CaCl2 Brine Research Articles

Solubility of H2S-CH4 mixtures in calcium chloride solution: Insight from molecular dynamics simulations

This study uses equilibrium molecular dynamics (EMD) simulations to gain microstructural insight into and predict crucial properties of gas-brine mixtures affecting sour gas reservoir development. The effects of pressure, temperature, gas composition and salinity on the solubility and density of H2S-CH4 mixtures in pure water and CaCl2 brine were investigated at industrially relevant conditions (temperature range of 280 − 340 K, pressures up to 20 MPa, and a salinity range of 4.78 − 17.32 wt%). The force fields used in the MD simulations were validated using experimental data for pure H2S and CH4. The results showed that the solubility of pure H2S and CH4 in pure water increases with pressure, with the latter having a higher solubility. For H2S-CH4 mixtures, the solubility of H2S increased while that of CH4 fell with increasing H2S mole fraction, with the solubilities of the two gases intersecting at an H2S mole fraction of 0.28. Further, the solubility of H2S shows a greater pressure dependence than that of CH4, and H2S gas tends to reach saturation in pure water. In calcium chloride solution, the gas solubility decreases as the ions reduce the interaction between water and gas molecules. The solubility of H2S gas is a stronger function of the ion concentration compared with CH4, and increases 6-fold as the H2S mole fraction increases from 0.5 to 0.8. The overall solubility ranges were 0.45 to 3.48 mol/kg for H2S and 0.15 to 0.25 mol/kg for CH4.

Distribution and Main Controlling Factors of Gas and Water in Tight Sandstone Gas Fields: A Case Study of Sudong 41-33 Block in Sulige Gas Field, Ordos Basin, China

Distribution and Main Controlling Factors of Gas and Water in Tight Sandstone Gas Fields: A Case Study of Sudong 41-33 Block in Sulige Gas Field, Ordos Basin, China

Experimental and Molecular Dynamics Simulation to Investigate Oil Adsorption and Detachment from Sandstone/Quartz Surface by Low-Salinity Surfactant Brines.

In this study, we explore the impact of monovalent (NaCl) and divalent (CaCl2) brines, coupled with sodium dodecyl sulfate (SDS) surfactant at varying low concentrations, on the detachment and displacement of oil from sandstone rock surfaces. Employing the sessile drop method and molecular dynamics simulations, we scrutinize the behavior of the brine solutions. Our findings reveal that both low salinity and low-salinity surfactant solutions induce a gradual shift in rock wettability toward a more water-wet state. This wettability transformation is not instantaneous but evolves over time, as observed through meticulous molecular motion analyses. Through contact angle measurements and molecular dynamics simulations, we delve into the molecular motion at subpore and micropore scales on sandstone/quartz surfaces. The adsorption of surface-active agents from the oil to the oil-brine interface results in a reduced interfacial tension, significantly contributing to oil displacement. Notably, low salinity concentrations ranging from 1000 to 10,000 ppm exhibit the lowest contact angles within 30 min across all solutions. However, higher concentrations deviate from this declining trend, especially with divalent ions like Ca2+, which bridge polar molecules onto the rock surface, resulting in an increased oil-wetting state. This research unveils the intricate molecular motions involved in employing low-salinity surfactant solutions for oil detachment from surfaces. Furthermore, it provides valuable insights into the underlying forces driving oil detachment and wettability alteration.

Brine formation in cold desert, shallow groundwater systems: Antarctic Ca-Cl brine chemistry controlled by cation exchange, microclimate, and organic matter

