Surface tensions for aqueous NaCl, NaBr, NaI, KCl, KBr, and KI solutions have been measured at different temperatures and different concentrations. The liquid densities and activity coefficients for electrolyte solutions are modeled accurately with the ion-based statistical associating fluid theory (SAFT2). Besides, a new surface tension prediction model on the basis of the Gibbs thermodynamic method, coupled with ion-based SAFT2 is established, which is applied to predict the surface tension of aqueous concentrated salt solutions at different concentrations and temperatures. In this model, we derived the relationship between the activity coefficient and surface tension, and the activity coefficient can be calculated by ion-based SAFT2. The model is found to give accurate prediction for the surface tension of aqueous concentrated electrolyte solutions at different concentrations and temperatures with the parameter obtained at one fixed temperature.

This study investigated the mechanisms and performance of SiO2 nanofluid for enhanced oil recovery (EOR) in low-permeability cores. Three-phase contact angles for quartz/oil/brine systems were measured, and the microscopic imbibition characteristics of nanofluids in a capillary were observed through visualization experiments. In addition, the effects of the adsorption of the nanoparticles on the oil–water relative permeability was studied using core displacement tests. Furthermore, a total of 11 core flooding tests were performed, and the effects of injection parameters, such as nanoparticle concentration, injection rate, and injection scheme, on the oil recovery were investigated. Wettability alterations were observed among quartz/oil/brine systems that contributed to higher displacement efficiencies in microscopic imbibition tests. Relative permeability measurements showed that, upon the adsorption of the nanoparticles, the irreducible water saturation and oil-phase relative permeability increased whereas the water-phase relative permeability decreased. Moreover, nanoparticles tended to adhere to the pore surface of the rock, which significantly changed the wettability of cores to strongly water-wet conditions. Nanofluid displacement tests showed that additional 4.48–10.33% increments in the oil recovery can be obtained compared to conventional waterflooding. With increasing nanoparticle concentration, the viscosity and asphaltene content of the produced oil gradually decreased. The results showed that the optimum nanoparticle concentration was 10 ppm, whereas further a increase in the injected nanoparticle concentration could plug the pore throats, resulting in a slight decrease in tertiary oil recovery. The effects of nanofluid imbibition on the recovery were more significant at lower injection rates, leading to higher recoveries. Furthermore, it was found that cyclic nanofluid injection can provide higher tertiary oil recovery than a continuous nanofluid injection scheme.

•N2/liquid CO2 foam showed an outstanding filtration control performance.•Leak coefficient was decreased by the increasing of foam quality (<80%).•Low quality foam (∼30%) controlled filtration effectively under high pressure drop.•The damage of N2/liquid CO2 foam to porous media could be eliminated with time.Liquid CO2 has been successfully used as a fracturing fluid and injected into rock formations to enhance oil and gas production. However, the difficulty in controlling the filtration of liquid CO2 in porous media limits its application. The goal of this study is to investigate the dynamic filtration control performance of N2/liquid CO2 foam with a fluorochemical (HFE) as stabilizer. A laboratory apparatus has been specially designed and built for the generation of N2/liquid CO2 foams and the measurement of their viscosity and filtration rate under high pressure (10–25 MPa). The test results show that after liquid CO2 and HFE were mixed with N2, the N2/liquid CO2 foams were generated and showed significant viscosity improvement compared to liquid CO2. The foams exhibited better filtration control performance compared to liquid CO2 and liquid CO2 + N2 systems. Although the addition of HFE did not result in the formation of filter cake, the foam showed a wall-building behavior, which could be explained by the CO2 phase change in porous media. As foam quality increased from 28% to 92%, the leakoff coefficient and spurt loss volume first decreased until the foam became unstable and changed into mist flow. The leakoff coefficient of foam increased with the increase in permeability of porous media. For foam with the quality of about 50–80%, a change of 2 orders of magnitude in permeability resulted in a change of 1 order of magnitude in leakoff coefficient. At high pressure difference, lower initial quality foam (∼30%) showed better filtration performance than higher initial quality foam (∼80%). When the pressure difference was high enough to cause the CO2 phase change from liquid to gas in the porous media, the initial foam damage after filtration became obvious, but the damage could be eliminated with time by gas return flow. Thus, by using N2/liquid CO2 foam in porous media, the fluid filtration behavior could be controlled without damage.

