Oil-brine Interface Research Articles

Oil storage and debrining process in insoluble sediment voids for underground salt cavern energy storage: An experimental study

Large salt cavern oil storage is an effective underground oil storage method, which has been widely used in the United States, Germany, and France. However, the insoluble impurity sediment particles at the bottom of the salt cavern will occupy plenty of oil storage space. To enhance the oil storage capacity, the sediment void oil storage (SVOS) method was proposed. The debrining process from the sediment void prerequisite of the SVOS. It will affect the feasibility of oil injection into the sediment void and the operation efficiency of SVOS. Thus, a self-made debrining device of SVOS was built, and the dynamic debrining process in the sediment void was investigated to explore the debrining process from the sediment void. Six debrining parameters (oil-brine interface change, oil injection rate, brine discharge rate, oil viscosity, the second oil injection quantity, and ground temperature) were proposed and considered. Two kinds of oils (diesel and petrolatum) were conducted in the SVOS debrining experiments. The experimental results showed that the debrining rate remained stable, and it was relevant to the oil injection rate and the interaction of oil and sediments. The average debrining rate of the initial diesel debrining, second diesel debrining, and petrolatum debrining were 2.5 g/s, 2.55 g/s and 2.40 g/s, respectively. The 50 °C of ground temperature sped the debrining rate of high-viscosity oil storage in the sediment void. The oil-brine interface kept balance from the macro perspective, and the oil did not penetrate the inner brine. The oil-brine interface drops ratio of the initial diesel debrining, second diesel debrining, and petrolatum debrining process were 0.586 mm/s, 0.629 mm/s and 0.592 mm/s, respectively. The oil in the sediment voids generated movable and immobile bubbles. The petrolatum flow in the sediment void was easier than the diesel due to the low viscosity at 50 °C. The research has a certain reference value for the development of underground salt cavern oil storage.

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.

A triple-layer based surface complexation model for oil-brine interface in low-salinity waterflooding: Effect of sulphate interaction with carboxylic and basic groups, pH and temperature

The determination of the electrokinetic properties of oil-brine interface is necessary to understand and evaluate the low-salinity waterflooding (LSWF) effect on enhanced oil recovery (EOR). Among the least understood aspects are the effect of SO42- interaction with the polar oil components, and temperature on the zeta-potential of the oil-brine interface. Therefore, a novel triple-layer based surface complexation model (SCM) was developed to capture the effect of SO42- interaction with both carboxylic and amine sites. One of the key uncertainties in a SCM is the surface site density of the functional groups. In this regard a Monte-Carlo based optimization algorithm for determination of these parameters as a function of pH and brine composition was devised. The SCM was successfully validated with the published zeta-potential data and was further used to evaluate the electrokinetic properties of oil-brine interface in a wide range of temperature and pH and to unravel the reason behind positive oil-brine zeta-potential at high ionic strength and pH, as reported for some crude oils in the literature. A sensitivity analysis was conducted to determine the relative contribution of site densities of carboxylic and amine groups as well as the capacitances to the oil-brine zeta-potential. The results clearly show that the interaction of SO42- ions with both carboxylic and particularly amine groups affects the surface potential significantly, thus should not be underestimated. Presence of SO42- in Na2SO4 and MgSO4 brines results in an incremental negative zeta-potential compared to that in NaCl and MgCl2 brines; confirming its role in changing charge distribution in the Stern layer. If these interactions are ignored, it should be compensated for by artificially adjusting concentration of positively and neutrally charged surface species. One important finding is that, despite the common perceptions, the site density of the oil polar groups is not constant and should be changed as pH and brine composition are changed and linear correlations between acid and base number and site densities are not justifiable. It is also found that zeta-potential tends to shift to neutral values as temperature is elevated due to the increased adsorption of divalent cations to the interface. The findings of this paper can help predict the zeta-potential of oil-brine interface more accurately and explain the observed trends in the experimental data.

Forecasting the Problem of Excessive Oil Entrainment in a Desalter Using Spinning Drop Method.

