Low Salinity Water Effect Research Articles

The effect of low salinity water on wettability alteration of oil-wet calcite surfaces

To shed light on the chemical and physical aspects of low-salinity (LS) water flooding to enhance oil recovery, we explored the impact of the brine salinity on the modifications of the oil-calcite interface using a multi-technique surface science approach based on FTIR, AFM, XPS, and Contact angle measurements. Our findings reveal that Nujol-model oil adsorbs on fresh-cleaved CaCO3 (104) surface and initially forms a continuous film. Chemical and morphological surface characterizations were performed on oil-wet calcite, followed by their conditioning with formation (FW), demineralized (DW), and low salinity water (LS25, LS50, LS75, and LS100). The oil removal was quantified by semi-quantitative FTIR analysis and was found to vary from ∼20 % for FW up to ∼81 % for LS75 conditioning. In the investigated experimental conditions the fresh-cleaved calcite surface is most efficiently converted from oil-wet to water-wet when conditioned with LS75 brines. Significant surface wettability alterations were observed for LS 75 brines as contact angle measurements were found to reach a minimum contact angle of ∼18°. The changes in calcite wettability correspond to the formation of fragmented oil islands and calcite step bunches, the signature of surface dissolution, and changes in the oil-calcite chemical interactions. A model for Nujol adsorption and its detachment from the calcite surface was proposed for oil removal, competitive mechanisms related to the brine chemical composition are discussed.

Synergistic Effect of Low Salinity Surfactant Nanofluid on the Interfacial Tension of Oil–Water Systems, Wettability Alteration, and Surfactant Adsorption on the Quartz Surface

Interfacial tension (IFT) and wettability are the two major factors influencing oil recovery. The synergistic effect of low salinity water (LSW) with chemical agents such as surfactants, alkalis, and polymer is an emerging technology for enhanced oil recovery (EOR). Recently, the use of nanoparticles for EOR has become the attractive option. This study examines the impact of low salinity surfactant–silica nanofluid (LSS–SNF) on interfacial tension (IFT) and wettability alteration in an oil–water–quartz system using various types of oils, viz., n-heptane, n-decane, benzene, toluene, model oil A, model oil B, and crude oil. Besides, the adsorption of surfactants on the quartz substrate in the presence of silica nanoparticles is also studied. A quartz substrate is particularly chosen to mimic the sandstone formation. It has been observed that the type of oil has a crucial role in the IFT behavior, and different trends have been observed for model oil A and model oil B in the presence of LSS–SNF. Also, a prominent wettability shift is observed on the quartz substrate for the acidic (model oil A) than the other oil employed. Further, the adsorption studies using an ultraviolet–visible (UV–vis) spectrometer confirm the reduction in surfactant adsorption with an increase in silica nanoparticle concentration. The adsorption of surfactants is also confirmed using scanning electron microscopy (SEM) and energy-dispersive X-ray analysis (EDXA), and the order of adsorption is identical to the Freundlich adsorption isotherm. The outcomes of this study will help us understand the application of silica nanofluid in EOR operation.

Low Salinity Water–Polymer Flooding in Carbonate Oil Reservoirs: A Critical Review

AbstractLow salinity water–polymer flooding (LSWPF) is an emerging hybrid enhanced oil recovery (EOR) method that uses the synergetic effects of low salinity water (LSW) and polymers to enhance both the microscopic and macroscopic sweep efficiencies. Polymer flooding is an EOR method that aims to increase water viscosity and improve the mobility ratio of the injected fluid to the reservoir. It enhances mobility control and reduces water relative permeability, reaching a more favorable condition for sweep efficiency. LSW is an EOR method that aims to change wettability by exploiting crude oil and reservoir rock interactions. It allows for improving oil recovery when the injected water has a very low salinity compared to seawater or formation water. The literature reports LSWPF studies applied to sandstone reservoirs. However, LSWPF applications in carbonate reservoirs still lack. This review critically analyzes LSWPF as an alternative to Polymer flooding using seawater in carbonate reservoirs.

