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Due to extensive applications of microfluidic devices, manufacturing of these apparatus has recently been noticed. Production of multiple emulsions is one of the main goals of manufacturing microfluidic devices. Design and fabrication of microfluidics are functions of the size of emulsion droplets, properties of fluids applied for emulsification, and considered stability for emulsions. In this article, we have manufactured a novel microfluidic device using simple fabrication and accessible materials. Capillary tubes, PTFE (polytetrafluoroethylene) chassis, a medical needle of gauge 32, and O-rings are the primary materials used to produce this device. The production procedure is explained completely, and all the drawings are represented. Concerning probable interactions between glues and flowing fluids, we tried to fabricate and seal the device without applying chemical agents. The device is tested by n-heptane and deionized water to produce multiple water-in-oil-in-water (W/O/W) emulsions. A sensitivity analysis on the rate of injection is performed. Considering the HLB (hydrophilic–lipophilic balance) as an important property of emulsifiers, the effects of two different types of emulsifiers (sodium dodecyl sulfate with HLB of 40 and glycerol monostearate with HLB of 3.8) at various concentrations are investigated. Due to the results, the injection rate of the mediate phase should be less than half of the outer phase for the formation of emulsions. Consequently, the rate of injection for the inner phase should be less than half of that for the mediate phase. The simplicity of production and accessible raw materials could be considered as the strengths of our microfluidic device. [ABSTRACT FROM AUTHOR]

Reservoir heterogeneity is an important factor which should be considered for each operation in oilfields. Acidizing operation is performed to eliminate or reduce the damages of reservoirs. The dissolution of the minerals and rock texture in damaged areas is the main goal of acidizing. However, the existence of high permeable zones through flowing paths results in extra damages and fluid loss. Some additives could be added to the injected acid to avoid these undesirable phenomena. In this research, we added a Zwitterionic sulfonate surfactant to hydrochloric acid (HCl) solution and evaluated the rheological behavior of several compositions of acid‐based viscoelastic surfactant (VES) solutions under various temperature and shear rates. The capability of optimum solution to plug the high permeable zone and divert the acid flow to low permeable zone is examined. The optimum solution was injected into a parallel sandpacked system with different permeabilities at various flow rates (1, 3 and 5 cc/min). It was observed that the injection rate of 3 cc/min has the most efficiency to reduce the heterogeneity. Besides the tendency of VES based solutions for altering wettability of rock to more water‐wet condition is observed. The findings of this study can help the better understanding of practical application of VES in acidizing through heterogeneous reservoirs. Besides, effective parameters for such application are determined. [ABSTRACT FROM AUTHOR]

In this study, the problem of water production in one of Iran's oil reservoirs will be examined. First, using the flow rate diagram of oil and water production, the water production problem will be examined according to time. Then, after confirming the occurrence of water production problem, the mechanism of water production will be investigated using Chan diagnostic diagrams and the created sector model. The results of this study indicate that firstly, the problem of water production in the well under study is observed, and secondly, according to the Decline-curve analysis diagrams, Recovery plot, Chan derivative diagram and schematic shape of the fluid flow movement, it shows the mechanism. Water production is a channel flow process, underwater injection. A gel treatment at early time with 25% of water cut was studied, for that it was modelled a gel treatment after 500 days of production. The main observation is that by increasing the concentration of injected gel, the rate of oil production increases and the rate of water production decreases. The concentration evaluated concentration was from 0 to 100 (lb/bbl) of solution, a stabilization concentration was not observed. Finally, first by identifying the type of water production mechanism for this reservoir in Iran, it has been determined that it has water production through the canal and then by using a simulation of gel injection, the water production rate has decreased and the oil production rate has increased. [ABSTRACT FROM AUTHOR]

Many experimental investigations on carbonated water injection (CWI) have shown an increase in oil recovery which CWI is defined as the process of injecting CO2-saturated water in oil reservoirs as a displacing fluid. In every enhanced oil recovery method, the potential formation damage of the injected fluid is considered. This is due to the fact that the injection of incompatible fluids often causes clay swelling and fines migration and thus impairs the formation permeability. Permeability reduction by clay particles mostly depends on its distribution which can be pore lining, pore bridging, dispersed or combination of these causing pore blocking or pore-throat diameter reduction. Besides, fine migration is considered as an important mechanism of recovery improvement during injection of low-salinity water in sandstone oil reservoirs. The present paper investigates the impact of injection of carbonated water and brines with the different salt concentrations on oil recovery and formation damage focusing on permeability variation. The investigation has been done on 12 relatively homogeneous clay-containing sandstone cores, while the compositions of the injection water were varied from 40,000 to 1000 ppm, at 176° F and 2000 psi. The amount of recovery improvement and permeability drop recorded in all tests and the fine effluent of two experiments were analysed using XRD, one for CWI and one for WF (water flooding). In all salinities, CWI has shown more oil recovery improvement than conventional water. CWI of 40,000 ppm showed the minimum permeability reduction of 6 percent, while the highest permeability was obtained by injection of water with 1000 ppm. Maximum ultimate oil recoveries of 61.2% and 42% were achieved by 1000 ppm both for CWI and WF, respectively. In comparison with brine injection, CWI resulted in more permeability drop in salinity above critical salt concentration (CSC), while below CSC, WF has caused more formation damage than CWI. Experimental results also showed that fine migration was the main reason behind formation damage. It was also revealed that permeability was significantly reduced due to fine production in the effluent. [ABSTRACT FROM AUTHOR]