Frequent desalter upsets in the refineries processing opportunity crude oils are often triggered by a rapid and uncontrollable buildup of the rag layer, a thick water-in-oil emulsion, at the oil-brine interface. This is caused by spontaneous emulsification of brine in oil. This study investigates a unique observation from a spinning drop (SD) tensiometer, revealing the low apparent interfacial tension and rigidity of SD caused by spontaneous emulsification. Fine droplets of brine generated through spontaneous emulsification decorate the SD surface and form a stable, low-energy bilayer. Simulated rag layers using the brines from upset incidences exhibit similar behavior, indicating that spontaneous emulsification is driven by chemical species in brine, which promote osmotic water transport. The rate of rag layer buildup correlates with the rate of spontaneous emulsification, with the temperature coefficient of interfacial tension reduction serving as a sensitive indicator. An imminent upset in the operation can be forecasted by measuring this temperature coefficient, enabling preventive measures.

Fluid-fluid interfacial properties during low salinity waterflooding

Understanding the fluid–fluid interfacial interactions is critical to enhancing oil recovery, underground CO2 storage, and soil remediation. Fluid-fluid interfacial interactions were identified as key parameters to govern fluid–fluid interfacial properties. In this investigation, we aim to evaluate the properties of the oil-brine interface in function of fluid compositions during low salinity waterflooding (LSW). Specifically, the main target is to unravel the oil-brine structure, including orientation of the carboxylic group (–COOH), interfacial structure, and species distribution. We utilized molecular dynamics (MD) simulation to evaluate the species distribution and surface structure at the molecular scale. The MD results showed that the carboxylic group accumulated near the oil-brine interface. The orientation of C=O in the carboxylic group is closer to 90° in the brines with all salinity ranges, which is perpendicular to the oil-brine interface. The accumulation and orientation of the carboxylic group is, however, not sensitive to salinity variations. Furthermore, the oil-brine interfacial area turns to be wider with lowering salinity. Radial distribution function (RDF, g(r)) confirmed that lowering salinity decreases g(r) between –COOH and water and thus looses the affinity of oil to water. This investigation provides insights into the fluid–fluid interfacial properties of LSW at the molecular level.

Static and dynamic adsorption of a gemini surfactant on a carbonate rock in the presence of low salinity water

In chemical enhanced oil recovery (cEOR) techniques, surfactants are extensively used for enhancing oil recovery by reducing interfacial tension and/or modifying wettability. However, the effectiveness and economic feasibility of the cEOR process are compromised due to the adsorption of surfactants on rock surfaces. Therefore, surfactant adsorption must be reduced to make the cEOR process efficient and economical. Herein, the synergic application of low salinity water and a cationic gemini surfactant was investigated in a carbonate rock. Firstly, the interfacial tension (IFT) of the oil-brine interface with surfactant at various temperatures was measured. Subsequently, the rock wettability was determined under high-pressure and high-temperature conditions. Finally, the study examined the impact of low salinity water on the adsorption of the cationic gemini surfactant, both statically and dynamically. The results showed that the low salinity water condition does not cause a significant impact on the IFT reduction and wettability alteration as compared to the high salinity water conditions. However, the low salinity water condition reduced the surfactant’s static adsorption on the carbonate core by four folds as compared to seawater. The core flood results showed a significantly lower amount of dynamic adsorption (0.11 mg/g-rock) using low salinity water conditions. Employing such a method aids industrialists and researchers in developing a cost-effective and efficient cEOR process.

The stabilization of oil-bound thin brine films over a fixed substrate with electrically charged surfactants subject to van der Waals and electrostatic forces

Enhanced oil recovery through low salinity water flooding has been attributed to increased rock-to-water wettability due to the stabilization of a thin brine film between the rock and the oil phase resulting from the expansion of the electric double layer. However, the underlying physicochemical mechanisms are not well understood and an electrohydrodynamic approach to the thin film dynamics helps to better understand its evolution to equilibrium states. Lubrication theory is applied to a thin brine film bounded by a viscous phase with diffusing charged surfactants at the oil–brine interface under van der Waals and electrostatic interactions. Linear analysis and numerical solutions of the nonlinear governing equations are carried out and linear stability diagrams indicate that disturbances evolve in oscillatory or non-oscillatory modes. In addition to the expansion of the electric double layer, other physicochemical mechanisms affect the stabilization of the brine film. Among them are the (secondary) ionic hydration within the brine, surface charge concentrations, diffusion of surface-active species, as well as Marangoni, tangential and normal stresses. In the nonlinear regime, the van der Waals attraction leads to rupture in regions where the film is narrower since primary hydration is not considered. The oil–brine interface may be negatively or positively charged and different mechanisms can change the wettability of rock formations. Including hydration forces led to nonlinear metastable states, in addition to linearly stable states. The findings help design ’smart waters’ based on modifying the properties of surfaces and adjacent fluids of thin liquid films in order to drive positively or negatively charged rock formations into more water-wet states.

