The utilization of synergistic mixtures of nanoparticles (NPs) and surfactants for enhanced oil recovery (EOR) has drawn increasing scientific attention. In this study, a series of coarse-grained (CG) molecular dynamics (MD) models were built to study the behaviors of NPs and surfactants in the vicinity of the oil/water interface. Hydrophilic, hydrophobic, and amphiphilic NPs were constructed to investigate the effect of hydrophobicity on the ability of NPs in term of interfacial tension (IFT) reduction. The synergistic effect of surfactants and NPs were also studied.
Surfactants and amphiphilic NPs can both accumulate at the interface of oil and water, while hydrophilic and hydrophobic NPs stay in water or oil phase. The NPs with various ratios of hydrophobic to hydrophilic domains were investigated to determine the types of NPs that result in the most IFT reduction. The comparison of IFTs indicates that amphiphilic NPs has a better ability to assist surfactants in further reducing the interfacial tension. Meanwhile, surface modification and the presence of surfactants can prevent the aggregation of NPs.
These MD simulation results allow us to figure out the physical behavior of NPs and surfactants at the oil/water interfaces. Analysis of the results can further assist the NPs synthesis for surfactant and/or surfactant-nanoparticle EOR applications in unconventional reservoirs.
Enhanced Oil Recovery (EOR) is well known for its potential to produce residual oil after the primary and secondary oil recovery. The residual oil is trapped in the narrow throat due to high capillary pressure, which is influenced by rock wettability and oil/water interfacial tension (IFT) (Wu et al., 2008). Surfactants have been widely investigated and employed in the EOR process to reduce the IFT and to alter the wettability (Sheng et al. 2015; Kamal et al., 2017; Negin et al., 2017). However, during the surfactant flooding, surfactants can adsorb onto the rock surfaces. This may result in the reduction of their concentrations, which significantly reduce the efficiency of surfactants in practical applications. The high cost of surfactants also makes this potential loss a critical issue. Many researchers have focused their studies on reducing the adsorption of surfactants by adding various materials in the chemical formulations.
Today, global energy demand increases significantly, but supply growth does not increase in the same proportion. The oil industry has been affected by the shortage of discoveries of new deposits of oil. Thus, it is compelling the development of cost-effective enhanced oil recovery (EOR) alternatives that allow the increase of the current hydrocarbons supply of actual reservoirs. Hence, the nanotechnology emerges as a good option as the use of nanoparticles and nanofluids has shown potential benefits in improving the efficiency of chemical treatments. Nevertheless, field applications of nanoparticles have been avoided due to current studies indicate that nanoparticles concentrations higher than 10,000 mg/L are needed, which disable the implementation due to high costs and the possibility of formation damage. Hence, the main objective of this study is the development for the first time of unconventional and engineered designed 0-D nanomaterials, namely NiO/SiO2 Janus nanoparticles that can be used for enhancing the oil recovery at low concentrations (~100 mg/L) without the risk of formation damage in the reservoir. These type of nanoparticles, due to its low size and 0-D characteristics, can improve the swept efficiency in the reservoir and increase the recovery. The primary mechanism of these nanomaterials is their strategic positioning at the oil/water interface and reduction of the interfacial tension. The Janus nanoparticles can migrate at the oil/water interface. The Janus-based nanofluids (nanomaterials dispersed in determined carrier fluid) flooding were assessed for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase, and altering the rock wettability, which impacts the capillary number and hence increases the crude oil recovery. The synthesized nanomaterials were characterized by TEM, stability, IFT, rheology, contact angle measurements and coreflooding tests under real reservoir conditions (fluids, pressure, temperature and rock samples) looking for flow assurance previous to a field trial. The results showed an increase of the capillary number at a very low concentration of 100 mg/L of both nanomaterials, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using conventional SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on the engineering designed nanomaterials at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.