•Fractal theory was used for evaluation of aqueous foam in porous media.•A concise relation was established by calculating the foam fractal dimension.•Multiple major factors affecting foam structure were discussed.The evaluation and simulation of foam fluid are still matters of significant debate despite the large number of available studies due to the excellent properties of foam and its successful applications, especially in oil and gas field development. The properties of foam fluid are substantially determined by its dynamic structure in porous media; however only a few studies that investigate and perform measurements related to such structure have been reported. In this research, a new method based on fractal theory is proposed for evaluation of aqueous foam in porous media. As a first step, the fractal characteristics of foam in porous media are confirmed by image processing and calculations. Accordingly, the foam dynamic structure is quantitatively studied by defining and calculating the foam fractal dimension. Secondly, a concise relation is established which reveals that the foam fractal dimension is nearly time-independent. Finally, a sensitivity analysis is carried out by discussing three major factors affecting foam structure in porous media. These results are expected to be helpful for further understanding the dynamic characteristics of foam fluids and their advanced applications.Download high-res image (271KB)Download full-size image

The evaluation and simulation of foam-based materials are still matters of significant debate, despite the large number of available studies, due to the excellent properties of foam and its successful applications, especially in oil and gas field development. The properties of foam are substantially determined as a result of a dynamic structure, however few studies have been reported which investigate and perform measurements related to such a structure. In this work, a new model based on fractal theory is proposed for the simulation of aqueous foam. As a first step, the fractal characteristics of foam are confirmed using image processing and calculations. Accordingly, the foam structure is quantitatively studied by defining and calculating the foam fractal dimensions. Secondly, a foam structure evolution model is established, which reveals that the evolutional trend of the fractal dimensions of foam is non-linear with the changing of time, following an exponential equation. The model is then validated and a sensitivity analysis is also carried out. Finally, the applications of this model to the evaluation of foaming agents and the prediction of foam structures are discussed. These results are expected to be helpful for further understanding the dynamic characteristics of foam fluids and their advanced applications.

Nanoparticles can improve the stability of CO2 foam and increase oil recovery during CO2 flooding in reservoirs. The synergistic effect of hydrophilic SiO2 nanoparticles and hexadecyltrimethylammonium bromide (CTAB) on CO2 foam stability was examined in this study. Experimental results show that the synergistic effect requires a CTAB/SiO2 concentration ratio of 0.02–0.07, with 0.033 representing the best concentration ratio. With the increase in the concentration ratio, the synergistic stabilization effect of CTAB/SiO2 dispersion first increases and then decreases. In the monolayer adsorption stage (concentration ratio from 0.02 to 0.033), when the hydrophobicity of SiO2 nanoparticles increases with the concentration ratio, the nanoparticles tend to adsorb on the gas–liquid interface and the stability of CO2 foam increases. In the double-layer adsorption stage (concentration from 0.033 to 0.07), when the hydrophobicity of SiO2 nanoparticles decreases with an increase in the concentration ratio, the nanoparticles tend to exist in the bulk phase and the stability of CO2 foam decreases. The CTAB/SiO2 dispersion stabilizes CO2 foam via three mechanisms: decreasing the coarsening of CO2 bubbles, improving interfacial properties, and reducing liquid discharge. CTAB/SiO2 foam can greatly improve oil recovery efficiency compared to water flooding. Experimental results provide theoretical support for improving CO2 foam flooding under reservoir conditions.