Evaluation of sour gas-low salinity waterflooding in carbonate reservoirs - A numerical simulation approach

Although significant amount of H2S (sour gas) rich natural gas is estimated globally, but not much attention has been given to the application of H2S in the oil recovery process. Recent studies on the use of H2S in oil recovery processes showed that H2S has the potential of improving the oil recovery, and it can be even more effective than using CO2 in some processes. H2S can equally dissolve in the water, react with the reservoir rock to change its surface charge, porosity, and permeability. However, previous investigations on H2S oil recovery attributed the improved oil recoveries to the higher miscibility of H2S in the oil, and the reduction in the oil viscosity. Therefore, there is limited understanding on the H2S-oil-brine-rock geochemical interactions, and how they impact the oil recovery process. This study aims to investigate the interactions between H2S, oil, and carbonate formations, and to assess how the combination of H2S and low salinity water can impact the wettability and porosity of the reservoirs. A triple layer surface complexation model was used to understand the influence of key parameters (e.g., pressure, brine salinity, and composition) on the H2S-brine-oil-rock interactions. Moreover, the effects of mineral content of the carbonate rock on H2S interactions were studied. Thereafter, the results of the H2S-oil-brine-rock interactions were compared with a study where CO2 was used as the injected gas. Results of the study showed that the seawater and its diluted forms yielded identical ζ-potential values of about 3.31 mV at a pH of 3.24. This indicates that at very low pH condition, pH controls the ζ-potential of the oil-brine interface regardless of the brine's ionic strength. The study further demonstrated that the presence of other minerals in the carbonate rock greatly reduced the calcite dissolution. For instance, the calcite dissolution was reduced by 4.5% when anhydrite mineral was present in the carbonate rock. Findings from the simulation also indicated that CO2 produced negative ζ-potential values for the carbonate rocks, and these values were reduced by 18.4%–20% when H2S was used as the gas phase. This implies that the H2S shifted the carbonate rock ζ-potentials towards positive. The outcomes of this study can be applied when designing CO2 flooding and CO2 storage where the gas stream contains H2S gas since H2S greatly influences the dissolution of the carbonate mineral.

Synergy of surface modified nanoparticles and surfactant in wettability alteration of calcite at high salinity and temperature

The surface of silica nanoparticles (NPs) was modified by chemical grafting of ligands to: (1) achieve colloidal stability in concentrated brine at salinities up to 25.7 % total dissolved solids (TDS) and temperatures up to 90 °C and (2) change the wettability of carbonate reservoirs from oil-wet to water-wet. The ligand precursors included low molecular weight cationic N-trimethoxysilylpropyl-N, N, N-trimethylammonium chloride or nonionic 3-glycidyloxypropyl trimethoxysilane. The water-phase contact angle θw of a crude oil droplet on calcite was measured for binary mixtures of the modified NPs combined with different types of surfactants, for a heavy and a light crude oil. For two types of reservoir conditions (16.7 % TDS at 55 °C and 25.7 % TDS at 90 °C), positively charged NPs with quaternary nitrogens (QNP) at 1 wt% altered the wettability of the calcite surface from strongly oil-wet (θw = 125° to 159°) to intermediate wet with a θw = 69° to 85° for light crude oil and θw = 71° to 107° for heavy crude oil. Meanwhile, cationic surfactants tetradecyltrimethylammonium bromide (TTAB) at 1 wt% altered the wettability to water-wet with a θw = 41° to 59° for light crude oil and θw = 70° to 90° for heavy crude oil. Synergy between the QNP and TTAB was observed in lowering the θw by another 10°. The reduced θw is beneficial for secondary oil recovery from carbonates, along with a significant decrease in the viscoelasticity of the crude oil-brine interface that helps destabilize undesirable water-in-crude oil emulsions.