Erzuah, Samuel (National IOR Centre of Norway, University of Stavanger) | Fjelde, Ingebret (International Research institute of Stavnger, UiS, National IOR Centre of Norway) | Voke Omekeh, Aruoture (IRIS, National IOR Centre of Norway)
The wetting properties of the reservoir rocks are governed by the tendency of the individual minerals constituting the reservoir rock to adsorb oil during crude oil/brine/rock (COBR) interactions. To explore the oil adhesion kinetics during COBR interactions, one approach is to assess the oil adhesion tendencies of the individual minerals. The aim of this presented study was to characterize the wettability by determining the oil adhesion tendencies of the minerals using Quartz Crystal Microbalance with Dissipation (QCM-D). The kinetics of the mass (Δmads) and the thickness (Δt) of the adsorbed film were modelled mathematically using the Sauerbrey relation with the QCM-D output as input. In addition, we present Surface Complexation modelling (SCM) evaluation of possible electrostatic linkages of the studied COBR system.
The kinetics of oil adsorption during COBR interactions were prominent during Formation Water (FW)/Stock Tank Oil (STO)/FW injection sequence with kaolinite sensor as compared to that of quartz. This was depicted by the relatively high change in the FW frequency signal (Δf) before and after the injection of STO with kaolinite sensor as compared to quartz. Negligible change in the frequency signal (Δf≈ 0) was observed during the various injection sequence with quartz sensor. This suggested that minor adsorption has taken place, thus confirming the hydrophilic nature of the quartz sensor. The mathematical modelling of the thickness (Δt) and the mass (Δmads) of the adsorbed film also reveals that kaolinite is more oil wet than quartz. This is portrayed by the relatively high magnitude of the adsorbed oil on kaolinite (Δt = 6nm - 14nm and Δm = 1600ng - 3500ng). The SCM results also confirm negligible (≈ 0.008) electrostatic pair linkage for the quartz sensor as compared to kaolinite (≈ 0.3). This shows that the tendency for oil to be adsorbed onto kaolinite sensors were relatively high as compared to quartz. The electrostatic pair linkages reveal that the dominant electrostatic pair linkage existing between the mineral- brine and the oil-brine interface was cation bridging by divalent cations such as Ca2+ and Mg2+. Hence, it was not surprising that the FW/STO/FW injection sequence for all the three (3) methods were relatively oil-wet as compared to similar sequence of optimum LSW composition. This was attributed to the abundance of Ca2+ and Mg2+ to bridge the two negatively charged surfaces in the former than in the latter.
Due to the favorable properties and versatility, the applications of ionic liquids (ILs) have been introduced in petroleum industry for different purposes including Enhanced Oil Recovery (EOR) processes. The ability of ILs to alter surface behavior of surfactant molecules by producing specific interactions with surfactant has motivated further investigation on its application to the important chemical EOR mechanisms, such as surface and interfacial tension lowering under reservoir conditions. The mixtures of in-house surfactant and different types of ILs (imidazolium- and eutectic-based ILs) as additives were formulated using different concentration ratio and prepared in fixed brine salinity. The surface tension (ST) and interfacial tension (IFT) behavior of the formulated mixtures were investigated by performing pendant and spinning drop tests at ambient and high temperature. In general, the extent of ST and IFT reduction was dependent on the type and concentration of ILs. The presence of ILs was able to lower both ST and IFT of surfactant solution and its effect as a function of ILs concentration was found to be more pronounced at high temperature. Of all ILs, eutectic-based IL showed the highest ability to decrease ST at any concentration used. Similarly, the eutectic-based IL was also regarded as the best ILs in lowering the surfactant solution/oil IFT even in the use of low concentration. From this study, it can be concluded that ILs can be proposed as new additives to alter the surface and interfacial behavior which are taking place through some surfactant-IL interactions and eventually improve surfactant performance in reducing ST and IFT. Surfactant solution with a lower ST due to the addition of ILs is expected to provide promising performance for surfactant-based EOR process involving gas mobility control application leading to enhancement of sweep efficiency, while a lower IFT value can provide favorable conditions for better oil displacement efficiency.
