Brine System Research Articles

Wettability alterations of amorphous shales in geological carbon storage: Impact of acidic conditions in deep saline aquifers

The feasibility of Geological carbon storage (GCS) in deep saline aquifers is mainly determined by its ability to prevent CO2 leakage through caprock, which is most commonly shale. The wettability of the shale–CO2–brine system is one of the most essential petro-physical parameters in the assessment of the integrity of shale caprock. Current literature suggests that wettability measurements of the shale–CO2–brine system have many contradictory outcomes. Furthermore, previous applications of molecular dynamic simulation (MDS) to estimate wettability of the shale–CO2–brine system disregarded variations in shale composition and concentrated on just a single component. Moreover, there has been limited investigation into the effect of CO2 dissolution in brine and the resultant acidic conditions on the wettability of the shale–CO2–brine combination. In this study, MDS is implemented for evaluating the wettability of a system made up of amorphous shale, CO2, and brine under conditions representative of typical geological storage site. An amorphous shale molecular model has been developed through the integration of illite, quartz, and kerogen. The microscopic wetting and half-angle fitting approaches have been applied to establish the wettability. A qualitative investigation was also conducted to further examine the wettability of the studied systems. Additionally, a contrasting analysis was conducted to assess the conclusions of this study in relation to relevant literature data. The findings of this study demonstrate the wettability of an amorphous shale–CO2–brine system is significantly influenced by the composition of the shale and the presence of acidic conditions. The water contact angles for shales with TOC values of 5% and 10% were measured to be 42.1° and 52.5°, respectively, at a pressure of 10 MPa and a temperature of 333 K, without taking into account any acidic conditions. The addition of induced acidic conditions resulted in a 15% and 24% increase in the water contact angle, respectively, for high and low TOC shale systems, respectively. The findings of this study have significant implications on the containment of stored CO2, thereby contributing to the worldwide efforts of minimizing greenhouse gas emissions through enhancements in the performance of GCS processes.

Amino acid-assisted effect on hydrate-based CO2 storage in porous media with brine.

CO2 storage as hydrates in porous media is a promising method for storing carbon dioxide (CO2). However, the sluggish formation kinetics of hydrates urge the need to focus on the use of additives (promoters) to accelerate hydrate kinetics. This study investigates the effect of amino acid solutions in brine on CO2 hydrate formation and dissociation kinetics in quartz sand particles QS-2 (0.6-0.8 mm) with 38% porosity. The amino acids l-methionine (l-meth), l-isoleucine (l-iso), and l-threonine (l-threo) were studied at 0.2 wt% using an autoclave hydrate reactor at 4 MPa and 274.15 K in the presence and absence of salt (3.3 wt% NaCl) in 100% water saturation. The hydrate dissociation kinetics was studied at a temperature of 277.15 K. These conditions represent the normal seabed temperature range in Malaysia and hence were used for testing CO2 hydrate formation and dissociation kinetics in quartz sand in this study. Further, CO2 hydrate formation and dissociation experiments were conducted with sodium dodecyl sulphate (SDS) and brine systems as standards for comparison. The findings reveal the best kinetics for l-meth exhibiting the highest CO2 hydrate storage capacity. l-meth recorded a gas-to-hydrate conversion ratio of about 93% at 0.2 wt% in quartz sand with brine. Moreover, l-meth exhibited the lowest hydrate dissociation rate compared to l-iso and l-threo systems, thereby enhancing CO2 hydrate stability in quartz sand. Comparatively, l-meth enhanced the storage capacity by 36% and reduced the induction time by more than 50% compared to conventional promoter SDS in quartz sand with brine, suggesting it to be favorable for CO2 storage applications. CO2 hydrate nucleation time was predicted in quartz sand with and without the best-studied amino acid l-meth system with high prediction accuracy and an absolute average deviation of 2.4 hours. The findings of this study substantiate the influence of amino acids in promoting the storage capacity of CO2 in sediments as hydrates.