Groundwater in the McMurdo Dry Valleys of Antarctica is commonly enriched in calcium and chloride, in contrast to surface and groundwater in temperate regions, where calcium chemistry is largely controlled by the dissolution of carbonates and sulfates. These Antarctic Ca-Cl brines have extremely low freezing points, which leads to moist soil conditions that persist unfrozen and resist evaporation, even in cold, arid conditions. Several hypotheses exist to explain these unusual excess-calcium solutions, including salt deliquescence and differential salt mobility and cation exchange. Although the cation exchange mechanism was shown to explain the chemistry of pore waters in permafrost cores from several meters depth, it has not been evaluated for near-surface groundwater and wetland features (water tracks) in which excess-calcium pore-water solutions are common. Here, we use soluble salt and exchangeable cation concentrations to determine whether excess calcium is present in water-track brines and if cation exchange could be responsible for calcium enrichment in these cold desert groundwaters. We show that calcium enrichment by cation exchange is not occurring universally across the McMurdo Dry Valleys. Instead, evidence of the present-day formation of Ca-Cl−rich brines by cation exchange is focused in a geographically specific location in Taylor Valley, with hydrological position, microclimate, soil depth, and organic matter influencing the spatial extent of cation exchange reactions. Up-valley sites may be too cold and dry for widespread exchange, and warm and wet coastal sites are interpreted to host sediments whose exchange reactions have already gone to completion. We argue that exchangeable cation ratios can be used as a signature of past freeze-concentration of brines and exchange reactions, and thus could be considered a geochemical proxy for past groundwater presence in planetary permafrost settings. Correlations between water-track organic matter, fine sediment concentration, and cation exchange capacity suggest that water tracks may be sites of enhanced biogeochemical cycling in cold desert soils and serve as a model for predicting how active layers in the Antarctic will participate in biogeochemical cycling during periods of future thaw.

Source and genesis of Ca-Cl type brines in Qaidam Basin, Qinghai-Tibetan Plateau: evidence from hydrochemistry as well as B and Li isotopes

Ca-Cl brine is a highly mineralized special water body occurring in oceanic ridges or basins. The deep part of the western Qaidam Basin is rich in Ca-Cl brine, which is essential for the formation of (MgSO4-deficient) potash deposits. Previous studies on this type of brine in the Qaidam Basin focused on its source tracing, but different carriers led to different conclusions. Moreover, the genesis of Ca-Cl brines in inland basins still remains unclear. In essence, a solid understanding of the relatively abundant Ca sources for the formation of Ca-Cl brines in inland basins has not been reached. In addition, a metallogenic model for this type of brine has not yet been established. Through hydrochemical analysis as well as Band Li isotope tracing, this study clarified that the main elements (Na and Cl) in these Ca-Cl brines mainly originated from the dissolution of existing evaporites in the inner basin. Further, trace elements in Ca-Cl brines (such as Band Li) mainly originated from lixiviation; atmospheric rainfall infiltrated and interacted with ore-rich mother rocks along the basin-margin fracture system under suitable temperature-pressure conditions; alternatively, they may have originated from mixing with magmatic hydrothermal fluids. This study showed that Ca-Cl brines in the western part of the Qaidam Basin have a typical “binary structure” in terms of their sources. In addition, the sources of Ca in Ca-Cl brines were further discussed based on B and Li isotope data, thus exploring a new genesis of Ca-Cl brines in inland basins. Finally, by integrating the above findings, an ore-forming model of this type of water body in the western part of the Qaidam Basin is proposed. This study is valuable for understanding the genesis mechanism of Ca-Cl brines in inland basins, and also has practical significance for the prediction, exploration, and evaluation of this type of brine resource.

Polyampholyte-grafted silica nanoparticles for shale plugging under high-temperature and extreme-salinity conditions

Nano-/submicron-scale plugging is critical for wellbore stability during shale gas exploitation but typically fails under high-temperature and extreme-salinity conditions due to colloidal instability. Herein, polyampholyte polymers (ZP) were grafted from the surface of silicon dioxide (SiO2) nanoparticles through surface-triggered free radical polymerization to generate nanoplugging additives (SiO2-g-ZP). SiO2-g-ZP exhibited excellent colloidal dispersion stability with a nano/submicron size distribution in 35 w/v% sodium chloride (NaCl) and 11 w/v% calcium chloride (CaCl2) brines at 160 °C for a long time and over a wide pH range, and efficiently plugged 220 nm and ∼20 μm pores and 5 μm fractures at 160 °C and 3.5–5.5 MPa. Three critical aspects of observation and analysis obtained through microstructure analysis and molecular dynamics (MD) simulations helped elucidate the mechanisms that control the SiO2-g-ZP's performances: an increase in SiO2-g-ZP's hydration capability with salinity due to the antipolyelectrolyte behaviours of ZP coatings with zwitterionic nature, an efficient mitigation of Na-bent agglomeration even at harsh conditons due to the preferential adsorption of SiO2-g-ZP rather than Na+, Ca2+ and Cl− on Na-bent, and the presence of a nanosilica core and rigid groups and massive hydratable groups. The first two aspects caused a perfect matching of particles in muds to pores and fractures in formation and the third aspect helped enhance the SiO2-g-ZP's thermal resistance and residence in the pores and fractures. This work provides a novel approach that can be broadly generalized to address the thermal- and salt-tolerance challenges of colloidal systems used in the exploration and development of deep and complex shale formations.

