جستجوی مقالات مرتبط با کلیدواژه "low-salinity water" در نشریات گروه "مهندسی شیمی، نفت و پلیمر"

The mechanisms that enhance oil recovery through low-salinity waterflooding can be categorized into two main groups: fluid-fluid interactions and rock-fluid interactions. Fluid-fluid interactions have been less explored in the existing literature. One significant effect of these interactions is the maintenance or increase of oil phase connectivity, which boosts the relative permeability and production rate of oil from the reservoir. This research aims to deepen the understanding of these effects and their time scales by examining the coalescence of two adjacent oil droplets in presence of saline water. A novel device and method were developed in this study. In this method, two oil droplets (one hanging from the top and one from the bottom) are placed near the desired brine. After an aging period, they are brought together to initiate contact. The time it takes for the droplets to merge, known as the “coalescence time,” is recorded. The results show that coalescence time increases with aging time, however starts to stabilize after about 15 minutes. Additionally, the coalescence time of two oil droplets exhibits a nonmonotonic relationship with salinity, peaking at an intermediate salinity level. The maximum coalescence time occurs at lower ionic strengths in brines with divalent salts like calcium, magnesium, and sulfate compared to monovalent salts. The specific values for sodium chloride, magnesium chloride, calcium chloride, and sodium sulfate brines are 0.5, 0.05, 0.05, and 0.01 M, respectively. Ultimatly, this study indicates that there is an optimal salinity for the fluid-fluid effects in low-salinity waterflooding, and understanding these effects on oil recovery necessitates further waterflooding experiments.

The water injection process, especially low salinity water injection (LSW), is one of the significant processes in enhanced oil recovery. Mainly, different mechanisms are based on the type of rock and fluid in the water injection process in the reservoir. In this research, seawater and diluted water are injected into calcite reservoir rock in reservoir condition. Dissolution and precipitation mechanism by water incompatibility have considered and investigated. The competition between dissolution and precipitation mechanisms, have evaluated by concentration change in outlet of injected core, and permeability change. The results have shown that the dissolution mechanism is dominant in low salinity and seawater injection. In addition, precipitation have observed as an effect on permeability reduction. The competition between mechanisms and contact time effect is investigated by water co-injection into core sample. The results have shown that scale deposition can cause low effect on permeability reduction because dissolution. Also concentration change did not show ion exchange for magnesium ion in precipitation. Thus, the contrast between the precipitation of water incompatibility and dissolution mechanisms in the permeability changes are a function of the rock structure and injection fluid composition, as well as the temperature conditions, as are shown in the results.

By increasing the extraction from the hydrocarbon reservoirs, the investment risks in the hydrocarbon field development projects reduces. Experimental analysis, generalization of their results, modeling and design the reservoir are used because of the uncertainty in geological issues during the preparation of dynamic and static models of the fields and the high cost of auditing these projects. Engineered water injection improves oil recovery, but the mechanism of its effect is not completely clear. According to the researches, one of the effective mechanisms of engineered water is the change of electric charge on the surface of oil and as a result, change of wettability. The effect of electric charge on the wetting behavior of carbonate rock which leads to harvest increase, has been investigated in this study. The existing surface complex models were reconstructed for the pure calcite rock model and the ionic composition used in this work. Models has been examined from the electric potential and surface absorption points of views and the best model was considered to predict zeta potential. Based on the obtained contact angles, 40 times diluted seawater increases the hydrophilicity by 30.79% compared to concentrated seawater. The results also showed that 40 times diluted seawater leads to a decrease in the zeta potential of pure calcite/brine from -2.9 to -5.4 mV and a decrease in the zeta potential of crude oil/brine from -6.2 to -18.3 mV. Based on the results, the electric charge of these two surfaces becomes more negative as the water salinity decreases and consequently the repulsive force between these two interfaces and the thickness of the blue film between these two interfaces increases. These changes lead to increase the water-friendliness of the rock, the greater tendency of oil for separating from the reservoir rock and ultimately lead to an increase in harvest.