Surfactant application both in single or mixture fluid system has been continuously considered as a promising strategy to increase the oil recovery after waterflooding from mature fields (Alvarado and Manrique 2010). The ability of sufactants to undergo self-assembly at the interface due to their amphiphilic properties provides a solution in controlling the water/gas, crude oil/water, and crude oil/gas interactions (Sharma and Shah 1989). As the large interfacial areas are always required wherein the high amount of energy is needed, surfactant chemistry is used to lower the interfacial free energy resulting in reduced surface or interfacial tension (Schramm 2000). For instance, the addition of small amount of surfactant to water or brine would significantly lower the surface tension (ST) and the mechanical energy required for foam formation (Sanchez and Hazlett 1992, Hartland 2004). This behavior would be useful for foam mobility control application which is addressed to improved sweep efficiency. Moreover, the changes in interfacial properties due to surfactant presence impart a stabilizing influence in immiscible fluids system which is favorable for enhanced oil recovery (EOR) mechanisms, such as increasing the capillary number, producing ultra-low cude oil/brine interfacial tension, and altering the wettability (Sharma and Shah 1989). Different factors affecting oil displacement efficiency, such as salinity condition, mobility control, and surfactant formulations and their interactions have suggested the great importance of understanding the surface and interfacial behavior in a mixture fluid system under reservoir conditions. Critical micelle concentration (CMC), the typical property of surfactant, is also of interest because at concentration above this value the adsorption of surfactant at the interface becomes insignificant, indicating that the optimum reduction of surface or interfacial tension has been achieved (Myers 2005). In regards to displacement process, many types of commercial surfactant have been used and optimized by having a mixture of multiple species with interfacial properties variations and different effects on oil recovery (Hirasaki et al. 2008). The addition of supporting chemicals has also been considered, for instance, alcohols which can act as co-surfactant to achieve ultra-low IFT (Salager et al. 2013, Zhang et al. 2012). From the past decades, it has also been ascertained that the addition of salts is able to lower CMC value as well as reduce the surface and interfacial tensions of air/surfactant solution and oil/surfactant solution systems, respectively (Wan and Poon 1969). The synergistic effect between surfactant and salt mixtures in reducing interfacial tension has also been discussed suggesting that the addition of salt in surfactant system could influence the surfactant molecules arrangement at the interface and also the partitioning of the surfactant at the oil/water interface (Bera et al. 2013).
Wu, Junwen (Research Institute of Petroleum Exploration & Development, Dong Liao, Geological Exploration and Development Research Institute, Chuanqing Drilling Engineering Co. Ltd) | Lei, Qun (Research Institute of Petroleum Exploration & Development, Dong Liao, Geological Exploration and Development Research Institute, Chuanqing Drilling Engineering Co. Ltd) | Xiong, Chunming (Research Institute of Petroleum Exploration & Development, Dong Liao, Geological Exploration and Development Research Institute, Chuanqing Drilling Engineering Co. Ltd) | Zhang, Jianjun (Research Institute of Petroleum Exploration & Development, Dong Liao, Geological Exploration and Development Research Institute, Chuanqing Drilling Engineering Co. Ltd) | Li, Jun (Research Institute of Petroleum Exploration & Development, Dong Liao, Geological Exploration and Development Research Institute, Chuanqing Drilling Engineering Co. Ltd) | Cao, Guangqiang (Research Institute of Petroleum Exploration & Development, Dong Liao, Geological Exploration and Development Research Institute, Chuanqing Drilling Engineering Co. Ltd) | Wang, Yun (Research Institute of Petroleum Exploration & Development) | Jia, Min (Research Institute of Petroleum Exploration & Development) | Li, Nan (Research Institute of Petroleum Exploration & Development) | Liu, Yan (Research Institute of Petroleum Exploration & Development) | He, Chunyan (Research Institute of Petroleum Exploration & Development)
Decrease of gas production is an indicator that liquid column is probably building up in the well and an additional energy is required to lift the liquid out should be applied to control this situation.
Foaming agents provide a means to reduce the density of the liquid so that it can be removed from the well with the gas flow, unloading the accumulated liquid in gas and gas condensate wells. The main constituents of foaming agents are surface active agents. Foam stabilizers are added to increase foam stability. Foaming agent should be selected to form a stable foam under given condition, which means in the presence of salt or sweet water, hydrocarbon phase, at given temperature and pressure.