In this work, we have prepared CO2-in-water foam by mixing partially hydrophobic SiO2 nanoparticles and sodium bis(2-ethylhexyl)sulfosuccinate (AOT) and studied its properties. The observation of the appearance of the foam revealed that, with the continuous addition of AOT, the phase behavior of the SiO2 nanoparticle and the AOT mixed system transformed from that of a two-phase system of aggregated nanoparticles into that of a uniform dispersed phase. Both foaming ability and foam stability were optimized when the nanoparticles and the AOT were mixed in a proportion of 1:5. On the basis of our findings from measurements of the dispersion properties, including measurements of the adsorption isotherm of the surfactant on the nanoparticles, zeta potentials, interfacial tension and the three-phase contact angle, we concluded that the synergistic interactions between the SiO2 nanoparticles and the AOT led to the adsorption of nanoparticles around the bubble surface and the formation of a spatial network structure of nanoparticles in the film, thereby enhancing the mechanical strength of the bubble and improving the resistance to outside disturbances, deformation and drainage. Laser scanning confocal microscopy (LCSM) analysis of the same foams further confirmed the existence of a “viscoelastic shell” wrapped around and protecting the bubble.

CO2 foam can control the CO2 mobility and improve the sweep efficiency in reservoirs; however, CO2 foam stabilized solely by surfactants is not stable. Nanoparticles can improve the performance of CO2 foam. The synergistic effect of SiO2 nanoparticles and sodium dodecyl sulfate (SDS) on the CO2 foam stability was studied in this paper. The experimental results show that the synergistic effect requires an SDS/SiO2 concentration ratio of 0.1–0.4. The strength of the effect increases as the SDS/SiO2 concentration ratio increases from 0.1 to 0.17 but then decreases as the ratio further increases from 0.17 to 0.4; thus, a ratio of 0.17 provides the best performance for CO2 foam. The mechanisms of the synergistic effect of SDS and SiO2 include modulating the position of nanoparticle adsorption on the CO2 and liquid interface, improving the interfacial properties of the CO2 foam, and reducing its liquid discharge and coarsening. SiO2 nanoparticles can also improve the CO2 foam performance under high temperatures and pressures. The visual flooding experiment reveals that the addition of SiO2 nanoparticles can improve the stability of CO2 foam in porous media and shows good tolerance of crude oil. SDS/SiO2 foam can increase the pressure differences of the flow in sandpacks after water flooding and improve the oil recoveries markedly. As the SDS/SiO2 concentration ratio increases, the pressure differences and enhanced oil recovery first increase and then decrease. The best CO2 foam flooding performance is achieved at an SDS/SiO2 concentration ratio of 0.17, which is related to the CO2 foam stability. The experimental results provide theoretical support for improving CO2 foam flooding under reservoir conditions.

The deposition of asphaltenes in porous media is one of the most difficult problems during CO2 flooding. In this paper, the adsorption of asphaltenes onto Al2O3 nanoparticles was studied through two methods: (i) by adding a certain mass of nanoparticles in a fixed volume of solution with different initial concentrations of asphaltenes and (ii) by exposing a certain amount of asphaltenes in a fixed volume of solution to different nanoparticles additions. Then, the impact of Al2O3 nanoparticles on the asphaltene precipitation was investigated using the IFT behavior of the oil–CO2 system. Coreflood tests were conducted to study the potential of nanoparticles for inhibition of asphaltenes damage during CO2 flooding, and the effect of injection parameters of nanofluid. It is found that the solid–liquid equilibrium (SLE) can well describe the isotherms of asphaltene adsorption. The trend of the IFT–pressure curve is affected by asphaltene accumulation at the oil–CO2 interface. The slopes in the high pressure region can be used to examine the intensity of asphaltene precipitation. As the addition of nanoparticles increases, the IFT slope in the high pressure range decreases. This is because the asphaltenes are absorbed at the surface of nanoparticles. As a result, the nanoparticles prevent asphaltene precipitation from accumulating at the CO2–oil interface, hence causing asphaltene to remain within the bulk of oil. The higher the mass fraction of Al2O3 nanoparticles is, the lower the intensity of the asphaltene precipitation would be. The coreflood results show that the injection of Al2O3 nanofluid can lessen the oil permeability reduction because the nanoparticles can inhibit the deposition of asphaltenes onto the sand surfaces in the porous media. The 0.5 wt % nanoparticles and the 0.1 nanofluid/CO2 slug volume ratio are considered as the optimum for inhibiting asphaltenes damage during CO2 flooding. Continuous CO2 and nanofluid injection could be more effective compared with the cyclic injection pattern.

