A comprehensive review on critical affecting parameters on foam stability and recent advancements for foam-based EOR scenario

A study on the bio-based surfactant sodium cocoyl alaninate as a foaming agent for enhanced oil recovery in high-salt oil reservoirs

Environmental awareness is receiving increasing attention in the petroleum industry, especially when associated with chemical agents applied in enhanced oil recovery (EOR) technology. The bio-based surfactant sodium cocoyl alaninate (SCA) is environmentally friendly and can be easily biodegraded, which makes it a promising alternative to traditional surfactants. Herein, the SCA surfactant is proposed as a foaming agent for enhanced oil recovery. Laboratory investigations on the surfactant concentration, foaming performance, microbubble characterization, interfacial tension, and foam-flooding of the traditional surfactants SDS and OP-10 have been conducted. In particular, the anti-salt abilities of these three surfactants have been studied, taking into consideration the reservoir conditions at Bohai Bay Basin, China. The results show that concentrations of 0.20 wt%, 0.20 wt% and 0.50 wt% for SCA, SDS and OP-10, respectively, can achieve optimum foaming ability and foaming stability under formation salinity conditions, and 0.20 wt% SCA achieved the best foaming ability and stability compared to 0.20 wt% SDS and 0.50 wt% OP-10. Sodium fatty acid groups and amino acid groups present in the SCA molecular structure have high surface activities under different salinity conditions, making SCA an excellent anti-salt surfactant for enhanced oil recovery. The microstructure analysis results showed that most of the SCA bubbles were smaller in size, with an average diameter of about 150 μm, and the distribution of SCA bubbles was more uniform, which can reduce the risk of foam coalescence and breakdown. The IFT value of the SCA/oil system was measured to be 0.157 mN m-1 at 101.5 °C, which was the lowest. A lower IFT can make liquid molecules more evenly distributed on the surface, and enhance the elasticity of the foam film. Core-flooding experimental results showed that a 0.30 PV SCA foam and secondary waterflooding can enhance oil recovery by more than 15% after primary waterflooding, which can reduce the mobility ratio from 3.7711 to 1.0211. The more viscous SCA foam caused a greater flow resistance, and effectively reduced the successive water fingering, leading to a more stable driving process to fully displace the remaining oil within the porous media. The bio-based surfactant SCA proposed in this paper has the potential for application in enhanced oil recovery in similar high-salt oil reservoirs.

Utilization of synthesized silane-based silica Janus nanoparticles to improve foam stability applicable in oil production: static study

This study investigated the effect of silane-based silica (SiO2) Janus nanoparticles (JNPs) on stabilizing the foam generated by different types of gases. Two types of SiO2 JNPs were synthesized through surface modification using HMDS and APTS silane compounds. Static analyses were conducted to examine the impact of different concentrations of the synthesized nanoparticles in various atmospheres (air, CO2, and CH4) on surface tension, foamability, and foam stability. The results indicated that the synthesized SiO2 JNPs and bare SiO2 nanoparticles exhibited nearly the same ability to reduce surface tension at ambient temperature and pressure. Both of these nanoparticles reduced the surface tension from 71 to 58-59 mN m-1 at 15,000 ppm and 25 °C. While bare SiO2 nanoparticles exhibited no foamability, the synthesis of SiO2 JNPs significantly enhanced their ability to generate and stabilize gas foam. The foamability of HMDS-SiO2 JNPs started at a higher concentration than APTS-SiO2 JNPs (6000 ppm compared to 4000 ppm, respectively). The type of gas atmosphere played a crucial role in the efficiency of the synthesized JNPs. In a CH4 medium, the foamability of synthesized JNPs was superior to that in air and CO2. At a concentration of 1500 ppm in a CH4 medium, HMDS-SiO2 and APTS-SiO2 JNPs could stabilize the generated foam for 36 and 12 min, respectively. Due to the very low dissolution of CO2 gas in water at ambient pressure, the potential of synthesized JNPs decreased in this medium. Finally, it was found that HMDS-SiO2 JNPs exhibited better foamability and foam stability in all gas mediums compared to APTS-SiO2 JNPs for use in oil reservoirs. Also, the optimal performance of these JNPs was observed at a concentration of 15,000 ppm in a methane gas medium.

Study on thermal insulation cement and its thermal insulation characteristics for geothermal wells

Reducing the heat loss in wellbore is the key for efficient development of geothermal resource. It is a reliable solution to establish a long-term stable wellbore with good thermal insulation through cementing. In this paper, the cement-based composite thermal insulation material was prepared by using cement as the cementing material, hollow glass beads, foaming agent and stabilizer as main raw materials, and other conventional admixtures. Foams and hollow glass beads can introduce gas with low thermal conductivity into cement, so as to improve the thermal insulation of composite material. Foams are produced by chemical forming process, using foaming agent, which is prepared according electrochemistry and thermodynamics, and the foam stabilizer helps foam distribute in cement slurry stably and uniformly. 10-13% hollow glass beads can significantly reduce the thermal conductivity of hardened cement, without significant adverse effects on the rheology and strength of the material. The thermal conductivity of the composite thermal insulation material can be as low as 0.2998 W·(m·K)^-1, which is 62% lower than that of conventional cement, while the compressive strength is 6.10 MPa, meeting the engineering requirement. A thermal-conductivity prediction method is proposed correspondingly based on Maxwell model, and the prediction error of the newly established model is within 2%. This research can provide technical support for efficient development of geothermal resources.