In this work, the efficiency of CO2-foam injection for enhanced oil recovery (EOR) is investigated. Six floods were performed on sand pack columns. Pure water injection, WAG injection and simultaneous injection of CO2 and surfactant solution with various concentrations were conducted. Notable difference was observed between oil production in secondary surfactant assisted WAG and other injection scenarios. The experimental work in this research shows that increase in concentration of surfactant in the injection process results in mobilization of more oil that may not have been achievable by using water flooding and WAG flooding methods individually. [ABSTRACT FROM AUTHOR]

This research concerns the treatment of aqueous solutions by precipitation of Cu(II) with employing heavy oil fly ash (HOFA) which is preferred due to the comparatively low cost of sulfide precipitant for the removal of heavy metals. In this study, HOFA and NaOH were added to enhance sulfide precipitation which results in the reduction of heavy metal concentration to an acceptable level for discharging. The effects of different experimentally controlled factors including HOFA dose, time, pH, initial concentration of Cu(II), and NaOH concentration were investigated through the model equations which were designed by a two-leveled fractional factorial design in a batch system. Using the experimental results, a linear mathematical regression model representing the influence of the significant factors and their interactions were obtained. At last, results indicated that among the main interaction factors which are pH, dose of HOFA, NaOH concentration, and interaction of time and initial concentration had the most significant effects. Besides, it was observed that pH of the solution was the most influencing parameter on the removal of metal ion. Furthermore, based on the results, HOFA as a waste material, had a high efficiency in Cu(II) removal. [ABSTRACT FROM PUBLISHER]

This paper aims to prove that adsorption is one of the most applicable, efficient, and inexpensive processes in the removal of heavy metals from water. In this research, commercially activated carbon and clinoptilolite were used as adsorbents in order to adsorb Cu(II) in the aqueous solutions. The effects of different experiment control factors including pH, time, temperature, adsorbent dose, initial concentration of Cu(II), mixing rate, and type of adsorbent have been investigated through the equations model designed by a two-level fractional factorial design in a batch system. Furthermore, by employing the experimental results, a linear mathematical regression model which represents the influence of each factors and their mutual interactions was established. Finally, the results declared that pH and temperature are significant among the main factors. Besides, the interaction of time and mixing speed was noticeable, so it was observed that the pH level of solution was the most influential parameter in the removal of metal ion. [ABSTRACT FROM PUBLISHER]

The size and morphology of asphaltene aggregates, precipitated from live oil by pressure depletion at the reservoir temperature was studied using scanning electron microscopy and atomic force microscopy. The experimental studies showed that the mean size of aggregates increased when pressure decreased. The results indicate that the morphology of aggregates was changed from amorphous spherical and elliptical shapes to irregular. A bimodal distribution function was able to describe the size distribution in pressure range of 500 to 3500 psi. At higher pressure, the unimodel was able to represent the size distribution. The results showed reduction in live oil stability and asphaltene aggregation with pressure drop. [ABSTRACT FROM AUTHOR]

Growing oil prices coupled with large amounts of residual oil after operating common enhanced oil recovery methods has made using methods with higher operational cost economically feasible. Nitrogen is one of the gases used in both miscible and immiscible gas injection process in oil reservoir. In heterogeneous formations gas tends to breakthrough early in production wells due to overriding, fingering and channeling. Surfactant alternating gas (SAG) injection is one of the methods commonly used to decrease this problem. Foam which is formed on the contact of nitrogen and surfactant increases viscosity of injected gas. This increases the oil-gas contact and sweep efficiency, although adsorption of surfactant on rock surface can causes difficulties and increases costs of process. Many parameters must be considered in design of SAG process. One of the most important parameters is SAG ratio that should be in optimum value to improve the flooding efficiency. In this study, initially the concentration of surfactant was optimized due to minimization of adsorption on rock surface which results in lower cost of surfactant. So, different sodium dodecyl sulfate (SDS) concentrations of 100, 500, 1000, 2000, 3000 and 4000 ppm were used to obtain the optimum concentration at 70 °C and 144.74 x 105 Pa. A simple, clean and relatively fast spectrophotometric method was used for determination of surfactant which is based on the formation of an ion-pair. Then the effect of surfactant to gas volume ratio on oil recovery in secondary oil recovery process during execution of immiscible surfactant alternating gas injection was examined experimentally. The experiments were performed with sand pack under certain temperature, pressure and constant rate. Experiments were performed with surfactant to gas ratio of 1:1, 1:2, 1:3, 2:1 and 3:1 and 1.2 pore volume injected. Then, comparisons were made between obtained results (SAG) with water flooding, gas flooding and water alternating gas (WAG) processes. This study shows that using the concentration of 1500 ppm of surfactant solution is practical and economical. Results also show that the SAG ratio of 1:1 with 0.2 cm³/min at temperature and pressure of 70 °C and 144.74 x 105 Pa, has the maximum oil removal efficiency. In this SAG ratio, stable foam was formed and viscous fingering delayed in comparison to other ratios. Finally, the results demonstrated that SAG injection has higher oil recovery in comparison to other displacement methods (water flooding, gas flooding and WAG). [ABSTRACT FROM AUTHOR]