The development of hydraulic fracturing has created a huge demand for fracturing fluids with high performance and low formation damage in recent years. In this paper, a foam stabilized by partially hydrophobic modified SiO2 nanoparticles and sodium dodecyl benzenesulfonate (SDBS) was studied as a fracturing fluid. The properties of SiO2/SDBS foam such as rheology, proppant suspension, filtration, and core damage were investigated. The experimental data showed that the stability and thermal adaptability of sodium dodecyl benzenesulfonate (SDBS) foam increased when silica (SiO2) nanoparticles were added. The surface tension of SDBS dispersion almost did not change after SiO2 nanoparticles were added; however, the dilational viscoelasticity of the interface increased, indicating that the SiO2 nanoparticles attached to the interface and formed a stronger viscoelasticity layer to resist the external disturbance. The proppant settling velocity in the SiO2/SDBS foam was found to be 2 orders of magnitude lower than that in a pure SDBS foam. The total leakoff coefficient of the SiO2/SDBS foam was found to be lower than that of an SDBS foam. Although the core damage ratio of the SiO2/SDBS foam was slightly larger than that of an SDBS foam, compared to GEL/SDBS, the core damage caused by the SiO2/SDBS foam remained at a low level. SiO2 nanoparticle–surfactant-stabilized foam is superior to a surfactant-stabilized foam and causes lower core permeability damage than a gel–surfactant-stabilized foam. It is recommended for use in hydraulic fracturing, particularly for fracturing stimulation in tight and shale gas reservoirs.

Aqueous foams were produced with partially hydrophobic SiO2 nanoparticles and sodium dodecyl sulfate (SDS) dispersions. The injection behavior of SiO2 stabilized foam (SiO2/SDS foam) was analyzed and compared with SDS stabilized foam (SDS foam). The experimental results showed that the SiO2 nanoparticles and SDS surfactants had a synergistic effect on foam stability at proper SDS concentration. And the effect was accompanied with a slight decrease in foam volume. The adsorption of nanoparticles on the bubble surface was confirmed by laser-induced confocal fluorescence microscopy. And the effect of absorbed nanoparticles on bubble surface viscoelasticity was also verified by the interfacial dilational rheological measurement. The dilational viscoelasticity increased with increasing SiO2 concentration, corresponding to foam stability. The plugging flow experiment demonstrated that the maximum differential pressure in SiO2/SDS foam flooding was 1.9 MPa, much higher than that in SDS foam flooding. The SiO2/SDS foam had better diversion properties and resistance to water flushing than SDS foam. In the oil displacement experiments, SiO2/SDS foam could reduce the residual oil saturation noticeably. The enhanced oil recovery and the final oil recovery could reach to 41.2% and 75.7%, respectively. It was deduced that the enhanced foam stability and dilational viscoelasticity were the main reasons for the effective performance in porous media.

Nitrogen foam flooding is a promising technique for enhanced oil recovery, but instability of the foam limits its application. In this article, partially hydrophobic modified SiO2 nanoparticles with an anionic surfactant, sodium dodecyl sulfate (SDS), were used together to increase foam stability. Micromodel flooding and sandpack flooding were adopted to assess the stability and effect on enhanced oil recovery of the SiO2 stabilized foam (SiO2/SDS foam). The experimental data showed that the foam stability was decreased with an increase in temperature, while the foam volume was increased first and then decreased. SiO2/SDS foam showed better temperature tolerance than the SDS foam (foam stabilized by SDS) due to the adsorption of nanoparticles on the surface of the bubble. Almost all of the bubbles maintained spherical or ellipsoidal shape with prolonged time due to the enhanced surface dilational viscoelasticity, which was different from that of SDS foam. According to the micromodel flooding results, SiO2/SDS foam displaced more oil than brine flooding, SDS solution flooding, or SDS foam flooding. As the foam stability was enhanced, gas mobility and channeling were controlled effectively. In addition, more oil on the pore wall and in the dead-end pores was displaced out because of the higher viscoelasticity of the SiO2/SDS foam. The sandpack flooding results showed that the increase of differential pressure and profile control effect was a proportional function of the SiO2 concentration in SiO2/SDS foam. The test with a higher SiO2 concentration resulted in a higher oil recovery when SiO2 concentration was less than 1.5 wt %.