A Numerical Study of Tertiary Oil Recovery by Injection of Low-Salinity Water

The injection of Low Salinity Water (LSWI) as an Enhanced Oil Recovery (EOR) method has recently attracted a lot of attention. Extensive research has been conducted to investigate and identify the positive effects of LSWI on oil recovery. In order to demonstrate the impact of introducing low salinity water into a reservoir, simulations on the ECLIPSE 100 simulator are being done in this work. To simulate an actual reservoir, an easy static model was made. In order to replicate the effects of injecting low salinity water and normal salinity, or seawater, the reservoir is three-phase with oil, gas, and water. It has one injector and one producer. Five cases were suggested to investigate the effect of low salinity water injection with different concentrations and the period of injection. The low salinity injection period varied from twenty-five years in case one and reduced five years in each case until reached to five years in final case. Higher oil recovery factor obtained in case one with injection time twenty-five years and lower recovery factor for case five with injection time of low salinity water injection five years. Lower water concentration gives higher oil recovery for all cases where this study investigated the effect of low-salinity water flooding as slug injection. From the five cases presented, field oil recovery factor (FOE), field oil production rate (FOPR), field oil production total (FOPT), field pressure (FP), and field water cut (FWCT) were observed. Oil recovery is 56.6 percent in high salinity water flooding (HSWF), and 71.8 percent in low salinity water flooding (LSWF) for 0 percent salt concentration and 62.40 percent for 20 percent salt concentration as in case one.

Effects of the Reservoir Environment and Oilfield Operations on the Iron Mineral Surface Charge Development: An Insight into Their Role in Wettability Alteration

Iron minerals are hydrophobic minerals predominately found in sandstone formations with their role in wettability alteration not fully understood. With the reservoir rock being a complex system of multiple minerals, the control of wettability alterations becomes difficult to manage due to the different surface chemistry of constituent minerals. This study presents for the first time the surface charge development of pyrite, magnetite, and hematite minerals in native reservoir environments and the effect of oilfield operations such as acidizing, water injection, polymerization, surfactant flooding, and alkaline flooding on iron minerals, surface charge development. This was achieved using zeta potential measurement, which depicts the type of surface charge and infers the propensity of precipitation. The experimental results show that pyrite, magnetite, and hematite behave similarly under reservoir conditions with all the minerals being positively charged although pyrite and hematite are negatively charged in seawater (SW). Results also show that the surface charge development is controlled by the electrical double-layer effect and ion adsorption on the mineral surfaces. These findings provide key insights into the role of iron minerals in wettability alteration as they provide surfaces that serve as a precursor for polar crude component adsorption. Also, the design of an ion-engineered fluid to control the surface charge of iron minerals was implemented, and the results showed that they behave differently. Furthermore, the effect of low-salinity water on the mineral surface charge was examined. The findings revealed that low-salinity water can produce a negatively charged surface, however, cannot mitigate the iron mineral precipitation challenge as the observed zeta potential values are near zero. Finally, slug and continuous injection of the ethylenediaminetetraacetic acid chelating agent was implemented as an iron mineral precipitation control strategy, with the continuous injection observed to significantly improve the colloidal stability of the iron minerals in the reservoir native state and after SW injection.

Effects of low-salinity water on the interface characteristics and imbibition process