Currently, there are lots of different types of foaming agents. Previous studies mainly focused on the complex between anionic surfactant and anionic surfactant, anionic surfactant and amphoteric ion surfactant, however, the stability of the foam formed by such foaming agents is poor. Therefore, it is necessary to develop a robust foaming agent to cope with the harsh conditions. Traditional research neglect the study of complex between anionic surfactant and cationic surfactant, nevertheless the synergies between them through appropriate method can greatly improve the foam stability compared to one-component system. The strong electrostatic interaction between the opposite charge ionic head groups and the hydrophobic interaction between the hydrocarbon groups made the solution exhibit a complex phase behavior and microstructure which has a high surface activity and foam stability. Gemini surfactant contains a spacer and thus made the packing of molecules tighter and increased the cohesion of surfactant within the monolayer and enhanced the foam stability. Single molecule film formed by surfactant has certain dynamic characteristics, the gas can easily diffuse through the liquid film, so that the bubble burst. However, particles can be adsorbed in the gas/water interface to form a solid film which will reduce the drainage speed of the bubble to enhance the foam stability.
In summary, we proposed to develop a robust foaming agent using anionic-nonionic surfactant mixed with gemini cationic surfactant, stabilized by nanoparticles with certain hydrophilicity and size.
Enhanced oil recovery (EOR) methods often involve water-based flooding where surfactants, co-solvents and/or other chemicals are present in the aqueous phase being injected into the oil-bearing rock. The chemical flood may facilitate oil recovery by altering physical and chemical properties of the water-oil-chemical(s) system present in the porous medium such as interfacial tension, phase partitioning and liquid-liquid mixing. Prior to testing the efficiency of a chemical flood, initial laboratory experiments are routinely conducted to investigate the phase behaviour and thermodynamic properties (e.g. brine compatibility) of the present fluid system. However, such laboratory screening experiments consume significant time that scales linearly with the number of chemicals and combinations hereof to be characterized.
The Conductor-Like Screening MOdel (COSMO) has been developed over the last decades with the aim of predicting thermodynamics of complex mixtures based on single-molecule charge distributions. The charge distributions are calculated based on the molecular structure using density functional theory (DFT) to estimate molecular energies of quantum mechanical origin. Despite the fact that applications of COSMO have predominantly been used for biomedical, environmental, and chemical engineering research, applications of the theory show great promise for EOR research.
In this paper we demonstrate the versatility of applying the COSMO-theory to predict thermodynamic properties of water-oil systems, such as liquid-liquid mixing, phase partitioning, solubility, interfacial tension and ternary phase diagrams. Moreover, we describe an in-house developed database of 3D charge density landscapes of 100+ surfactants and present an in-depth analysis hereof with respect to single molecule properties as well as water-oil-surfactant system properties. Strikingly, we show that COSMO-theory in combination with a specific application of probability theory and the method of moments (MoM) can be used to estimate system properties such as interfacial tension, critical micelle concentration and phase partition coefficients.
We demonstrate that COSMO-theory provides a powerful framework for large-scale, fast and inexpensive initial computational prediction of single-molecule and continuum system properties. In particular we foresee that future applications of COSMO-theory to accurately estimate model input-parameters for chemical EOR simulators, such as UTCHEM, would be highly beneficial to the EOR research community.
This paper presents a new experimental technique and its computational scheme for studying gas mass transfer in the crude oil at high pressures and elevated temperatures by analysis of the measured dynamic and equilibrium interfacial tensions. In the experiment, a see-through windowed high-pressure cell is prefilled with a test gas at a prespecified pressure and a constant temperature. Then, a crude oil sample is introduced by using a specially designed syringe delivery system to form a pendant oil drop inside the pressure cell. Due to the dissolution of the gas into the pendant oil drop, the dynamic interfacial tension between the test gas and the crude oil keeps reducing and eventually reaches its equilibrium value when the saturation state is achieved. The sequential digital images of the dynamic pendant oil drop are acquired and analyzed by applying computer-aided image acquisition and processing techniques to measure the dynamic interfacial tensions at different times. Theoretically, a mathematical mass transfer model is formulated to describe the diffusion process of the gas in the pendant oil drop. This model is numerically solved by applying the semi-discrete Galerkin finite element method to obtain the transient gas concentration distribution inside the pendant oil drop. With a pre-determined calibration curve of the equilibrium interfacial tension versus the equilibrium gas concentration in the crude oil, the dynamic interfacial tension at any time is calculated. The mass transfer Biot number and the gas diffusion coefficient are thus determined by finding the best fit of the theoretically calculated dynamic interfacial tensions to the experimentally measured data. This newly developed experimental technique is applied to measure the mass transfer Biot number, the diffusion coefficient, and the interface mass transfer coefficient of CO2 in a reservoir oil sample at P=0.1~5.0 MPa and T =27°C.