Experimental measurement of the exclusion-diffusion potential in sandstone and shaly sand samples at full and partial water saturation

The exclusion-diffusion potential (EDP) arises in response to concentration gradients and is one of the key components of the self-potential (SP) observed in subsurface environments. However, few data are available to characterize the EDP in reservoir rocks saturated with complex natural brines and at partial brine saturation. We report experimental measurements of the EDP across fully and partially brine-saturated sandstone samples and fully brine-saturated shaly sand samples, using natural saline brine (2.2 Mol/L), seawater (0.5 Mol/L), and natural crude oil. When fully saturated, the EDP across the samples is diffusion-dominated, with the shaly samples exhibiting a small contribution from charge exclusion. The contribution of charge exclusion to the measured EDP increases as permeability decreases. At the residual oil saturation, the measured EDP is diffusion-dominated, consistent with our findings at full saturation. However, the EDP is more exclusive at the irreducible water saturation, and the polarity of the excluded ions depends on the polarity of the charged oil-brine interface. A charge exclusion is more significant at lower irreducible water saturation. Our results support recent studies suggesting that the oil-brine interface can be positively charged in contact with natural brines. The EDP trends reported have not been observed previously and have broad implications for geophysical monitoring of subsurface flow and transport, such as transport of nonaqueous phase contaminants in aquifers and water flow during hydrocarbon production.

The mechanistic investigation on the effect of the crude oil /brine interaction on the interface properties: A study on asphaltene structure

• The Asphaltene molecular Structure was determined by ATR and EDAX analysis. • the Asphaltene adsorption rate at the interface highly depends on the brine salinity. • compaction of the Asphaltene molecules Structure significantly affects the adsorption behavior of the Asphaltene. • The concentration of Asphaltene fraction in the crude oil has a key role in fluid–fluid interaction. • Asphaltene molecules accumulate at the oil-brine interface and perform the Asphaltene-ion-bound with the dissolved ions. Despite many attempts to study the interaction of fluids in low-salinity flooding, they do not examine the principles of interphasic transition phenomena. This study aims to provide a new understanding of liquid–liquid interactions during the low-salinity water interaction through a series of experiments on the oil, emulsion, and aqueous phase. Three samples of crude oils with different asphaltene concentrations and structures with known physical properties are in contact with different solutions. The brine pH, conductivity, and crude oil viscosity experiments before and after contacting the oil with brine showed that the heteroatom concentration and compaction of crude oil asphaltene fraction and the brine salinity affect the rate of the migration of crude oil polar component toward the interface. Moreover, the IFT measurement illustrated that interface interactions are affected by several parameters such as dissolved ion type, the concentration of the brine, and the concentration of the polar components in crude oil. The solubility of crude oil polar species such as naphthenic acids in the brine does not always increase by decreasing the salinity of the aqueous phase. To verify this important finding, UV–Vis spectroscopy and FTIR were performed on the brine and crude oils before and after in contact with each other.

Ionic Interactions at the Crude Oil-Brine-Rock Interfaces Using Different Surface Complexation Models and DLVO Theory: Application to Carbonate Wettability.