Micro kinetic analysis of the CO2 hydrate formation and dissociation with L-tryptophan in brine via high pressure in situ Raman spectroscopy for CO2 sequestration

Hydrate-based CO2 sequestration (HBCS) is widely recognized as a promising, long-term, and stable approach for CO2 sequestration, but its slow formation kinetics in saline systems pose a significant challenge. In order to address this challenge, this experimental study investigated the potential of L–Tryptophan (L–Trp) as a CO2 hydrate kinetic promoter in deionized water and brine systems. A high-pressure reactor coupled with in situ Raman spectroscopy was used to examine macro-level kinetics and micro-level Raman spectra. The CO2 hydrate formation experiments were conducted at 3.5 MPa and 275.15 K, with different L–Trp concentrations (0–3000 ppm) in deionized water (DI) and brine systems. Raman spectra were monitored throughout the hydrate formation process, identifying distinct peaks corresponding to dissolve CO2, CO2 hydrates, and water activity. The experimental results indicate that the addition of 1000 ppm L–Trp in deionized water significantly enhances CO2 uptake by 3.6–fold and promotes hydrate formation kinetics by 3.3–fold compared to the system without L–Trp. In the brine system (3.5 wt% NaCl), the optimal L–Trp concentration was found to be 2000 ppm, leading to a 1.5-fold increase in CO2 uptake. Remarkably, L–Trp not only enhances the formation kinetics but also facilitates dissociation and CO2 recovery in DI water. Nevertheless, the presence of NaCl hinders the promoting effect of L–Trp on the dissociation kinetics. These findings represent a significant advancement in feasible HBCS technology for CO2 sequestration.

Solubility of H2 in water and NaCl brine under subsurface storage conditions: Measurements and thermodynamic modeling

In the context of Underground Hydrogen Storage (UHS), deep saline aquifers offer great potential due to their availability and high storage capacity. In these porous media, the direct contact between gas (H2), brine and rock can lead to biotic and/or abiotic reactions (e.g. Hydrogen-induced calcite dissolution, (bio)methanation, Acetogenesis, etc.). These reactions take place in the aqueous phase between dissolved species (gas and minerals), hence the need for accurate high-pressure solubility data of hydrogen in brine. At high-pressure conditions, only few data on the phase equilibria of H2/brine systems are available in the open literature, and with significant inconsistencies among themselves. Hence, in this work, new solubility data for H2 in NaCl brine were obtained under subsurface storage conditions using a volumetric method, at temperatures between 298 and 373 K, at NaCl molalities between 0 and 4mol/kgw, and at pressures up to 200 bar. Interestingly, the data measured in this work lies between the two existing data sources which exhibited noticeable discrepancies. These data were used to parameterize and evaluate three well-known thermodynamic models based on different approaches: e-NRTL activity coefficient model, Duan-type (non-iterative) model and Søreide and Whitson's equation of state. It has been found that these models, of which the advantages and limitations of each have been discussed, are able to provide highly accurate predictions of the phase equilibria of the H2–NaCl brine system with an average absolute deviation of less than 3%. The resulting models and parameters can be used in reservoir simulators to evaluate dissolution losses and geobiochemical reactivity associated with UHS in porous media. Moreover, these models can be applied to estimate the saturation moisture content of gases coming out of UHS facilities, or in other applications (PEM electrolyzer, electrochemical H2 compressors, etc.).

Metal Recovery from Natural Saline Brines with an Electrochemical Ion Pumping Method Using Hexacyanoferrate Materials as Electrodes.

The electrochemical ion pumping device is a promising alternative for the development of the industry of recovering metals from natural sources-such as seawater, geothermal water, well brine, or reverse osmosis brine-using electrochemical systems, which is considered a non-evaporative process. This technology is potentially used for metals like Li, Cu, Ca, Mg, Na, K, Sr, and others that are mostly obtained from natural brine sources through a combination of pumping, solar evaporation, and solvent extraction steps. As the future demand for metals for the electronic industry increases, new forms of marine mining processing alternatives are being implemented. Unfortunately, both land and marine mining, such as off-shore and deep sea types, have great potential for severe environmental disruption. In this context, a green alternative is the mixing entropy battery, which is a promising technique whereby the ions are captured from a saline natural source and released into a recovery solution with low ionic force using intercalation materials such as Prussian Blue Analogue (PBA) to store cations inside its crystal structure. This new technique, called "electrochemical ion pumping", has been proposed for water desalination, lithium concentration, and blue energy recovery using the difference in salt concentration. The raw material for this technology is a saline solution containing ions of interest, such as seawater, natural brines, or industrial waste. In particular, six main ions of interest-Na+, K+, Mg2+, Ca2+, Cl-, and SO42--are found in seawater, and they constitute 99.5% of the world's total dissolved salts. This manuscript provides relevant information about this new non-evaporative process for recovering metals from aqueous salty solutions using hexacianometals such as CuHCF, NiHCF, and CoHCF as electrodes, among others, for selective ion removal.