Spontaneous imbibition is an important recovery method of low permeability and tight reservoirs. However, the mechanism and influencing factors of imbibition on the addition of low-salinity brine are seldom studied. In this study, the effects of ion type and concentration on the interfacial properties and the oil recovery of imbibition with low-salinity water were investigated by measuring the oil-water interfacial tension, contact angle and recovery of imbibition. The effects of temperature, pressure and other factors on the imbibition recovery under low-salinity conditions were analyzed. The results showed that the oil-water interfacial tension gradually increased with decreasing salinity of solutions at low salinity conditions, among which Ca 2+ had the greatest influence on the oil-water interfacial tension. With decreasing salinity, the contact angle decreased. The contact angle showed the largest variation (22.14°) during the dilution process of formation water. The solutions of different ion types showed a different production rate and oil recovery by imbibition, among which the NaCl solution with a concentration of 5000 mg/L had the highest oil recovery. Moreover, the oil recovery of imbibition increased with increasing temperature. Compared with low pressure, the production rate in the early stage under high pressure conditions was obviously improved. With increasing pH value, the oil recovery also increased. • Low-salinity water have remarkable effect on the performance of imbibition in low-permeability cores. • Different ions of different concentrations have different effects on IFT, CA and oil recovery of imbibition. • The mechanism of EOR for imbibition of low-salinity water is the combination of low IFT and good wettability alteration.

Data-Driven Analyses of Low Salinity Waterflooding in Carbonates

Low salinity water (LSW) injection is a promising Enhanced Oil Recovery (EOR) technique that has the potential to improve oil recovery and has been studied by many researchers. LSW flooding in carbonates has been widely evaluated by coreflooding tests in prior studies. A closer look at the literature on LSW in carbonates indicates a number of gaps and shortcomings. It is difficult to understand the exact relationship between different controlling parameters and the LSW effect in carbonates. The active mechanisms involved in oil recovery improvement are still uncertain and more analyses are required. To predict LSW performance and study the mechanisms of oil displacement, data collected from available experimental studies on LSW injection in carbonates were analyzed using data analysis approaches. We used linear regression to study the linear relationships between single parameters and the incremental recovery factor (RF). Correlations between rock, oil, and brine properties and tertiary RF were weak and negligible. Subsequently, we analyzed the effect of oil/brine parameters on LSW performance using multivariable linear regression. Relatively strong linear correlations were found for a combination of oil/brine parameters and RF. We also studied the nonlinear relationships between parameters by applying machine learning (ML) nonlinear models, such as artificial neural network (ANN), support vector machine (SVM), and decision tree (DT). These models showed better data fitting results compared to linear regression. Among the applied ML models, DT provided the best correlation for oil/brine parameters, as ANN and SVM overfitted the testing data. Finally, different mechanisms involved in the LSW effect were analyzed based on the changes in the effluent PDIs concentration, interfacial tension, pH, zeta potential, and pressure drop.

Numerical modeling and experimental investigation on the effect of low-salinity water flooding for enhanced oil recovery in carbonate reservoirs

Numerous studies concluded that water injection with modified ionic content/salinity in sandstones would enhance the oil recovery factor due to some mechanisms. However, the effects of smart water on carbonated formations are still indeterminate due to a lack of experimental investigations and researches. This study investigates the effects of low-salinity (Low Sal) solutions and its ionic content on interfacial tension (IFT) reduction in one of the southwestern Iranian carbonated reservoirs. A set of organized tests are designed and performed to find each ion’s effects and total dissolved solids (TDS) on the candidate carbonated reservoir. A sequence of wettability and IFT (at reservoir temperature) tests are performed to observe the effects of controlling ions (sulfate, magnesium, calcium, and sodium) and different salinities on the main mechanisms (i.e., wettability alteration and IFT reduction). All IFT tests are performed at reservoir temperature (198 °F) to minimize the difference between reservoir and laboratory-observed alterations. In this paper, the effects of four different ions (SO42-, Ca2+, Mg2+, Na+) and total salinity TDS (40,000, 20,000, 5000 ppm) are investigated. From all obtained results, the best two conditions are applied in core flooding tests to obtain the relative permeability alterations using unsteady-state methods and Cydarex software. The final part is the simulation of the whole process using the Schlumberger Eclipse black oil simulator (E100, Ver. 2010) on the candidate reservoir sector. To conclude, at Low Sal (i.e., 5000 ppm), the sulfate ion increases sulfate concentration lower IFT, while in higher salinities, increasing sulfate ion increases IFT. Also, increasing calcium concentration at high TDS (i.e., 40,000 ppm) decreases the amount of wettability alteration. In comparison, in lower TDS values (20,000 and 5000 ppm), calcium shows a positive effect, and its concentration enhanced the alteration process. Using Low Sal solutions at water cut equal or below 10% lowers recovery rate during simulations while lowering the ultimate recovery of less than 5%.