The impact of ionic association with the carbonate surface and its influence toward carbonate wettability remains unclear and is an important topic of interest in the current literature. In this work, a triple layer model (TLM) approach was used to capture the electrokinetic interactions at both calcite–brine and oil–brine interfaces. The developed TLM was assembled against measured ζ-potential values from the literature, successfully capturing the trends and closely matching the ζ-potential magnitudes. The developed TLM was compared to a diffused layer model (DLM) presented in previous works, with the DLM showing a better match to the ζ-potential values for seawater brine solutions. The ζ-potential values predicted from both surface complexation models (SCMs) were used to calculate the total interaction energy (or potential) based on the Derjaguin, Landau, Verwey, and Overbeek (DLVO) theory. It was observed that low Mg2+ and high SO42– concentrations in modified composition brine (MCB) made the calcite–brine interface more negative. However, at the oil–brine interface, low Mg2+ made the oil–brine interface more negative but high SO42– concentrations slightly shifted the oil–brine ζ-potential toward negative. At the crude oil–brine–rock (COBR) interfaces, low Mg2+ and high SO42– concentrations in the MCB were observed to generate a greater repulsive interaction energy, which could trigger carbonate wettability alteration toward water wetness. The absolute sum of the ζ-potential at both interfaces was observed to be correlated to the total interaction potential at a 0.25 nm separating distance. Thus, an increase in the absolute sum of the ζ-potentials would generate a greater repulsive interaction potential and trigger wettability alteration. Therefore, these SCMs can be applied to design modified composition brine capable of triggering a repulsive interaction energy to alter carbonate wettability toward water wetness.

A calibrated surface complexation model for carbonate-oil-brine interactions coupled with reservoir simulation - Application to controlled salinity water flooding

Vast majority of past studies that have been conducted on controlled salinity water flooding (CSWF) use diffuse layer model (DLM) that calculates only the surface potential, which can be significantly different from the ζ-potential of the interface. Importantly, stability of the water-film (between the oil and the rock surface) which dictates ultimate oil recovery is related to ζ-potential. As such, using DLM calculated surface potential (directly) for CSWF can be misleading. Additionally, most of the existing DLMs use integer charges instead of fractional charges to model carbonate-brine interactions, which may not represent the actual carbonate crystallographic. We present a triple layer surface complexation model (TLM) which offers the option to locate and distribute charge of the adsorbing ion(s) at three locations. TLM can therefore calculate potentials at three different locations within the Stern layer. To the best of our knowledge, only few authors have used TLM to simulate CSWF. However, some surface reactions were ignored in these models. For instance, adsorption of monovalent ions such as Na + and Cl − ions was ignored in some of the few available TLMs. Also, the effect of basic-oil components was not considered in some TLMs, and lastly, some TLMs used integer charges for the carbonate surface group. This study introduced a comprehensive TLM that includes all these complexities. Moreover, we introduced a new wettability indicator (WI) that is related to the electrostatic forces between the oil-brine and the rock-brine interfaces. That is, WI was calculated from ζ-potentials at the oil-brine and rock-brine interfaces. The TLM, built in a geochemical simulator, PHREEQC, was then coupled with UTCHEM, a multiphase reservoir simulator. The developed simulator based on the TLM-CSWF model was tested against several experimentally measured oil recovery data sets. Results of the model suggest that Oil basic component significantly impacts oil-brine interface ζ-potential irrespective of temperature, brine composition, and ionic strength. On the otherhand, Na + ions in brine may influence oil-brine ζ-potential, and this relates to temperature, brine composition, and ionic strength. The results further suggest that injection of (sulfate-free) diluted brine in chalk resulted to increased oil adhesion, shifting the reservoir to oil-wet condition. Hence, no additional oil is recovered with this brine injected at tertiary oil recovery stage. Finally, the results showed that wettability is related to ζ-potentials at the oil-brine and rock-brine interfaces, and the carbonate rock would be strongly oil-wet or water-wet only at significantly large magnitude of ζ-potentials at the interfaces. • A new triple-layer surface complexation model developed to characterize carbonate-brine-oil interactions. • The model is tested against several experimentally measured zeta potential and oil recovery data sets. • The model suggests that SO 4 −2 ion adsorption tends to decrease CO 3 −2 adsorption at the rock surface and vice-versa. • The model showed that only a small fraction of the carbonate-oil-brine reactive sites are involved in the geochemical reactions.