Solubility and interfacial tension models for CO2–brine systems under CO2 geological storage conditions

Thermodynamic properties of the CO2–brine pseudo-binary system are essential for the design of geological carbon storage (GCS) projects, especially those utilizing saline aquifers. The gas–liquid–solid interactions manifest in the interfacial tensions (IFTs) and contact angle determine the injectability, sealing capacity, and storage security of the GCS process. Dissolution of CO2 in the reservoir brine occurs throughout the entire GCS process, leading to enhanced storage capacity but also to acidification of the brine, possibly leading to reservoir or seal damage. Two of the most important thermodynamic properties of the fluids are the mutual solubility and the IFT of the CO2–brine pseudo-binary system. In this work, we report a new correlative model for the IFT between CO2- and water-rich phases over wide ranges of temperature (273 to 473 K) and pressure (up to 100 MPa). The model is parameterized for brines comprising any combinations of sodium, potassium, calcium and magnesium cations with chloride, sulphate and bicarbonate anions up to a total molality of at least 5 mol·kg−1. The independent variables in this new model are reduced temperature, ion molalities and the mole fraction of CO2 dissolved in the aqueous phase. The latter is related to temperature, pressure and ion molalities by an improved model for the mutual solubility. More than 2000 experimental data points were used in the development of the two models. For the IFT of the CO2-H2O binary system, the overall root-mean-square deviation (RMSD) is 0.65mN·m−1 while the absolute average relative deviation (AARD) is 1.8%. In the case of mutual solubility, the RMSD of CO2 mole fraction in the aqueous phase is 0.0003 and the AARD is 5.5% while, in the non-aqueous phase, the RMSD of H2O mole fraction is 0.0035 and the corresponding AARD is 8.7%. Similar results are found for the CO2-brine systems.

Interfacial properties of asphaltene–brine systems and analysis of adsorption kinetics: effects of ion and water injection for EOR

Interfacial properties of asphaltene–brine systems and analysis of adsorption kinetics: effects of ion and water injection for EOR

Measurements and predictions of phase equilibria in quinary system NaCl + KCl + MgCl2 + SrCl2 + H2O (saturated with NaCl) at 308.2 K

AbstractSichuan Basin of China is a typical underground brine enrichment area. In order to develop and utilize the brine resource, it is necessary to study the phase equilibria and phase diagram of brine systems. In this work, the phase equilibria of the quinary system NaCl + KCl + MgCl2 + SrCl2 + H2O (saturated with NaCl) at 308.2 K of the underground brines in Sichuan Basin are measured experimentally by isothermal dissolution equilibrium method. The phase diagram, water content diagram, and sodium chloride content change diagram of the quinary system with NaCl saturated are also drawn, respectively. The results show that the phase diagram of the quinary system contains three invariant points, seven isothermal solubility curves, and five solid crystal zones at 308.2 K. In the phase diagram, the KCl crystallization area is the largest, followed by SrCl2·6H2O, KCl·MgCl2·6H2O, and SrCl2·2H2O, while MgCl2·6H2O has the smallest crystallization area. Magnesium chloride in the quinary system has the largest solubility and has strong salting‐out effect on other salts. Furthermore, the unreported mixed ion interaction parameters θMg, Sr and ΨMg, Sr, Cl of Pitzer model are fitted, respectively. Consequently, the solubilities of the quinary system NaCl + KCl + MgCl2 + SrCl2 + H2O at 308.2 K are predicted using the Pitzer model, and the calculated phase diagram at 308.2 K is also plotted in detail. The predicted solubilities of the quinary system were in good agreement with the experimental solubilities. Finally, the study on the phase equilibrium of the quinary system can provide phase equilibrium data for the development and utilization of liquid mineral resources.