Predicting the aggregation number of cationic surfactants based on ANN-QSAR modeling approaches: understanding the impact of molecular descriptors on aggregation numbers

In this work, a quantitative structure-activity relationship (QSAR) study is performed on some cationic surfactants to evaluate the relationship between the molecular structures of the compounds with their aggregation numbers (AGGNs) in aqueous solution at 25 °C. An artificial neural network (ANN) model is combined with the QSAR study to predict the aggregation number of the surfactants. In the ANN analysis, four out of more than 3000 molecular descriptors were used as input variables, and the complete set of 41 cationic surfactants was randomly divided into a training set of 29, a test set of 6, and a validation set of 6 molecules. After that, a multiple linear regression (MLR) analysis was utilized to build a linear model using the same descriptors and the results were compared statistically with those of the ANN analysis. The square of the correlation coefficient (R ²) and root mean square error (RMSE) of the ANN and MLR models (for the whole data set) were 0.9392, 7.84, and 0.5010, 22.52, respectively. The results of the comparison revealed the efficiency of ANN in detecting a correlation between the molecular structure of surfactants and their AGGN values with a high predictive power due to the non-linearity in the studied data. Based on the ANN algorithm, the relative importance of the selected descriptors was computed and arranged in the following descending order: H-047 > ESpm12x > JGI6> Mor20p. Then, the QSAR data was interpreted and the impact of each descriptor on the AGGNs of the molecules were thoroughly discussed. The results showed there is a correlation between each selected descriptor and the AGGN values of the surfactants.

Fundamental Investigation on a Foam-Generating Microorganism and Its Potential for Mobility Reduction in High-Permeability Flow Channels

This study proposed a novel foam EOR technique using Pseudomonas aeruginosa to generate the foam and investigated the potential of the microbial foam EOR to modify the permeability of a high-permeability porous system. We investigated oxygen nanobubble, carbon dioxide nanobubble and ferrous sulfate concentrations to discover the optimal levels for activating the foam generation of the microorganism through cultivation experiments. We also clarified the behavior of the microbial foam generation and the bioproducts that contribute to the foam generation. The potential of the foam to decrease the permeability of high-permeability porous systems was evaluated through flooding experiments using sand pack cores. The foam generation became more active with the increase in the number of nanobubbles, while there was an optimal concentration of ferrous sulfate for foam generation. The foam was identified as being induced by the proteins produced by the microorganism, which can be expected to bring about several advantages over surfactant-induced foam. The foam successfully decreased the permeability of high-permeability sand pack cores to half of their initial levels. These results demonstrate that the microbial foam EOR has the potential to decrease the permeability of high-permeability porous systems and improve the permeability heterogeneity in oil reservoirs.

Microfluidic Investigation of Foam Coarsening Dynamics in Porous Media at High-Pressure and High-Temperature Conditions

Coarsening or Oswald ripening, induced by interbubble gas diffusion, is considered to dominate foam structure evolution in porous media. We present the first study of trapped foam coarsening dynamics under realistic deep reservoir conditions (up to 3200 psi/22 MPa of pore pressure and 100 °C of temperature) in a high-pressure and high-temperature microfluidic system. The findings are expected to help predict foam structure evolution in applications such as enhanced oil recovery and CO₂ geological sequestration. It is shown that, in porous media, larger bubbles grow at the expense of smaller bubbles. The growth rate of the average bubble area (⟨a⟩) over time shows a long-term linear increase when ⟨a⟩ is between 1/5 and 1/2 of the average pore size. The foam coarsening kinetics are determined by the liquid film permeability, gas-liquid interfacial tension, and the molar volume of the dispersed phase. In summary, foams prepared with less water-soluble gases (e.g., N₂ and air) and lower foam quality show slower coarsening kinetics due to a lower film permeability. Foam coarsening is more sensitive to surfactant concentration (than surfactant type), as it determines the interfacial tension that controls the mass transfer driving force (capillary pressure difference). The transport properties of the dispersed phase depend strongly on its density, which increases with increasing pore pressure and decreasing temperature. At the same experimental conditions, gas CO₂ foam shows a 10-fold faster coarsening rate than N₂ foam. However, dense (i.e., liquid and supercritical) CO₂ foams show a remarkable 20-500-fold reduction in coarsening kinetics compared with gas N₂ and CO₂ foams due to the significantly reduced mass transfer driving forces. In a sense, trapped CO₂ foam can be stronger than N₂ foam at high-pressure and high-temperature conditions.