Investigation of Influential Parameters on Oil/Water Interfacial Tension During Low-Salinity Water Injection

Abstract Injecting low-salinity water has proved to be an efficient displacement process in oil reservoirs, owing to its ability to modify the properties at the fluid-rock and fluid-fluid interfaces in favor of mobilizing more oil. In this regard, reduction of interfacial tension (IFT) between oil and water is one of the key controlling parameters. It is suspected that the asphaltene constituents of the oil and type of water ions are responsible for such a reduction in IFT. In this study, systematic experimental investigations were carried out to scrutinize the influence of brine salinity, asphaltene concentration, and temperature on IFT. Single and multi-component brines, which in particular compose of NaCl, CaCl2, and MgCl2 salts, and two synthetic oils with 1 and 10 wt% asphaltene content were used at temperatures ranging from 25 to 80 °C. The results showed that the presence of salt in the solution can alter the distribution of polar components at the oil-brine interface due to the electrostatic effects, which in turn would change IFT of the system. IFT also decreased when temperature increased from 25 to 80 °C; however, the level of changes was strongly depended on the brine type, salinity level, and asphaltene content. The results also demonstrated that the crude oil with the higher asphaltene concentration experiences higher IFT reduction when is contacted with the low-salinity water. The new findings from this study will improve the understanding of the underlying mechanisms for low salinity water flooding in oil reservoirs.

Triple-layer surface complexation modelling: Characterization of oil-brine interfacial zeta potential under varying conditions of temperature, pH, oil properties and potential determining ions

Low salinity water flooding (LSWF) is a popular enhanced oil recovery technique. Among factors that affect the performance of LSWF, geochemical interaction at the oil-brine interface and the associated enterokinetic properties plays a prominent role. This work presents a triple-layer surface complexation model for predicting the zeta potential of the oil-brine interface. We improve upon previous modelling studies by incorporating the effects of (1) temperature variation, (2) basic (-NH) oil surface group interactions (3) adsorption of sodium ions on outer and inner Helmholtz planes and (4) the presence of sulphate ions in brine. Model validation against published experimental data shows model accuracy between 66% and 99%. The model displays higher accuracies at lower salinities (making it particularly suited for LSWF applications), intermediate pH and higher total acid number. In addition, a correlation between (-NH) site density and total acid/base numbers is proposed. A sensitivity study performed utilising the developed model showed that higher sulphate concentration in the brine and elevated temperature makes the zeta potential at the oil-brine interface more negative. In addition, the sensitivity study indicates that a higher concentration of basic polar oil compounds is less favourable as it may result in less water-wet conditions in the reservoir.

Phase Behavior and Interfacial Properties of Salt-Tolerant Polymers: Insights from Molecular Dynamics Simulations

Mobilization of the capillary trapped oil beyond the conventional recovery methods is essential to enhance the oil extraction process and meet the global energy demands. Partially hydrolyzed polyacrylamide (HPAM) is a water-soluble polymer widely used to control the mobility ratio between the injected and displaced fluids to improve the sweep efficiency. However, its viscosifying capacity is substantially affected by the harsh reservoir conditions (high temperature and high salinity conditions). Using equilibrium molecular dynamics simulations and well-tempered metadynamics, we have investigated the effect of sidechain sulfonation on the polyacrylamide (PAM) phase behavior and interfacial properties. The sulfonated polymer exhibits weak interactions with the brine’s cations; it interacts almost equally with Na+ and Ca2+, while it displays an even weaker interaction with Mg2+ ions. Contrarily, the pristine HPAM shows stronger and specific interactions with Ca2+ and Mg2+ ions. Furthermore, HPAM encapsulates the metal cations, which induce a significant conformational contraction, leading to viscosity reduction. Combining our results and the reported works of the literature, the salt tolerance and the thermal stability of this kind of polymer originate from the sulfonated sidechain–ion weak interactions and its slower hydrolysis compared to the acrylamide group. Finally, the interfacial properties of the sulfonated polymer at the oil–brine interface are examined. These findings can help to enrich our understanding of the polymer salt tolerance and thermal stability in order to design polymers with better performance.

Specificity and Synergy at the Oil–Brine Interface: New Insights from Experiments and Molecular Dynamics Simulations

The authors acknowledge the support of the KAUST Supercomputer Lab in Thuwal, Saudi Arabia, for permission to use its computational resources and Alfahd supercomputer of the college of petroleum engineering and geosciences (CPG).