Numerical Simulation of the Combined Effects of Low Salinity Water and Alkaline-Surfactant-Polymer Flooding

Low Salinity Water (LSW) and Alkaline-Surfactant-Polymer (ASP) flooding are emerging enhanced oil recovery methods that help recover oil from the reservoir after primary and secondary recovery processes. Experimental studies on LSW and ASP flooding have indicated potential in additional oil recovery. In this paper, numerical simulation was performed to study the combined effects of LSW and ASP flooding. A heterogenous reservoir initially saturated with oil and water was modelled using Eclipse. The wells were completed with an inverse five-spot pattern and the production life of the reservoir was taken to be five years. The results showed that LSW flooding using a salt concentration of 1 000 ppm achieved a higher oil recovery than conventional (high salinity) water flooding with a salt concentration of 35 000 ppm. The oil recovery for conventional water flooding was 59.5% and that of low salinity flooding was 64.1%. The overall oil recovery for LSW combined with alkaline, surfactant and polymer flooding were 64.1%, 70.5% and 62.6%, respectively. The model indicated an increase in overall oil recovery of 91% when alkaline, surfactant and polymer were combined and injected as the same slug as opposed to the injection of the chemicals individually. This was attributed to the synergy of the chemicals. The alkaline and the surfactant reduce the interfacial tension between the oil and water and the polymer improves the mobility ratio thereby increasing sweep efficiency.

Modelling Low-Salinity Water Flooding as a Tertiary Oil Recovery Technique

In this project, low-salinity water flooding has been modeled on ECLIPSE black oil simulator in three cases for a total field production life of twenty-five years. In the first case, low-salinity water flooding starts fifteen years after secondary water flooding. For the second case, low-salinity water flooding starts five years after secondary water flooding and runs till the end of the field production life. For the third case, low-salinity water flooding starts five years after secondary water flooding, but low-salinity water flooding is injected in measured pore volumes for a short period of time; then, high-salinity water flooding was resumed till the end of the field production life. This was done to measure the effect of low-salinity water flooding as slug injection. From the three cases presented, oil recovery efficiency, field oil production rate, and field water cut were observed. Increased percentages of 22.66%, 35.12%, and 26.77% were observed in the three cases, respectively.

Functional compounds of crude oil during low salinity water injection

Due to the intrinsic complexity of crude oil, the advanced chemical compositional analysis would be required to detect the crucial interactions that may take place between water and crude oil during low salinity water injection (LSWI). In this study, a series of analytical techniques were combined to discover the functional compounds of crude oil contributing to low salinity water effect (LSE) during LSWI. The Fourier Transform Infrared (FT-IR) analysis and Fourier Transform Ion Cyclotron Resonance Mass Spectroscopy (FT-ICR MS) were deployed to characterise the oil/water interface of a chosen crude oil with a high potency toward formation of water microdispersion. Using the negative and positive electrospray ionisation modes (−ESI and +ESI, respectively), acidic compounds with aliphatic nature and asphaltene molecules were determined to be the most functional compounds at the interface promoting the spontaneous formation of water-in-oil microdispersion. These species are key to designing any waterflood operation in oil reservoirs.

Investigating the Applicability of Molecular Dynamics Simulation for Estimating the Wettability of Sandstone Hydrocarbon Formations.