Fly ash degree of reaction in hypersaline NaCl and CaCl2 brines: Effects of calcium-based additives

The pozzolanic reaction of fly ashes with calcium-based additives can be effectively used to solidify and chemically stabilize (S&S process) highly concentrated brines inside a cementitious matrix. However, complex interactions between the fly ash, the additive, and the brine typically affect the phases formed at equilibrium, and the resulting solid capacity to successfully encapsulate the brine and its contaminants. Here, the performances of two types of fly ash (a Class C and Class F fly ash) are assessed when combined with different additives (two types of cement, or lime with and without NaAlO2), and two types of brine (NaCl or CaCl2) over a range of concentrations (0 ≤ [Cl−] ≤ 2 M). The best performing matrices – i.e., the matrices with the highest Cl-containing phases content – were identified using XRD and TGA. The experimental results were then combined with thermodynamic modeling to dissociate the contribution of the fly ash from that of the additives. All results were implemented in a machine learning model that showed good accuracy at predicting the fly ash degree of reaction, allowing for the robust prediction of extended systems performance when combined with thermodynamic modeling.

Molecular Dynamics Simulation of a Brine Droplet under an Electric Field: Distinct Behavior Shown by NaCl and CaCl2.

Electrostatic demulsification is a promising technique to disrupt petroleum emulsions. However, the presence of salts in the emulsion can influence the effectiveness of the electric field. In this work, we target an understudied area, namely, the effect of salt ion type and concentration on the stability of brine droplets when exposed to an electric field. Molecular dynamics (MD) simulations are performed on a series of water-in-oil emulsion systems consisting of a water or brine droplet surrounded by an oil phase containing toluene and model asphaltene molecules (N-(1-hexylheptyl)-N'-(5-carboxylicpentyl) perylene-3,4,9,10-tetracarboxylic bisimide (C5Pe)). The brine droplet contains either NaCl or CaCl2, with concentrations varying from 0 to ∼11 wt %. An external electric field is applied, which has a strength ranging from 0 to 1 V/nm. Our results show that as the electric field increases, the bare water droplet exhibits progressive deformation from the original spherical shape to an ellipsoid, a spindle, and finally a cylinder. When the brine droplets are exposed to a low electric field (≤0.5 V/nm), they behave similar to the bare water droplet. However, at a high electric field (≥0.75 V/nm), both NaCl and CaCl2 brine droplets are stabilized in the bulk oil and maintain the spherical or ellipsoidal shape by ejecting salt ions toward the electrodes at high salt concentrations (≥7.8 wt %), which induces a counter electric field that weakens the destabilization of the droplet by the applied field. At low salt concentrations (≤4.5 wt %), brine droplets containing NaCl or CaCl2 display different behaviors: the former tends to shift toward an electrode, whereas the latter stays in the bulk oil phase. The contrasting phenomena are the result of combined effects of brine droplet net charge and C5Pe adsorption on the droplet surface: a large net charge and low C5Pe adsorption tend to drive the droplet toward an electrode. This study provides useful insights into the important role of salt ions in electrostatic demulsification of petroleum emulsions.