Assessment of low salinity waterflooding in carbonate cores: Interfacial viscoelasticity and tuning process efficiency by use of non-ionic surfactant

Hypothesis. A large number of papers discuss merits and mechanisms of low salinity waterflooding. For each mechanism proposed, there are counter examples to invalidate the stated mechanism. The effect of wettability from low salinity water, which is predominantly stated in literature as the dominant mechanism, may not be valid. We introduce a direct correlation between oil-brine interfacial viscoelasticity and oil recovery from waterflooding.Experiments. The oil recovery is investigated in carbonate rocks for three light crude oils, by injection of a wide range of aqueous phases, ranging from deionized water to very high salinity brine of 28 wt%, and low concentration of a non-ionic surfactant at 100 ppm. The oil-brine interfacial viscoelasticity is quantified and supplementary measurements of interfacial tension and wettability are performed.Findings. In our experiments, oil recovery is higher from high salinity water injection than from low salinity water injection. A strong relationship is observed between interface elasticity and oil recovery for different concentrations of salt in the injected brine as well as for ultra-low concentration surfactant. An elastic oil-brine interface results in high oil recovery. The surfactant molecule we have selected prefers the oil–water interface despite high solubility in the oil phase and makes ultra-low concentration of 100 ppm in injection water very effective. Contrary to widespread assertions in the literature, we find no definitive correlation between oil recovery and wettability.

Molecular Transport across Oil-Brine Interfaces Impacts Interfacial Tension: Time-Effects in Buoyant and Pendant Drop Measurements.

The buoyant drop method is a ubiquitous tool for addressing phenomena at the liquid-liquid interface via the determination of the interfacial tension (IFT) between two immiscible phases. Here, the focus is on how electrolytes (in an aqueous phase) and carboxylic acids (in a decane phase) impact the interfacial layer between the two phases. The IFT measurement provides a single number, which is not fulfilling when it comes to deducing information about a complex multiparameter system. Furthermore, the temporal evolution of IFT does not always reach a steady-state value on a time scale, which is realistic to use for comparative studies. We have investigated the temporal evolution of IFT in a series of experiments with varying compositions of the decane-carboxylic acid phase and the brine phase. The results show that there are at least two opposing effects in play. For water-soluble acids, the IFT initially increases with time until a turnover point is reached from where there is a gradual decay. The IFT at the turnover point is close to that of the pure water-decane system. For a poorly water-soluble acid, the IFT shows a much smaller increase and the turnover happens much faster. For a water-soluble acid, there is a high degree of sensitivity toward the electrolyte; it determines the position (in time) of the IFT peak and the steepness of the subsequent decay. Now, if the phases are reversed, that is, by placing a drop of brine in the decane-surfactant phase, the IFT decreases with time regardless of the acid and with little impact of the electrolyte and its concentration in the brine. We propose an explanation for the observed behavior (supported by COSMO-RS calculations), which is based on diffusion in and out of the two phases, solubility, and interfacial reactivity (i.e., aggregation between electrolytes and carboxylic acids).

Effect of surface chemistry of silica nanoparticles on contact angle of oil on calcite surfaces in concentrated brine with divalent ions

HypothesisFor an oil droplet on calcite with an intervening brine film, the water contact angle θw may be reduced markedly (greater water wetness) with surface modified silica nanoparticles (NP). Modification with cationic, anionic, and nonionic ligands may be used to control the nanoparticle adsorption and interactions at the oil-brine and brine-calcite interfaces to influence the rate and degree of reduction in θw. ExperimentsThe colloidal stability at 25 °C was determined in concentrated divalent brine (8 wt% NaCl and 2 wt% CaCl2) with dynamic light scattering, and the NP adsorption was determined on calcite. The NP adsorption at the oil-brine interface was characterized with the elastic dilational modulus. θw was measured for model decane-stearic acid droplets and crude oil droplets on calcite from 25 to 80 °C. FindingsThe fastest rate and greatest extent of reduction in θw for grafted ligands followed the order: cationic quaternary trimethylamine > sulfonate > methyl phosphonate > gluconamide. New mechanisms for reduction in θw were demonstrated on the basis of changes in interactions from NP adsorption at each interface. The greatest efficacy for the cationic NPs results from the weakest adsorption on calcite, steric repulsion at the three-phase contact line and the greatest desorption of carboxylate surfactants from the calcite.