Spatial Distribution of Glycine and Aspartic Acid in Rapidly Frozen Brines Relevant to Enceladus

Saturn’s moon Enceladus harbors a global, subsurface liquid ocean beneath an icy crust that actively erupts water jets from fissures in its south pole. Data returned from the Cassini mission have identified salts and organic matter within these ejected plume particles. Such combinations of water, organics, and salts present rather complex chemical environments that may hold direct implications for habitability. The fundamental behavior of organics in frozen brine systems upon exposure to relevant Enceladus surface conditions is an important aspect that has not been explored to date (e.g., how they organize and partition relative to the salt minerals within the ice matrix). The present work investigates this topic by characterizing the spatial distribution of two amino acids with different side chains (glycine and aspartic acid) in a putative frozen Enceladus brine, containing sodium, chloride, and carbonate ions, via micro-Raman imaging. The results show that both organic–salt solutions likely undergo some degree of vitrification upon flash freezing, especially for the chloride-bearing species. The subsequent annealing of the vitreous samples reveals a preferential association of the amino acids with crystalline salt hydrates, while minimal negative to no correlation is found between them and water ice. In particular, both amino acids exhibit stronger affinities for natron (Na2CO3•10H2O) than hydrohalite (NaCl•2H2O). This suggests that solute–solute interaction likely dominates in these frozen systems, especially when charged species are present. The results imply that salt-rich ice particles can serve as concentrators of organic biomarkers, enhancing their potential for detection from remote sensing or in situ analysis.

FluidFlower Benchmark: Lessons Learned from the Perspective of Subsurface Simulation

In this work, we describe our decisions made to perform the FluidFlower simulation study and discuss various aspects of the benchmark that are different from our usual subsurface simulation practice. We will discuss the impact of various modeling choices on the outcomes of the simulation models, such as gridding, discretization, and solver strategies, and the lessons learned, taking into account the different conditions of the FluidFlower study compared to conditions commonly dealt with in subsurface simulation. We will start with a brief description of the DARTS framework utilized for compositional simulation, the thermodynamic and physical modeling related to the atmospheric CO2\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\ ext{ CO}_{2}$$\\end{document}-brine system, and the modeling workflow used in our benchmark submission. Additionally, we describe a custom nonlinear solver developed for the atmospheric benchmark conditions to improve convergence including the linear solver strategy since our default two-stage preconditioner does not perform effectively. To make meaningful comparisons between each of the modeling choices, we define a baseline model which is a simplified version of our setup in the main FluidFlower benchmark. The baseline model is then used to study the effect of Cartesian and unstructured meshes and a two-point flux approximation compared with a multi-point flux approximation for capturing the physics at play. We conclude our work with lessons learned and future recommendations.

Solid–Liquid Phase Equilibria of the Quaternary System NaCl–CaCl2–H3BO3–H2O at 323.15 K: Solubility Determination and Thermodynamic Model

The solid–liquid phase equilibria of brine systems containing boric acid are the theoretical basis for the development of boric acid from brine resources. The phase equilibria of the systems NaCl–CaCl2–H3BO3–H2O and CaCl2–H3BO3–H2O at 323.15 K were investigated by the isothermal solution method. The phase diagram for the ternary system is composed of one co-saturation point, two univariant solubility curves, and two singe-salt crystallization fields of CaCl2·2H2O and H3BO3. The dry-salt phase diagram for the quaternary system consists of one invariant point, three univariant solubility curves, and three single-salt crystallization fields for NaCl, CaCl2·2H2O, and H3BO3. In the phase diagrams of the quaternary system at 298.15 and 323.15 K, the areas of sodium chloride and calcium chloride salt regions are enlarged, whereas the area of the H3BO3 region is diminished significantly with the increase of temperature. Using the Pitzer model, the lacking Pitzer parameters for H3BO3 were obtained by fitting the solubilities in the CaCl2–H3BO3–H2O system. The calculated solubilities with the Pitzer model were in accord with the experimental data.

Investigating High-Pressure Liquid CO2 Hydrate Formation, Dissociation Kinetics, and Morphology in Brine and Freshwater Static Systems

