT increased with the increased stearic acid concentration but remained constant with increased pressure. In all conditions, the order of increasing hydrophobicity of the mineral surfaces is calcite > mica > quartz. At 323 K, 25 MPa, and a stearic acid concentration of 10−2 mol/L, quartz became intermediate-wet with a CO2-brine equilibrium contact angle of 89.8°, whereas mica and calcite became CO2-wet with CO2-brine equilibrium contact angles of 117.5° and 136.5°, respectively. This work provides insight into the effects of organic acids inherent in CO2 geo-storage formations and caprocks on rock wettability and rock-fluid interfacial interactions.

Design, synthesis and properties evaluation of emulsified viscosity reducers with temperature tolerance and salt resistance for heavy oil

To construct ultra-high temperature and salt stable viscosity reducers, viscosity reducers AFOP-n were synthesized and evaluated. These additives were terpolymer of Bisphenol AF, p-hydroxy benzenyl sulfonic acid and Octylphenol ethoxylate synthesized by solution polymerization, and its general molecular structure was confirmed by IR, HNMR and GPC. The polymer AFOP-10 presented good surface activity (30.3 mN/m). Thermal gravimetric analysis showed that the polymer had a very high temperature tolerance, and it was stable up to 340 ℃. Furthermore, the polymer has a high salt resistance in solution. The viscosity values of heavy oil before and after emulsification were 3500 and 62.30 mPa·s, respectively. The viscosity reduction ratio was 98.22% and the water diversion ratio was 75.6% when the salt concentration was 49476 mg/L. Moreover, in the simulated brine system with salinity of 8246 mg/L, AFOP-10 still had good activity after aging at 300 ℃ for 24 h, the viscosity reduction ratio of heavy oil in Bohai Sea remained above 98.5%, and also exhibited better interfacial activity (0.21 mN/m).

Application of robust intelligent schemes for accurate modelling interfacial tension of CO2 brine systems: Implications for structural CO2 trapping

Given the current global climate change, renewable energy sources, carbon capture, utilization, and storage (CCUS) are being considered as a potential solutions to this critical global issue. Structural and capillary processes can be used to store carbon dioxide (CO2) in deep saline aquifers in a way that is safe and does not harm the environment. Due to this fact, the interfacial tension (IFT) of the CO2-brine system is an important factor influencing the capacity of storage formations to sequester CO2. As a result, IFT is essential for conducting a thorough and accurate evaluation in order to determine the optimal strategy for CO2 storage projects. This paper used intelligent models such as Gaussian Process Regression (GPR), Radial Basis Function (RBF), and Random Forest (RF) to forecast IFT in the CO2-brine system with high precision and substantial time saving. The results reveal that the constructed RF model could deliver excellent performance in predicting IFT with the lowest average absolute percent relative error (AAPRE = 1.9156 percent), highest coefficient of determination (R2 = 0.9907), and lowest root mean squared error (RMSE = 0.7279). Furthermore, a sensitivity analysis was performed to ascertain the most critical parameters in the RF model to be considered. The parametric analysis found that both pure and non-pure CO2 systems had a significant impact on IFT prediction.Also, the RF model was used to assess the structural trapping capacity of a storage location in the Cuu Long Basin. The estimation results obtained in this study agreed perfectly with the previous ones. The findings of this study can aid in a better understanding of how machine learning models can be applied to predict IFT values for the evaluation of the structural CO2 storage capacity.

Measurements and interpretation of crude Oil-Water/Brine dynamic interfacial tension at subsurface representative conditions

Interfacial tensions (IFTs) between crude oil and water or brine systems are critically important in many processes. Exhibited dynamic behavior often remains poorly studied and requires in-depth analysis. In this study, 27 series of dynamic IFT measurements were conducted for three different crude oils in combination with three different aqueous phases (pure water and two synthetic reservoir brines) at temperatures of 298.15, 343.15 and 393.15 K and pressures up to 30 MPa. This study provides a large database of crude oil-water/brine IFTs encompassing reservoir conditions of temperature and pressure. Specific effects of temperature, pressure, and fluid composition on the crude oil-water and oil-brine IFTs were evaluated. The dynamic evolution of the IFT between the crude oils and aqueous phases was categorized according to typical relationships observed. The most commonly observed evolution was an initial rapid decline in IFT, over a period of 100 to 1,000 s, followed by levelling off at a nearly-constant long-term value. However, in certain cases, the initial rapid decline was followed by a broad minimum and a subsequent slow increase towards a nearly-steady long-time value. In either case, the initial decline is described by a simple model based on diffusion of surface-active components in the oil and their subsequent adsorption at the interface. The longer-term behavior may be further attributed to a combination of saturation, rearrangement and dissolution of the surface-active components.

Unusual CO2 hydrate formation in porous media: Implications on geo-CO2 storage laboratory testing methods

CO2 sequestration in geological sediments as hydrates is a promising technique currently being explored by research to permanently store CO2. To achieve this, studies on site selection and best experimental practices are useful to provide recommendations for understanding and implementing the process. In this study, the kinetics of CO2 hydrate formation was evaluated in quartz sand at 4 MPa and 274.15 K to gain insight on selecting a suitable location that provides high CO2 hydrate storage capacity. The study was conducted using a stainless-steel autoclave cell and a constant cooling method in pure water and brine system (3.3 wt% NaCl). The study revealed that CO2 hydrate forms faster in quartz sand achieving about 87% CO2 to hydrate conversion in pure water as opposed to 55% CO2 to hydrate conversion in the brine system. The high hydrate conversion achieved in pure water is promising to provide a potential storage capacity of CO2 in sediments. However, visual confirmation revealed that a high percentage of the hydrates in the pure water system formed at the top of the sand bed within the reactor which is unusual and undesired for practical CO2 storage field applications. Interestingly, the hydrate formed in the brine system was within the porous media pore spaces. The results thus suggest that hydrate storage techniques experimental testing should be conducted in reactors with visual capabilities to gain a proper understanding of the location of the hydrates within the porous media.

Robust Graphene Oxide Hybrid Membrane for High-Efficiency Emulsion Separation and Dyes Removal in High-Salt Brine Systems

Robust Graphene Oxide Hybrid Membrane for High-Efficiency Emulsion Separation and Dyes Removal in High-Salt Brine Systems