A newly developed CO2–brine interfacial tension (IFT) correlation based on the alternating condition expectation (ACE) algorithm has been successfully proposed to more accurately estimate the CO2–brine IFT for a wide range of reservoir pressure, temperature, formation water salinity and injected gas composition. The new CO2–brine correlation is expressed as a function of reservoir pressure, temperature, monovalent cation molalities (Na+ and K+), bivalent cation molalities (Ca2+ and Mg2+), N2 mole fraction and CH4 mole fraction in injected gas. This prediction model is originated from a CO2–brine IFT database from the literature that covers 1609 CO2–brine IFT data for pure and impure CO2 streams. To test the validity and accuracy of the developed CO2–brine IFT model, the entire dataset was divided into two groups: a training database consisting of 805 points and a testing dataset consisting of 804 points, which was arbitrarily selected from the total database. To further examine its predicted capacity, the new CO2–brine IFT correlation is validated with four commonly used pure CO2–pure water IFT correlations in the literature, it is found that the new CO2–brine IFT correlation provides the comprehensive and accurate reproduction of the literature pure CO2–pure water IFT data with an average absolute relative error (% AARE) of 12.45% and standard deviation (% SD) of 18.57%, respectively. In addition, the newly developed CO2–brine IFT correlation results in the accurate prediction of the CO2–brine IFT with a % AARE of 10.19% and % SD of 13.16%, respectively, compared to two CO2–brine IFT correlations. Furthermore, sensitivity analysis was performed based on the Spearman correlation coefficients (rank correlation coefficients). The major factor influenced on the CO2–brine IFT is reservoir pressure, which has a major negative impact on the CO2–brine IFT. In contrast, the effects of CO2 impurities and salt components in the water on the CO2–brine IFT are in the following order in terms of their positive impact: bivalent cation molalities (Ca2+ and Mg2+), CH4, N2, and monovalent cation molalities (Na+ and K+).

Although foamy oil can improve the performance of solution gas drive in heavy oil, only about 5–15% original oil in place (OOIP) can be recovered under primary production. In this study, a series of micromodel flood experiments and sandpack flood tests were performed to evaluate the performances of water flooding, surfactant flooding, gas flooding, and foam flooding for enhancing the recovery of Orinoco Belt heavy oil after solution gas drive. Water flooding tests show that the sweep efficiency of water flooding was low as a result of the adverse mobility ratio caused by gas bubbles dispersed in the oil; about 10.57% OOIP was obtained in the sandpack study. Surfactant flooding tests indicate that the penetration of the surfactant solution into the heavy oil and the subsequent formation of gas bubbles and emulsified oil droplets in surfactant solution could reduce the mobility of water phase, thereby improving sweep efficiency, and oil recovery of 15.09% OOIP was recovered in the sandpack. Because of the viscous fingering, only 4.57% OOIP was obtained in the gas flooding test. The micromodel test of foam flooding shows that gas bubbles could reduce the mobility of the gas phase and the residual oil droplets could be pulled into oil threads by the viscoelasticity of gas bubbles, thereby reducing the residual oil saturation of foam flooding. The sandpack flood result shows that the oil recovery of foam flooding can reach 23.92% OOIP.

In order to improve the recovery effect of steam huff and puff in a super-heavy oil reservoir, the displacement efficiency of CO2 and viscosity breaker assisted steam flooding was studied through in-lab displacement experiments. The viscosity reduction mechanism of CO2 and viscosity breaker assisted steam huff and puff for horizontal wells was realized by numerical simulation. The results show that the displacement efficiency of CO2 and viscosity breaker assisted steam flooding (80.8%) is higher than that of steam flooding (65.4%). The CO2 and viscosity breaker assisted steam huff and puff technology for horizontal wells realizes the rolling replacement of viscosity reduction of viscosity breaker, CO2 and steam, thus effectively reducing the steam injection pressure, expanding the steam sweep area, i.e., expanding the viscosity reduction region and improving oil production rate. The viscosity region can be divided into four compound viscosity reduction areas according to temperature distribution and viscosity reduction mechanism. They are steam compound viscosity reduction region, hot water compound viscosity reduction region, low temperature water compound viscosity reduction region, and CO2-viscosity breaker compound viscosity reduction region. Field tests show that the CO2 and viscosity breaker assisted steam huff and puff technology for horizontal wells is effective in reducing viscosity and improving production of super-heavy oil reservoirs with deep and thin layers, deep and heavy layers, shallow and thin layers.