The method of low salinity water with nanoparticles can be considered as a hybrid method of enhanced oil recovery. The goal of this paper is to investigate the effect of salinity on nanoparticles with a green surfactant in enhanced oil recovery. It was tried to determine the appropriate mass fraction of the nanohybrid and the optimal concentration of salinity for nanofluids in the micromodel flooding test. In this research, gamma-alumina and silica metal oxide nanoparticles were used in basic fluids with different salinities. Nanoparticles improve oil recovery factor, however the most important challenge of using nanoparticles is when they are placed next to divalent ions in brine, which become very unstable. Therefore, an attempt was made to study the stability of gamma-alumina, silica and their hybrid nanoparticles (in different mass fractions) with different salinity. To increase the duration of stability of nanoparticles in water with different salinity, environmentally compatible and green surfactant called Gum Arabic was used. The experiments were designed with software and Taguchi method. After the preparation of nanofluids, their stability was investigated and the flooding test was performed on the nanofluids that had good stability. The lowest stability period was related to nanofluids whose base fluid was reported to have a salinity of 40,710 ppm. The highest recovery factor of gamma-alumina nanohybrids with a mass fraction of 10:90 in water with a salinity of 20400 ppm, with 1000 ppm of Arabic gum equal to 60.34% and the lowest recovery factor among nanofluids for silica nanoparticles with deionized water without gum Arabic was reported to be 34.5%.

In recent years, low salinity polymer injection as an enhanced oil recovery method has drawn more attention by researchers. Combination of other methods with low salinity water injection has also been investigated in the literature. Among them is the combined low salinity water and surfactant or polymer injection which shows its efficiency in enhancing oil recovery. In this study, the combined low salinity water and polymer injection to five sandpack models and its efficiency in oil production is investigated through different flooding experiments. To this end, three and two polymer injection experiments were conducted in tertiary and secondary modes (after and before low salinity water injection), respectively. The results indicates that polymer injection in tertiary mode has better performance than the secondary mode injection experiments as in the former case the oil recovery at breakthrough is about 11% higher than the later one. In tertiary polymer injection experiments, as the concentration of polymer solution increases, the mobility of the displacing fluid decreases leading to an increase in the microscopic efficiency. During the secondary polymer injection, polymer is in contact with the high salinity formation water which increases the adsorption of polymer onto the rock surface and decreases the permeability of the porous medium. As a result, oil recovery decrease. The pH analysis of the produced water shows that during the low salinity water injection experiments, the pH increment is the active mechanism and the wettability alteration toward water-wet increases the oil recovery. Displacement of the polymer and low salinity water are also investigated by measuring the refractive index in the produced water indicating the trend of the salinity change.

As oil fields approach to the end of the primary production phase, the new technologies should be employed to increase the recovery of hydrocarbons. In recent decades, nanofluid has been proposed as an efficient, and environmentally friendly approaches for EOR purpose. The target of this study is to investigate the effect of silica nanoparticle on the wettability alteration of the carbonate rock. In this study, four different concentrations of silica nanoparticle were used (0.01, 0.02, 0.05, and 0.1 wt.%) in low salinity seawater (1000 ppm of positive ions). The stability of nano particle in brine is one of the challenge while using for EOR. In this study the stability of nano fluid was achieved without using any surfactant. The Spontaneous imbibition experiments, and contact angle measurements were carried out at 75 °C to check the performance of nano fluids in wettability alteration of carbonate rock. The results showed that the silica nanoparticle has a significant effect on the oil recovery from carbonate rock. The diluted sea water (1000 ppm) without nano particle resulted to the oil recovery of 10.45% whereas nano fluid with concentration of  0.01, 0.02, and 0.05 wt.%  resulted to the oil recovery of 11.5%, 10.83%, and 22.16% , respectively. The contact angle results also confirmed that the silica nanoparticle has a positive effect on the wettability alteration of the carbonate rock surface toward water wetness. The permeability measurement after and before spontaneous imbibition tests showed that the pores were not blocked due to nano particle precipitation. The impact of initial water in the rock was investigated on the performance of wettability alteration while using nano fluid. The results depicted that the presence of initial water in the carbonate rock adversely affect the oil production.