Carbon capture and storage [CCS] is crucial for mitigating CO2 emissions. One of the potential CCS concepts is to compress and store the captured CO2 into deep oceanic sediments as gas hydrates. However, seawater is highly saline [brine], which may impair the formation/dissociation kinetics and storage of CO2 hydrates. Therefore, it is essential to understand the liquid CO2 [LCO2] hydrate formation and dissociation kinetics in static brine systems. In this experimental study, we have examined the formation/dissociation kinetics and morphology of high-pressure LCO2 hydrates in brine using a static [unstirred] high-pressure crystallizer at deep oceanic [1 km] thermodynamic conditions [10 MPa, 1–2 °C]. The results are compared with [unstirred/stirred] freshwater systems with/without hydrate promoters. Three key stages have been identified in the experiments: nucleation [stage 1], LCO2-hydrate-brine film formation [stage 2], and LCO2-hydrate-brine film breakage [stage 3]. In the absence of stirring, the formation of the LCO2-hydrate-brine film resists the mass transfer of LCO2 into the brine, and most likely, the volume expansion during hydrate formation causes the LCO2-hydrate-brine film to break. New hydrate morphological growth patterns have been identified. It was estimated that the hydrate conversion in the freshwater system was higher [27.5% (±3.04%) in 21.1 (±1.26) h] compared to the brine system [25.0% in 24.2 (±0.58) h]. LCO2 hydrates dissociate faster in brine [1.7 (±0.14) h] compared to the freshwater system [5.7 (±1.77) h]. Finally, the presence of the eco-friendly hydrate promoter 500 ppm l-tryptophan can delay the dissociation process.

Solid-liquid equilibria of Sorel phases and Mg (OH)2 in the system Na-Mg-Cl-OH-H2O. Part I: experimental determination of OH− and H+ equilibrium concentrations and solubility constants at 25°C, 40°C, and 60°C

Sorel phases are the binder phases of the magnesia building material (Sorel cement/concrete) and of special concern for the construction of long-term stable geotechnical barriers in repositories for radioactive waste in rock salt, as potentially occurring brines are expected to contain MgCl2. Sorel phases, in addition to Mg(OH)2, are equally important as pH buffers to minimize solubility and potential mobilization of radionuclides in brine systems. In order to obtain a detailed database of the relevant solid-liquid equilibria and the related pHm values of the equilibrium solutions, extensive experimental investigations were carried out. Solid phase formation was studied by suspending MgO and Mg(OH)2 in NaCl saturated MgCl2-solutions at 25°C. Mg(OH)2 and the 3-1-8 Sorel phase were identified as the stable solid phases, while the 5-1-8 Sorel phase is metastable. Equilibration at 40°C did not lead to any solid phase changes. Both OH− and H+ equilibrium concentrations were analyzed as a function of MgCl2 concentration at 25°C and 40°C. In addition to our already published solid-liquid equilibria for the ternary system Mg-Cl-OH-H2O (25°C–120°C), the equilibrium H+ concentrations (pHm) determined at 25°C, 40°C and 60°C are now reported. Analyzing these data together with known ion-interaction Pitzer coefficients, the solubility constants for Mg(OH)2 and the 3-1-8 phase at these three temperatures, for the metastable 5-1-8 phase at 25°C and for the 2-1-4 phase at 60°C have been consistently calculated.

Hydrogen tightness evaluation in bedded salt rock cavern: A case study of Jintan, China

Hydrogen is regarded as one of the most important energy sources for the future. Safe, large-scale storage of hydrogen contributes to the commercial development of the hydrogen industry. Use of bedded salt caverns for natural gas storage in China provides a new option for underground hydrogen storage (UHS). In this study, the physical properties of multicomponent gases in UHS and salt rock are reviewed and discussed, along with the flow of hydrogen in the surrounding salt rock. Mathematical models of the two-phase multicomponent flow of the gas–brine system in the UHS were established. A numerical model of a simplified elliptical salt cavern was built to simulate the migration of the gas–brine system in the UHS. The hydrogen tightness of the UHS was evaluated through simulation with different storage strategies, salt rock and interlayer permeabilities, and gas components. The results indicate that: (1) Cyclic injection and withdrawal facilitate hydrogen leakage, which is accelerated by increasing the frequency. (2) The huff-n-puff of hydrogen gas in the injection and withdrawal cycles forces the gas into pore space and enhances the relative permeability of the gas phase. The migration of hydrogen and brine weakens the hydrogen tightness. Brine saturation is an important index for evaluating the hydrogen tightness of UHS. (3) The leakage rate of UHS increases with an increase in the permeability of the salt rock and interlayer and the total thickness of the interlayers. The average permeability Kwa weighted by the thickness of layers for the bedded salt formation is proposed to integrate three variables to facilitate field application of the simulation results. The critical Kwa is less than 3.02 × 10−17 m2 if the recommended annual hydrogen leakage rate is less than 1%. (4) The difference between hydrogen and other gas species is another important factor in the leakage rate and should be considered. This study provides theoretical guidance for evaluating the feasibility of UHS in salt caverns and site selection in China.