One of the techniques to increase oil recovery from hydrocarbon reservoirs is the injection of low salinity water. It is shown that the injection of low salinity water changes the wettability of the rock. However, there are argumentative debates concerning low salinity water effect on changing the wettability of the oil/brine/rock system in the oil reservoirs. In this regard, molecular dynamics simulation (MDS) as a tool to simulate the phenomena at the molecular level has been used for more than a decade. In this study, the Zisman plot (presented by KRUSS Company) was simulated through MDS, and then, contact angle experiments for n-decane interactions on the Bentheimer substrate in the presence of different concentrations of sodium ions were conducted. MDS was then used to simulate experiments and understand the wettability trend based on free-energy calculations. Hereafter, a new model was developed in this study to correlate free energies with contact angles. The developed model predicted the experimental results with high accuracy (R2 ∼ 0.98). A direct relation was observed between free energy and water contact angle. In contrast, an inverse relation was noticed between the ion concentration and the contact angle such that an increase in the ion concentration resulted in a decrease in the contact angle and vice versa. In other terms, increasing brine ionic concentrations in the presence of n-decane is linked to a decrease in free energies and an increase in the wetting state of a sandstone. The comparison between the developed model’s predicted contact angles and experimental observations showed a maximum deviation of 14.32%, which is in satisfactory agreement to conclude that MDS can be used as a valuable and economical tool to understand the wettability alteration process.

Effect of salinity, single and binary ionic compounds’ low salinity water on wettability alteration in carbonate rocks

Low salinity water flooding is one of the emerging enhanced oil recovery technologies as it has been proven economical and environmentally friendly. However, the recovery mechanism of low salinity water (LSW) is still under debatable due to the complex effect of low salinity water and its ionic compositions. Therefore, this study aims to discover the optimum seawater dilution salinity and influence of single and binary ionic compounds low salinity water on wettability alteration of carbonate core slices at optimum salinity. To achieve that, a modified Design of Experiments (DOE) has been implemented. Contact angle measurement was carried out to characterize the wettability of core slices at 0 hour, after 24 hours and after 48 hours. The results revealed that dilution of seawater reduced the contact angle of carbonate core slices towards more water wet until the optimum salinity of 1750ppm. Further dilution to 700ppm only shown a slight impact in shifting the wettability of the carbonate slices towards more water wet. In single ionic compound LSW, MgCl2 showed the greatest ability in altering wettability. In binary ionic compounds LSW, it was found out that MgCl2 mixed with ionic compounds containing monovalent ion is more effective in altering contact angle than MgCL2 mixed with ionic compounds containing divalent ion which serve as a new finding in current low salinity water study on carbonate rocks.

Effect of divalent cations in formation water on wettability alteration during low salinity water flooding in sandstone reservoirs: Oil recovery analyses, surface reactivity tests, contact angle, and spontaneous imbibition experiments

This paper demonstrates the importance of Ca2+ in formation water on low salinity oil recovery, and the importance of Mg2+ in formation water with Ca2+ and alone. A series of Berea sandstone cores were flooded with formation water (FW) water as a secondary flood, then low salinity (LS) water was injected for the tertiary stage. The temperature of the experiments was 90 °C (reservoir temperature). Surface reactivity tests were run where water saturated cores were flooded with the same FW and LS water that was used in oil recovery experiments. While injecting brines, samples of the effluent were analyzed for pH, Mg2+, and Ca2+. We also measured contact angles between sandstone cores and crude oil in the presence of LS water and FW after some flooding stages. Oil recovery tests with double Ca2+ and Mg2+ (especially Ca2+) concentration in FW revealed a lower LS water EOR effect, indicating that the cores are apparently more water-wet. The LS water effect was much larger when the concentration of Ca2+ and Mg2+ in the FW was decreased by half. Additionally, the oil recovery due to LS water is greater for cores with Mg2+ abundance in the FW than for those with Ca2+. The LS water effect is greater as the Mg2+ exists. Surface reactivity tests, contact angle measurements, and spontaneous imbibition results were consistent with the oil recovery tests. Generally, contact angle measurements and spontaneous imbibition predict similar wettability trends because both tests depend on the same physics concepts. In this study, we claim that the smaller Mg2+ radius causes Mg2+ to be more tightly enveloped in water molecules than Ca2+, which might mean that Ca2+can actually get closer to the oil and mineral surfaces than Mg2+and have a bigger effect.The tests conducted in this study to investigate the role of divalent cations on LS water response should be routine practice as a supplement to conventional core flooding experiments. Such tests will give the operator clear guidance as to proper LS water design to maximize oil recovery for a given FW and core.