Study of CO2 absorption by low salinity aqueous solutions of specific salts in the absence and presence of carbonate rocks

Fossil-fuels combustion is currently the main driving force of industrialization; however, it has resulted in CO2 emission that challenges sustained socioeconomic growth. One way to reduce CO2 emissions is to sequester it into saline aquifers or depleted hydrocarbon reservoirs. In this study, CO2 absorption in different aqueous salt solutions is elucidated. CO2 absorption in different salines is also simulated using PHREEQC software to predict the concentration of different species formed by saline-CO2 interactions at equilibrium. Investigated parameters include concentration of different salts at low salinity condition, type of cations and anions, temperature, and carbonate rock on the CO2 absorption and storage in aqueous media at high pressures. Results revealed that both initial absorption rate and final absorbed amount of CO2 in aqueous salt solution decay in the order of MgSO4 > Na2SO4 > CaCl2 > MgCl2 > NaCl. For a given anion in the dissolved salt, the presence of divalent cations promotes CO2 absorption more than that of monovalent cations. Also, for equivalence cations the one with a higher charge density promotes CO2 absorption. It is also evident that for a given cation in the dissolved salt the associated anion which has a higher charge density hinders CO2 absorption more than that with a lower charge density. Similar pattern is maintained for CO2 absorption in saturated carbonate rock. PHREEQC simulations revealed that concentrations of precipitated carbonate salts in CO2-saturated Na2SO4 and NaCl brines are higher than those of the other brines. Moreover, increasing temperature increases concentration of precipitated carbonate salts in CO2-saturated MgSO4, CaCl2, and MgCl2 brines while it has an opposite effect on precipitated carbonate salts formed due to CO2 absorption in Na2SO4 and NaCl brines.

Effect of type of ion and temperature on fines migration induced by mineral reactions during water injection into carbonate rocks

Managed aquifer recharge is a water storage and recovery method. However, fines migration during water injection can significantly affect formation permeability. Several studies have analyzed fines migration in sandstone and soil samples, but few studies have investigated fines migration in carbonate rocks. In addition, the effect of neither temperature nor type of ion on fines migration has been investigated in carbonate rocks.Our experiments use filtered-deaired distilled water and pure salts to prepare the injection fluids. Rock samples are injected with 0.63 mol/L brine followed by four sequential injections of diluted brine: 0.21 mol/L, 0.1 mol/L, 0.05 mol/L, and 0 mol/L (distilled water). Pressure difference is recorded across the rock sample throughout each experimental run and used to calculate permeability. Effluent is collected to characterize produced fines and elements. pH and particle concentration measurements are collected frequently. Scanning electron microscope (SEM) images of inlet and outlet faces pre- and post-injection were taken to observe any changes.For the experimental runs performed at 25 °C, permeability decrease was 99.92% of the original permeability for seawater experimental run, 99.96% for NaCl brine experimental run, and nearly zero for CaCl2 brine experimental run. For CaCl2 brine experimental run, the only observed mineral reaction is mineral dissolution. For NaCl brine and seawater experimental runs, both mineral dissolution and cation exchange are observed, of which the latter appears to be the main mechanism for fines migration. Due to mineral dissolution, permeability increase is observed during 0.21 mol/L and 0.1 mol/L injection at high temperature. However, during distilled water injection, permeability decrease is found to be similar at both low and high temperatures.

Effect of fines migration on oil recovery from carbonate rocks

We perform single-phase and two-phase flooding on Edwards Brown rock samples. The single-phase injection was of seawater or CaCl2 brine, at successive salinities 0.63, 0.21, 0.07, 0.05, and 0 mol/L (distilled water). For CaCl2 brine experimental run, no significant fines migration or permeability decrease is observed. For seawater experimental run, distilled water injection is found to bring about the highest concentration of produced fines and most of the permeability decrease, with the ultimate permeability decrease being 99.94%. Therefore, distilled water injection is used to stimulate fines migration in the following two-phase experimental runs. Two-phase experiments are performed on four Edwards Brown rock samples using seawater or CaCl2 brine as the aqueous phase, and Soltrol® 130 or crude oil as the oleic phase. Rock samples are initially fully saturated with 0.63 mol/L of the selected aqueous solution. This is followed by injecting the selected oil at a constant rate for at least 20 pore volumes to displace brine. Next, selected brine is injected to displace oil, and finally distilled water. For CaCl2 brine, distilled water injection is found to recover no additional oil of either type of oil. However, for seawater, the fines production observed during distilled water injection is found to reduce water relative permeability by two orders of magnitude when Soltrol® 130 is used and by three orders of magnitude when crude oil is used. The seawater experimental runs also brought about additional oil recovery during distilled water injection: 18% when Soltrol® 130 is used and 3.4% when crude oil is used. This last result can be attributed to the plugging of pores due to fines migration, which can divert further injected water into previously unswept pores. Cited as: Almutairi, A., Saira, S., Wang, Y., Le-Hussain, F. Effect of fines migration on oil recovery from carbonate rocks. Advances in Geo-Energy Research, 2023, 8(1): 61-70. https://doi.org/10.46690/ager.2023.04.06

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.