Metal budget and origin of aqueous brines depositing deep-seated Zn-Pb mineralization linked to hydrocarbon reservoirs, North German Basin

The origin, evolution, and interplay of brine and hydrocarbon fluid systems play a crucial role in the formation of deep sediment-hosted base metal ore deposits. Here we investigate ratios of halogens, noble gases, stable C and S isotopes, and metal budgets of aqueous brines, which deposited deep-seated and near-surface hydrothermal Zn-Pb mineralization hosted by Zechstein carbonates in the Lower Saxony Basin (North German Basin), by studies of fluid inclusions in sphalerite and quartz. Major and trace element geochemistry and noble gas isotopic signatures of brine inclusions revealed that the ore-forming fluids were highly reactive and experienced prolonged interactions with host rocks in the constricted, over-pressured metal source regions and consequently evolved from near-neutral, oxidized brines towards more reduced, acidic high-salinity brines. Quartz-hosted halite-saturated fluid inclusions with Th <200°C contain Zn and Pb concentrations up to ca. 9400 μg g-1 and 5200 μg g-1, respectively, and indicate the efficiency of metal scavenging processes. The interactions with Westphalian coals and Corg-rich shales influenced the redox state as well as the trace and critical element budget of the sphalerite-hosted fluid inclusions, with enrichment in Ge, Pd, Sb, Tl, Bi, and Ag. The salinities of metalliferous fluids originated primarily from seawater evaporation, however in addition a significant halite-dissolution component is present in the southern part of the Lower Saxony Basin. High concentrations of radiogenic noble gases and potassium in the sphalerite-hosted fluid inclusions are ascribed to strong interactions with the Paleozoic siliciclastic sedimentary pile and crystalline basement rocks. Reflux of the strongly modified, sulfur-poor, Zn-Pb-bearing acidic brines, proceeded via re-activated structurally controlled pathways into sour gas or gas-saturated brine pools in the Zechstein Ca2 carbonate unit. Here, mixing of the ascending metal-rich brines with H2S derived from thermochemical sulfate reduction (TSR), resulted in the deposition of deep-seated Zn-Pb ores in the Lower Saxony Basin. The overall timing of the Zn-Pb ore formation can be constrained to the Upper Cretaceous basin inversion.

Unlocking the Power of Artificial Intelligence: Accurate Zeta Potential Prediction Using Machine Learning.

Nanoparticles have gained significance in modern science due to their unique characteristics and diverse applications in various fields. Zeta potential is critical in assessing the stability of nanofluids and colloidal systems but measuring it can be time-consuming and challenging. The current research proposes the use of cutting-edge machine learning techniques, including multiple regression analyses (MRAs), support vector machines (SVM), and artificial neural networks (ANNs), to simulate the zeta potential of silica nanofluids and colloidal systems, while accounting for affecting parameters such as nanoparticle size, concentration, pH, temperature, brine salinity, monovalent ion type, and the presence of sand, limestone, or nano-sized fine particles. Zeta potential data from different literature sources were used to develop and train the models using machine learning techniques. Performance indicators were employed to evaluate the models' predictive capabilities. The correlation coefficient (r) for the ANN, SVM, and MRA models was found to be 0.982, 0.997, and 0.68, respectively. The mean absolute percentage error for the ANN model was 5%, whereas, for the MRA and SVM models, it was greater than 25%. ANN models were more accurate than SVM and MRA models at predicting zeta potential, and the trained ANN model achieved an accuracy of over 97% in zeta potential predictions. ANN models are more accurate and faster at predicting zeta potential than conventional methods. The model developed in this research is the first ever to predict the zeta potential of silica nanofluids, dispersed kaolinite, sand-brine system, and coal dispersions considering several influencing parameters. This approach eliminates the need for time-consuming experimentation and provides a highly accurate and rapid prediction method with broad applications across different fields.

A-Priori screening of deep eutectic solvent for enhanced oil recovery application using COSMO-RS framework

This study investigates the potential of Deep Eutectic Solvent (DES) in Enhanced Oil Recovery (EOR) via interfacial tension (IFT) reduction mechanism. The effectiveness of 217 DES in the IFT reduction mechanism that ultimately assist in EOR is investigated via COnductor-like Screening MOdel for Real Solvent (COSMO-RS) theory and the sigma moment model. Genetic algorithm (GA) is employed to estimate the constants of COSMO-RS theory and sigma moment model. IFT prediction of representative Omani heavy crude oil in 217 DES in the brine system is reported and analyzed at the mole fraction of DES in brine ranging from 1 × 10-3 to 5 × 10-1 with variation in temperature from 298.15 K to 353.15 K. The highest and the lowest values thus obtained for IFT are 560.8 and 0.2 mN/m. There are 26 DESs capable of reducing IFT by more than 50%, while another 10 DESs show a reduction capability of more than 75%. The optimum concentration of DES to maximize IFT reduction is further analyzed.