CO2 diffusion in oil-saturated porous media with low permeability is of great importance for the project design, risk assessment, and performance forecast of carbon capture and storage (CCS) or enhanced oil recovery (EOR). This paper developed a method to determine CO2 diffusion in oil-saturated cores under low permeability reservoir conditions. Core, crude oil and experimental parameters were taken from the representative low permeability reservoir. In the solution of the mathematical model, oil saturation was introduced in to diffusion equation, an oil-phase swelling caused by gas dissolution was considered, but a water-phase swelling was not, which is in agreement with the actual diffusion situation. The error caused by the state equation of carbon dioxide was eliminated, improving the calculation accuracy of the diffusion coefficient. The effects of pressure (6.490–29.940 MPa), temperature (70–150 °C), oil saturation (0–63.58%) and permeability (8.62–985.06 mD) on the diffusion coefficient of supercritical CO2 in low-permeability reservoirs were studied. The order of the diffusion coefficient is from 10−10 to 10−9 m2/s. The results show that with an increase in pressure and temperature, the CO2 diffusion coefficient in the porous media saturated with oil firstly increases significantly and then the rate of increase gradually slowed down. The CO2 diffusion coefficient increases greatly with the oil saturation in porous media. The CO2 diffusion coefficient first increases greatly with permeability, and when the permeability of the core is greater than approximately 100 mD, it remains almost stable. The experimental results can provide theoretical support for CO2 transport in porous media.

•A new surface tension model using Gibbs method and Ion-based SAFT2 is proposed.•Activity coefficients are represented accurately by Ion-based SAFT2.•Surface tensions of single/mixed electrolyte solutions are well extrapolated.•Surface tensions of associating mixtures are well extrapolated.A new surface tension model is proposed, based on the Gibbs phenomenological surface-phase method, coupled with Ion-based Statistical Associating Fluid Theory (Ion-based SAFT2). The model was used to extrapolate the surface tensions of aqueous electrolyte solutions and mixed electrolyte solutions, as well as systems of associating mixtures at different temperatures and concentrations, and was found to give good agreement with experimental data from the literature.

During the fracturing operations for oils and gases, not only the oil and gas reservoirs, but also the nearby civil aquifers are often polluted by the invasion of fracturing fluid filtrates. In this study, we investigated the potential of silica nanoparticles as a high-performance filtrate reducer for a foam fluid in a porous media. First, the three factors affecting filtration reduction using nanoparticles, i.e., surface rheology, foam slipping, and foam stability, were described. Then, the foam filtration through a porous media in the core was measured using a dynamic fluid-loss device, and the effects of foam quality, pressure drop, and core permeability on the performance of the filtrate reducer were evaluated. The difficulty of bubbles flowing from a throat to a pore in a porous media was described by resistance gradient coefficient Cf, which is a combination of surface tension and viscoelastic modulus and increases by adding nanoparticles. Nanoparticles improve the roughness of the SiO2/sodium dodecyl benzene sulfonate foam film surface, thus increasing the slipping resistance Fslip when foams flow on the wall of a throat in a porous media. For the foams in a porous media, the diffusion of bubbles decreased in the presence of nanoparticles, and the growth rate of gas bubble size also decreased, thus increasing the foam resistance to gas channeling. The results of core filtration tests indicate that the fluid-loss-control properties increased with foam quality ranging from 0 to 85%, and the negative effects of pressure drop and permeability increase to foam filtration were weakened by adding SiO2 nanoparticles. Thus, silica nanoparticles can be used as a high-performance filtrate reducer for a foam fluid in a porous media.Download full-size image