Nonylcyclohexanol polyethoxylate, a greener alternative of nonylphenol polyethoxylate endows sodium oleate solution high salt tolerance

Nonylphenol polyethoxylate (NPEOn) has been expected to enhance salt tolerance of system containing carboxylates, but banned in countries recently. Herein, a group of new surfactants, nonylcyclohexanol polyethoxylate (NCEOn) was formulated with sodium oleate (NaOA) into binary surfactant systems, to investigate their interaction towards salt tolerance, phase behavior, interface tension and lime soap dispersing requirement in brine with comparison of NPEO10. The results indicate that the salt tolerance of NaOA-NCEOn system increased with increasing NCEOn concentration and EO number, following the order towards the salts: SO42- > Cl- for anions and Na+ > Mg2+ > Ca2+ for cations, respectively. Moreover, cloud point (CP) of NaOA-NCEOn system was increased by adding NaOA but decreased by introducing inorganic salts, respectively. The influence strength of cationic ions on CP decline was in the order: Na+ < Mg2+ < Ca2+. The thermodynamic parameters at CP explains the difference in salt tolerance of NaOA towards monovalent and divalent cations. Notably, the NCEO11(0.02 %)-NaOA (0.05 %) system exhibited similar or superior salt-tolerance in NaCl (20 %) or CaCl2 (2 %) brine, as NPEO10 did. The solubility of NaOA in saline (0.1 %-5%) was up to thousand folds of that in water, suggesting NCEOn a green substitute for NPEO10 in the field.

How Brine Composition Affects Fly Ash Reactions: The Influence of (Cat-, An-)ion Type

Abstract Hypersaline brines can be solidified and stabilized via the hydraulic and pozzolanic reactions between fly ash(es) and calcium-based additives. Although recent work has examined fly ash reactivity in single-salt (“simple”) hypersaline brines (ionic strength, Im &amp;gt; 1 mol/L), the effects of mixed-salt solutions on fly ash reactivity remain unclear. Herein, the reactivity of a Class C (calcium oxide [CaO]-rich) or Class F (CaO-poor) fly ash mixture with calcium hydroxide is reacted in solutions bearing sodium chloride (NaCl), calcium chloride (CaCl2), magnesium chloride (MgCl2), sodium sulfate (Na2SO4), or combinations thereof for 1.5 ≤ Im ≤ 2.25 mol/L, from 1 week until 24 weeks. Expectedly, sulfate anions promote the formation of sulfate phases (i.e., ettringite, monosulfoaluminate, U-phase), while chloride anions induce the formation of Cl-AFm compounds (i.e., Kuzel’s and Friedel’s salt). Although the Class C fly ash’s reactivity is similar across different anions (for a fixed cation and Im), Class F fly ash shows a small change in reactivity depending on the anion present. NaCl suppresses (Class C and Class F) fly ash reactivity by up to 30 % as compared to neat CaCl2 and MgCl2-based brines. Thermodynamic modeling reveals that NaCl induces a considerable increase in pH—up to 13.7, where many hydrated phases of interest cease to be the major phase expected—as compared to CaCl2 and MgCl2 brines (pH &amp;lt; 13). In mixed-salt brines, anion immobilization is competitive: sulfate achieves a greater level of incorporation into the hydrates, as compared to chloride. These results offer new understanding of how the brine composition affects solidification and stabilization and thereby yield new insight into improved approaches for wastewater disposal.