Sequential injection mode of high-salinity/low-salinity water in sandstone reservoirs: oil recovery and surface reactivity tests

The aim of this paper is to quantify the effect of low-salinity (LS) water on oil recovery from sandstone cores at different temperatures and at various permeabilities, oil viscosities, and Ca2+ concentrations in the formation water. Six sandstone cores were waterflooded with high-salinity (HS) and LS water at various temperatures ranging from 25 to 90 °C. Four cores were allocated to oil recovery experiments, and the other two were dedicated to surface reactivity tests. The Swi and Sor of the cores were established, and then the cores were pre-aged for 3 days at 70 °C with oil in a closed container. We examined the effect of different ionic solutions (HS water, LS water, and double Ca2+ HS water) at different temperatures. The surface reactivity test cores were flooded with the same HS and LS brines that were used in oil recovery forced-imbibition experiments. During flooding, samples of the effluent were analyzed for pH and Ca2+. The absence of an oil phase enabled us to isolate and quantify the important water–rock reactions. Ca2+ desorption from the core that was aged in the double Ca2+ concentration was larger than that desorbed from the other core, but pH and pressure was less than the other core during surface reactivity tests. Due to dehydration at high temperatures, the desorption of Ca2+ decreased as the temperature increased. Also, as the temperature increased, the pH gradient between the HS and LS water effluents decreased. Oil recovery forced-imbibition experiments with a double Ca2+ concentration showed a small LS water effect at all temperatures, meaning that the cores became more water-wet; however, the LS water effect was much greater when the amount of Ca2+ in the HS water was decreased by half. Furthermore, as the core permeability and oil viscosity increased, our tests showed a greater positive effect from the LS water. This work attempts to isolate the separate effects and thus examines the oil recovery achieved with the most important LS waterflood factors, which are temperature, ion exchange, and pH.

Impact of clay type and water composition on low salinity water injection – visualisation approach

Low salinity water (LSW) injection as an enhanced oil recovery method has attracted much attention in the past two decades. Previously, it was found that the presence of clay such as kaolinite and water composition like the nature of cations affect the enhancement of oil recovery under LSW injection. In this study, a pore-scale visualisation approach was developed using a 2D glass micromodel to investigate the impact of clay type and water composition on LSW injection. The glass micromodels were coated by kaolinite and illite. A meniscus moving mechanism was observed and the oil–water interface moved through narrow throats to large bodies, displacing the wetting phase (oil phase). In the presence of kaolinite, the effect of LSW injection was reflected in the change to the wettability with a transition towards water-wetness in the large sections of the pore walls. The advance of the stable water front left behind an oil film on the oil-wet portions of pore walls; however, in water-wet surfaces, the interface moved towards the surface and replaced the oil film. As a result of wettability alteration towards a water-wet state, the capillary forces were not dominant throughout the system and the water–oil menisci displaced oil in large portions of very narrow channels. This LSW effect was not observed in the presence of illite. With regard to the water composition effect, systems containing divalent cations like Ca2+ showed the same extent of recovery as those containing only monovalent ions. The observation indicates a significant role of cation exchange in wettability alteration. Fines migration was insignificant in the observations.