Solid–Liquid Phase Equilibria and Boron Species Distribution in the Brine System Li2SO4‒LiBO2‒Li2B4O7‒H2O at 323.15 K

Solid–Liquid Phase Equilibria and Boron Species Distribution in the Brine System Li2SO4‒LiBO2‒Li2B4O7‒H2O at 323.15 K

Rock–Oil–Brine Dominant Mechanisms in Smart Water Flooding

Recent research has highlighted wettability alteration as the main consequence of the different mechanisms involved in technologies such as adjusted brine composition water flooding (ABCW) and low-salinity water flooding (LSW). However, studies are still needed to give a phenomenological explanation, and the most influential components of the system (rock–oil–brine) must be clarified. This work focuses on determining the most relevant variables for the smart water effects to occur. Static (contact angles) and dynamic tests (coreflooding) were conducted. For the static tests, aged Berea slices, a specific crude oil (27° API, 10.5 cp at 60 °C), and mono and divalent inorganic salts (Na+, K+, Ca2+, and Mg2+/Cl−) were used in 3 different concentrations of 1000, 3000, and 5000 ppm (ionic strength variation between 0.015 and 0.06) to establish the wettability state by measuring the contact angles of the system. When salts containing chloride were evaluated, a decrease in oil wettability was observed at 5000 ppm. At 3000 and 1000 ppm, tendencies depended on the particular cation. Three brines were selected from the contact angle experiments to be used in coreflooding assays, considering a particular design to identify ion exchange from the rock–oil–brine system. The first assay was carried out in the absence of crude oil as a baseline to determine the ion exchange between the brine and the rock, and a second test considered crude oil to provide insight into ion exchange and its effect on displacement efficiency. Capillary electrophoresis was used in this research as a novel contribution to the systematic study of oil displacement tests, and it has proven to be a powerful tool for understanding the mechanisms involved. The results show that the variations in the concentrations detected in the displacement effluents were the product of the interactions between rock, oil, and brine since the concentrations measured in the absence of oil phase were comparable to those in the injection brine. Significant variations in the effluent ion concentrations were determined for the different brines used, and increases in the pressure differentials were observed for the KCl and CaCl2 brines. These results suggest that the oil–brine ion exchange (salting in/out) represents a relevant mechanism to explain the observed displacement efficiencies and differential pressures. The ionic enrichment of the water phase due to the salting in/out effect needs to be better understood.

Solid-liquid equilibria in relevant subsystems of LiBr-NaBr-KBr-MgBr2-CaBr2-H2O system at 298.15K.

In view of the composition characteristics of lithium, calcium and bromine rich in Nanyishan oil and gas field brine of western Qaidam Basin, Qinghai Province, as well as based on the results reported in relevant literature, the phase equilibrium relationship of ternary system LiBr-CaBr2-H2O at 298.15K was studied by isothermal dissolution equilibrium method. The equilibrium solid phase crystallization regions, as well as the compositions of invariant point, in phase diagram of this ternary system were clarified. On basis of the above ternary system research, the stable phase equilibria of quaternary systems (LiBr-NaBr-CaBr2-H2O, LiBr-KBr-CaBr2-H2O and LiBr-MgBr2-CaBr2-H2O), as well as quinary systems (LiBr-NaBr-KBr-CaBr2-H2O, LiBr-NaBr-MgBr2-CaBr2-H2O and LiBr-KBr-MgBr2-CaBr2-H2O) were further carried out at 298.15K. According to the above experimental results, the corresponding phase diagrams at 298.15K were drawn, which revealed the phase relationship of each component in solution and the law of crystallization and dissolution, and meanwhile summarized changing trends. The research results of this paper lay a foundation for further research on the multitemperature phase equilibria and thermodynamic properties of lithium and bromine containing high-component brine system in later stage, and also provide basic thermodynamic data for guiding the comprehensive development and utilization of this oil and gas field brine resource.