Simulation case studies of aqueous formate solution for geological carbon storage

Carbon storage in geologic formations has been considered an important technology that reduces the carbon intensity of industrial processes based on fossil fuels. Carbon capture and storage (CCS) conventionally uses carbon dioxide (CO2) as a carbon carrier. However, various shortcomings of the conventional CCS are related to the physical properties of CO2, such as low carbon density at low to moderate pressure, low mass density, low viscosity, immiscibility with water, and corrosivity. In particular, CO2 injection often results in inefficient use of pore space in the formation under geophysical heterogeneities.This paper presents case studies of using aqueous formate solution as carbon-bearing water for geological carbon storage. Properties of aqueous formate solutions were measured. Experimental results showed that the formate solubility in 102,600-ppm NaCl + CaCl2 brine ranged from 30 wt% to 35 wt% between 25 and 75 °C. Viscosities of 30 wt% formate solutions in the brine were approximately 12 cp at 25 °C, 5 cp at 50 °C, and 3 cp at 75 °C with Newtonian behavior.Numerical reservoir simulations were performed for an aquifer and an oil reservoir. Simulation results consistently showed that the formate injection case resulted in more stable fronts of oil and water displacement. The more stable fronts yielded the oil recovery and carbon storage that were insensitive to the injectant breakthrough. This is a substantial advantage of using formate as a carbon carrier for controlling the risk of CCS associated with the permeability heterogeneities and their impact on the subsurface flow regime.The case study of enhanced oil recovery and carbon storage in an oil reservoir showed that the net present value (NPV) of the formate injection case would be equivalent to that of the CO2 injection case when the cost of CO2 electrochemical reduction (ECR) into formate was $269/t-CO2 for year 20. The breakeven cost of CO2 ECR for the formate injection case was $575/t-CO2 for year 20. Although the estimated CO2 ECR costs are sensitive to many factors, they are not unrealistically higher than the current costs of CO2 ECR reported in the literature.

Brine Refrigerants for Low‐cost, Safe Aqueous Supercapacitors with Ultra‐long Stable Operation at Low Temperatures

AbstractTraditional aqueous energy storage devices are difficult to operate at low temperatures owing to the poor ionic conductivity and sluggish interfacial dynamics in frozen electrolytes. Herein, the low‐cost brine refrigerants for food freezing and preservation as electrolytes, and unexpectedly realize high ionic conductivity and stable operation of an aqueous storage device at low temperatures are demonstrated. A CaCl2 brine refrigerant electrolyte (BRE) with a low freezing point −55 °C and high ionic conductivity (10.1 mS cm−1 at −50 °C) is developed for supercapacitors (SCs), which retains 80% of the room temperature capacity at −50 °C and exhibits ultra‐long cycle life with excellent capacity retention of 92% over 98,500 cycles, outperforming the other SCs which can be operated below −40 °C in literature. Moreover, the SCs with MgCl2 and NaCl BREs can also be operated successfully with excellent cycle stability and high‐capacity retention at low temperatures of −30 and −20 °C, respectively. Fundamental correlation between various cations and their effect on the freezing point reduction of aqueous electrolytes is revealed via Raman investigation and molecular dynamics simulations. This study provides a rational design strategy for green, inexpensive, and safe low‐temperature aqueous electrolytes for energy storage devices.

Effects of brine valency and concentration on oil displacement by spontaneous imbibition: An interplay between wettability alteration and reduction in the oil-brine interfacial tension

Brine fluids have recently been of high interest to enhanced oil recovery process in both academia and industry. Both diluted formation brines and specifically formulated brines were reported to improve crude oil displacement in porous rock, owing to either their bulk salinity or brine-type. Mechanisms for such an improvement were widely proposed, including microscopic interfacial phenomena: wettability alteration and reduction in the oil-brine interfacial tension (σ), although their synergistic or interlinked contributions were vaguely clarified. To elucidate insights into this “low-salinity” enhanced oil recovery, crude oil displacement by spontaneous imbibition was conducted in the current research with focus on the effects of brine valency and concentration. Monovalent (NaCl) and divalent (CaCl2) brines at elevated concentrations (10, 100, and 1000 mM) were examined as imbibing fluids. Changes in the three-phase contact angle and the crude oil-brine interfacial tension were also investigated. Imbibition results showed that NaCl brine at ‘suitable’ concentration (100 mM) displaced greater oil (95.8 %) than too-low (10 mM) or too-high (1000 mM) concentrations, and these monovalent brines displaced more effective than those of divalent CaCl2 due to an oil-wetting as a result of divalent ion bridging phenomenon. This echoes crucial influences of both brine valency and concentration. Since no direct individual contribution from either the contact angle or σ on the oil displacement was obtained, an interplay between these two parameters were thought to control. The imbibition results were a capillary-dominated process (capillary number < 2.1 × 10−6), re-confirmed by their correlations with the calculated capillary pressures and inverse Bond numbers. The findings revealed that in a given imbibition system a required σ is a wettability-dependent: water-wet system needs high σ to enhance a driving capillarity while oil-wet system prefers lower σ to weaken a resisting capillary force. Brine formula directly attributed to wettability and σ: NaCl brines secure water-wetting with high σ while CaCl2 brines reduced σ more effectively with an assured oil-wetting. Low-salinity enhanced oil recovery mechanism was thus found to be contributed from capillary effect, which was an interplay between the interfacial tension and wettability. Paring these two parameters by formulating imbibing brine to anticipate high oil recovery is crucial and of challenge.