Effect of low-salinity water on asphaltene precipitation

ABSTRACTThe effect of low-salinity (1000 to 5000 ppm) and intermediate-salinity (5000 to 40000 ppm) water (MgSO4, MgCl2, Na2SO4, CaCl2, NaCl and KCl) on asphaltene precipitation was investigated in this work. The results revealed that all brines intensify the amount of asphaltene precipitation. All cases exhibited initial downward trend followed by the upward trend for the amount of asphaltene precipitation with increasing the brine concentration. A similar trend was also observed for Interfacial Tension (IFT) between crude oil and brine in this study. IFT was tested for MgSO4, MgCl2, Na2SO4, CaCl2, NaCl and KCl brines with concentrations of 1000 to 40000 ppm. Finally, experimental results showed that an increase in volume of all brines in the mixture (brine +oil) led to increase and decrease of the asphaltene precipitation in low and intermediate salinity regions, respectively.

Effects of low salinity water on calcite/brine interface: A molecular dynamics simulation study

Calcite is among the most abundant minerals organizing the oil reservoir formation and therefore its surface properties play a central role in the increase of the oil recovery efficiency. The effect of low-salinity water in carbonate rocks reveals that brine composition and salinity can improve the oil recovery in carbonates through wettability alteration. However, the specific mechanism for wettability changes that leads to improved oil recovery in calcite is not well understood. To obtain deeper insights at atomic level into the understanding the characteristics of the calcite-water interface, we performed classical molecular dynamics simulations in the presence of different ions in brine solutions in the oil reservoirs. The results showed highly ordered water layer in the vicinity of calcite surface, followed by subsequent layers rich in ions of brine. These layers form an electric double layer, with monovalent Na+ ions in the Stern layer and anions in the diffuse layer. The results also indicated that divalent cations do not appear in the electric double layer. The appearance of ions at calcite/brine interface is more effective in wettability alteration for low saline brines such as seawater than high saline ones like formation water validating the applicability of low saline water injection method to improve oil recovery efficiency.

Investigation into the Effects of Crude Oil on Foam Stability by using Different Low Salinity Water

Objectives: To find the surfactant aqueous solution that will ultimately reduce the IFT and form a more stable solution in presence of oil. Methods/Analysis: Each test was performed at 80oC. The Low Salinity Water (LSW) consisted of thirtyone samples with different ion compositions and concentrations ranging from 500 to 6500 ppm. The surfactant aqueous solutions were prepared by mixing proportions of surfactant with each of the LSW aqueous solutions. For Interfacial Tension (IFT) and Foam Stability Test (FST), two types of crude oil with different Total Acid Number and Total Base Number were used. Findings: The experimental results revealed that for both crude oils A and B, the surfactant solution with LSW composed of monovalent ions of sodium and potassium caused much changes in the IFT and were characterized with stable foam columns as compared to the divalent cations of magnesium, Calcium, as well as the mixture compositions. However, changes for crude oil B (lower TAN and higher TBN) were greater than for crude oil A (higher TAN and lower TBN). Similar results were observed for AST. The formation water presented poor results for all the tests. Novelty/Improvement: This paper is very important in a way that attempts to produce a foam formulation that will remain stable even in the presence of oil; a study never performed before. Moreover, the obtained results are valuable for further lying down the truth behind the effects of LSW on the IFT, AST, and FST. Furthermore, it applies a good approach when using two different types of light crude oils for the IFT and FST.

Effects of low-salinity water coupled with silica nanoparticles on wettability alteration of dolomite at reservoir temperature

ABSTRACTWettability alteration in porous media is one of the mechanisms for enhancing oil recovery through injecting low-salinity water into carbonate reservoirs, in which active ions can remove the carboxylic oil component from the rock surface, altering the rock's wettability toward a water-wet condition. This study investigated the concomitant effects of low-salinity water and hydrophilic SiO2 nanoparticles on oil-wet dolomite rock. Results revealed that low-salinity water coupled with hydrophilic nano-SiO2 in oil-wet dolomite rock remarkably affected the wettability alteration of the rock, showing that the simultaneous presence of ions in water and hydrophilic nano-SiO2 led to considerable wettability alteration compared with using just low-salinity water.