Water injection especially low-salinity water injection has provided a low-cost EOR method for more oil recovery. In recent years, most of the studies on low-salinity waterflooding have been focused on the investigation of the effect of water injection on rock/oil/water interaction. The purpose of this study is to investigate the fluid/fluid interaction which has received less attention in comparison with the rock/fluids interaction. In this experimental work, a series of bottle tests have been performed with 20 percent of crude oil and 80 percent of saline water (for five different common salts in the seawater) with different salinities from 6,000 to 40,000 ppm. By sampling the emulsified portion at the oil/water interface, the size distribution of the water droplets in oil has been obtained. Moreover, the size of water droplets have varied from 0.02 to 1.65 mm, and relative frequency of categories was 0.73 at its maximum. The size of water droplets decreases with a decease in the salinity. Among the salts, calcium chloride is more effective in comparison with others as the water droplet size is the lowest among three other salts, and consequently it could attract more natural surface active materials from oil to water-oil interface. The sorting of salts from highest to lowest stable emulsion is calcium chloride, magnesium chloride, sodium sulfate and sodium chloride. Ultimately, this is due to the interactions of ions in saline water with oil, charge density of ions and their surface activity.

One of the enhanced oil recovery methods that has been recently received more attention is low salinity water injection (LSW). Among the proposed mechanisms to describe LSW, geochemical reactions seem to mainly affect rock wettability alteration and thus incremental oil recovery. The goal of this paper is to investigate the effect of geochemical reactions of calcite dissolution and ion exchange on the performance of LSW in a sandstone reservoir by using the concept of threshold salinity. Fluid flow equations according to Buckley-Leverett theory were numerically coupled with the PHREEQC software. Results showed that as LSW was injected, initial equilibrium between reservoir rock surface and aqueous phase was disturbed leading to calcite dissolution and also cation exchange between aqueous phase and rock surface. Analysis of geochemical reaction near the injection well showed that cation exchange may cause to separation of organic compound from rock surface leading to wettability alteration to more water- wet. Also, pH profile through the reservoir showed that rate of calcite dissolution was very high near injection well, but only partial dissolution of calcite induced by cation exchange occurs at farther distance. Fractional flow analyses in line with total salinity profile showed that two distinct saturation shock fronts were established during LSW injection: first one represents high salinity condition with a water saturation of 0.43, and the second one represents low salinity condition with a water saturation as much as 0.58. Under the conditions of this study and selection of a salinity threshold of 3000 ppm, such increase of water saturation reveals EOR potential of LSW by which an incremental oil recovery of 10% of the oil initially in place was obtained as compared to high salinity water injection.

The low salinity water flooding caused an increased secondary and tertiary oil recovery in many laboratory and field tests. The extent of the reactions and interactions of this type of flooding led researchers to investigate and find the main mechanisms¡ governing this process. To describe the interactions¡ numerous mechanisms such as¡ fines migration¡ increase in pH¡ multiple ion exchange and electric double layer effect have been noted¡ but none of them¡ has not been accepted as a comprehensive mechanism due to the complexity of the crude-oil-brine-rock interactions. So far¡ most of what has been suggested in previous research was creating a favorable wettability state with dilute brine injection. In this laboratory experiments that take place on sandpacks¡ the effects of brine salinity¡ aging of oil in packs and the fines have been investigated on recovery of oil¡ end point water relative permeability in each salinity and wettability alteration. The obtained results from dilute brine injections show that without the presence of minerals and divalent ions and with NaCl brine¡ tertiary recovery was increased¡ and of course this increase was higher for the aged sample. Also¡ the wettability alteration towards more water wet has been probed by means of flooding data.