Sorption of Eu on MX-80 Bentonite in Na–Ca–Cl Brine Solutions

Sorption of Eu on MX-80 Bentonite in Na–Ca–Cl Brine Solutions

A systematic study of Smart Water technology in improving the reservoir recovery performance

Smart Water flooding, as an emerged technique in improving reservoir performance, demands systematic research. Determining the effective range of water ionic concentration has erupted the argumentative debates. Along with this, there is still a requirement to identify the in-situ wettability change and optimum water concentration. This research navigates to improve water chemistry knowledge using a systematic scheme of experimental and simulation approaches by the contribution of monovalent (Na+) and divalent (Ca2+) ions. To do this, one-factor-at-a-time (OFAT) and design of experiments (DOE) methods were employed to conduct contact angle and interfacial tension (IFT) measurements. Then, water force displacement tests and reservoir simulations were run to ascertain the in-situ changes and optimum brine concentration considering relative permeability, fractional flow, and ultimate oil recovery curves. In conclusion, two new analytical/empirical models were generated to predict contact angle and IFT based on brine concentration. The effective range of brine concentration was found to be 1000 to 15,000 ppm NaCl and 15,000 to 20,000 ppm CaCl2 in sandstone and 1000 to 10,000 ppm of both brines in carbonate. The IFT results showed the same range of concentration in sandstone, but irregular range in carbonate. In addition, according to water force displacement tests and simulation outcomes, the optimal value of Smart Water flooding was measured to be 8000 ppm NaCl-20,000 ppm CaCl2 brine concentration, resulting in about 4% increase in ultimate oil recovery. This study offers practical findings that advance water flooding technology understanding.

Evaluation of performance spectra of mono and divalent low saline brine injection in sandy-carbonates for mobilization of crude oil

Low salinity water (LSW) injection is one of the most economical methods of enhanced oil recovery (EOR) but its applicability as a waterflood was very limited. Also, its performance spectra significantly change when exposed to different rock compositions which need to be well understood. Thus, this study reports the impact of monovalent i.e., KCl and divalent i.e., CaCl2 salts (of varying concentration: 0–1 wt%) on rock/fluid interaction and oil recovery from rocks of different compositions (sandstone and sandstone + carbonate). Interfacial tension (IFT) measurements, between brine and crude oil, suggested minimum IFT for KCl brine and CaCl2 brine of 0.25 and 0.1 wt%, respectively. The variation in rock composition significantly affected the solution activity (via zeta potential) of KCl and CaCl2 brines, and brines exhibited maximum change in solution activity and adsorption of ions for the rock samples showing a compositional shift towards carbonate. Finally, flooding experiments were conducted wherein, initially porosity was found to be greater in sandstone (29.4%) as compared to carbonate (24.3%) rock composition. Finally, oil recovery and water cut profiles were obtained for different rock samples flooded by KCl and CaCl2 brines and compared with the ones of the conventional water flooding method. The results showed better performance of low saline brine injection which further improved when tests were performed for synthetic rock samples of pure carbonate (0% sandstone + 100% carbonate). A maximum oil recovery of 51% OOIP (original oil in place) was obtained for 100% sandstone while 100% carbonate demonstrated maximum oil recovery of 59% OOIP. Also, the impact of high temperature (90 °C) on these results was tested for promoting the role of low saline brine injection in carbonate reservoirs of complex conditions. Increasing the temperature further increased the amount of oil recovered to 61% OOIP, demonstrating the high efficacy of LSW at high temperatures.