جستجوی مقالات مرتبط با کلیدواژه « foam stability » در نشریات گروه « مهندسی شیمی، نفت و پلیمر »

The growing demand of the world for energy has caused to exploit the non-renewable resources using best techniques to enhance the recovery. Gas injection is one of the most common techniques in the exploitation of reservoir’s hydrocarbon. In addition, carbon dioxide is used widely for gas injection processes in oil reservoirs due to the good results obtained by executing numerous field projects. It should be noted that there exist problems in the process of gas injection into reservoirs. Low density and viscosity of gas is caused unfavorable movement of gas in the porous environment as well as early gas breakthrough in production wells. These factors cause gravitational separation as well as fingering phenomenon in reservoirs. To reduce gas injection problems, foam is replaced instead of gas as injecting material. Implementing the foam injection techniques would result better sweeping efficiency than solely gas flooding since foam has a higher apparent viscosity than gas. Fingering and early breakthrough of gas are reduced by foam injection in oilfields. In this research, by using deionized water at atmospheric temperature and pressure, in the first step, the foaming ability of the designed solutions was investigated. At a critical concentration of 0.24% (weight percent of surfactant), the effect of various parameters on the foaming ability were investigated. In addition, the stability of these solutions were measured based on the foam half-life and the optimal parameters of the different solution were determined to be injected into the micromodel. At the end, the solution obtained from the optimal parameters was prepared for running the injection scenarios. Then the amount of produced oil for different solutions was evaluated by micromodel experiments. It should be stated that presence of silica nanoparticles increased the half-life of the foam by about 25%. In addition, adding the Xanthan gum polymer to injecting foam structure along with the silica nanoparticle increased foam half-life to about 60%.

The main purpose of this study is to determine the molecular arrangement in lamella and the role of Marangoni convection in foam stability in the presence of nanoparticles. Experiments were conducted in two different foam systems of (1) anionic nanoparticles-cationic surfactant (CTAB) and (2) anionic nanoparticles-anionic surfactant (SDS). Observations showed that the effective mechanisms of stability are different. Although nanoparticles increase the stability of both foam systems, the presence of nanoparticles in the like-charge system improves foamability. In contrast, in the unlike-charge system, foamability decreases with the increment of nanoparticle concentration. The most influential factor in the foam stability in the like-charge case is the repulsive force which sends more surfactant molecules to the interface. Surface tension results demonstrate that Marangoni flow restitutes the negative impact of gravity drainage and increases the foam stability. In contrast, In the unlike-charge system, the presence of nanoparticles at the interface increases detachment energy significantly, and as a result, the stability boosts. The accumulation of nanoparticles in the interface changes it to a solid-like and high elasticity surface; thus, Marangoni flow is lost.

In this study, stability of aqueous foam is increased by modified nanoparticles using surfactant. To better understand the behavior of stabilized foam with nanoparticles and surfactants, foam ability, stability, wettability changes of nanoparticle, and interfacial tension versus time were investigated. The results of contact angle of calcite/crude-oil/foam agent solution showed that adding CTAB surfactant to silica nanofluid changes the wettability of nanoparticles. At a concentration of critical micelle concentration of surfactant, the nanoparticle experiences the greatest change in wettability towards hydrophobicity, and contact angle increases from 20° at initial time to 57° after 24 hours. The results showed that at the mentioned concentration, the interfacial tension reaches its maximum value. This phenomenon was attributed to the reduction of free surfactants due to adsorption on the nanoparticles. Stability and foaming behaviors were investigated by Ross-Miles method. Foam stabilized with nanoparticles at low hydrophobic values at the beginning of life had a linear decay diagram similar to foam stabilized with surfactant alone. Therefore, the initial stability of the foam is controlled by the free surfactant. Later, the stability of the foam is controlled by the nanoparticles and increases substantially as the bridging mechanisms become more prominent, maximum capillary pressure increases, and viscosity of the liquid bulk increases. At high levels of nanoparticle hydrophobicity (close to CMC 1), the nanoparticles act as surfactants and no longer have the sharp linear drop observed in other samples with low adsorption values. Therefore, the beginning of the foam life is controlled by both nanoparticles and free surfactant. The results showed that the foaming behavior of foam generating solutions is similar to the interfacial tensile behavior. Also, the change in wettability of nanoparticles, which had a long equilibrium time, was proposed as a mechanism for high stability of nanoparticle-stabilized foam in the second half of its life.

The gas flooding is one of the most common methods for enhancing oil recovery. However, some problems; such as, gas uptake reduces this method’s efficiency. The foam formation reduces the relative permeability of the gas and improves this technique. However, the generated foam by the combination of water and gas does not have enough stability. Thus, surfactant is used for many years. However, the foam stabilized by surfactants is problematic in high temperatures and salt content. The studies have shown that the foam stabilized with Nanoparticles can endure the harsh conditions. Since the presence of oil in the reservoir is inevitable, investigating the effects of crude oil on the foam is of special importance. In this project, the foam generated by Nano-silica and SDS is studied. Then the differences between this foam and the foam generated by only surfactant is discussed. The effect of different kinds of crude oils with different viscosities on foam structure is discussed too. For studying the foam ability and foam stability in the presence of different concentration of these crude oils, the static method called “mixing” is used by the setup that is designed for this job. The results show that nanoparticles do not effect foam ability but increase the foam stability significantly. Regarding the effect of crude oil, it was also determined that the presence of crude oil reduces foam stability and by increasing oil concentration, the stability reduces more. It also turned out that with increasing oil viscosity, foam stability and properties will be improved.

Foam injection for the purpose of Enhanced Oil Recovery (EOR) process is one of the approaches of chemical EOR. In this method, in addition to using the surfactant, other chemical additives are used to achieve ultralow IFT which result in mobilizing the residual oil of the primary and secondary recovery stage. Foam generation causes to achieve the mobility ratio of less than 1, and then the foam generation improves volumetric sweep efficiency. In foam flooding, foam stability is one of the determining parameters for increasing oil recovery. Generating the most stable foam is one of the subjects of the recent researches on this kind of EOR process in stand point of selection of type and concentration of chemicals. In this study, effects of salinity, surfactant concentration, and the type and the concentration of co-solvent were investigated on foam stability. Optimized stability was gained in different co-solvents. This optimum was used in flooding process to investigate its effect on oil recovery. Butyric acid and 1-butanol were two used co-solvent. The most stable foam was resulted from the samples which utilized butyric acid as co-solvent. Maximum oil recovery of 44% of OOIP has observed in solution with 1-butanol as co-solvent, which is not displaced by water flooding. Moreover, observing the maximum oil recovery validates the efficacy of this technique.