It has been long recognized that interfacial interactions (interfacial tension, wettability, capillarity and interfacial mass transfer) govern fluid distribution and behavior in porous media. Therefore the interfacial interactions between CO2, brine and reservoir oil and/or gas should have an important influence on the effectiveness of any CO2 storage operation. As a model, the interfacial tension of the pure water-CO2 system has been studied intensively. Nevertheless, to our knowledge, no interfacial tension (IFT) equilibrium data for brine-CO2 systems are available at reservoir conditions for different salinities, temperatures and pressures.
In this paper, we present experimental IFT brine-CO2data obtained at high pressures (45 to 255 bar), high temperatures (27 to 100°C) and different salt concentrations (5,000 to 150,000 ppm of NaCl) using the axi-symmetric drop shape analysis technique (ADSA) for a rising drop case. Special attention was paid in developing a procedure to achieve true thermodynamic equilibrium. The themodynamic conditions were selected in order to cover the most practical CO2 storage cases of interest, liquid and supercritical CO2. A correlation was developped on the basis of the Parachor model, the salt effect and a regression fit of more than a hundred IFT experimental values obtained in this study. This correlation yields a Brine-CO2 IFT prediction at reservoir conditions with a mean absolute deviation of 2.5%. We also present correlations to determine the IFT increase due to salt concentration. The existence of a plateau in the brine-CO2 IFT values, independent of the temperature and the pressure and only dependent on the salt concentration, has been demonstrated from the experimental data for temperatures between 27 to 71°C and pressures above 150 bar. These pressure and temperature values can be easily found in many geological sites considered as prospects for CO2 storage. The linear dependency of the IFT increase with molal NaCl concentration has also been demonstrated.
Miscible CO2 gas injection is becoming the most popular enhanced oil recovery process for light oil reservoirs in the world. An accurate determination of miscibility conditions is essential to improve the economics of these gas injection projects. The terms, miscibility and solubility, are widely used in phase behavior studies of ternary fluid systems. The distinction between these two terms appears to be still hazy, leading to their synonymous use in some quarters. Furthermore, the relation of these two properties with interfacial tension has largely remained unexplored.
Recently, a new experimental technique of Vanishing Interfacial Tension (VIT) has been reported in the literature, relating miscibility with interfacial tension for gas-oil systems. Therefore, the objective of this study is to correlate miscibility and solubility with interfacial tension and to investigate the applicability of the new VIT technique to determine miscibility compositions in ternary fluid systems. For this purpose, a standard ternary liquid system of benzene, ethanol and water was chosen since their phase behavior and solubility data were readily available. The interfacial tension of benzene in aqueous ethanol at various ethanol enrichments was measured in pendant drop mode, using the Drop Shape Analysis (DSA) technique.
The experimental results indicate the applicability of VIT technique to determine miscibility conditions for ternary liquid systems as well. Comparison of IFT measurements with solubility data showed a strong mutual relationship between these two properties, in addition to demonstrating a clear distinction between solubility and miscibility. This study has identified the need to use pre-equilibrated solutions for IFT measurements in soluble regions in order to eliminate compositional effects on IFT. The interfacial tension appears to be independent of solvent-oil ratio in feed, provided pre-equilibrated solutions are used during experimentation. The conceptual extension of these experimental insights to gas-oil systems at reservoir conditions would be of immense use in determining miscibility conditions for gas injection EOR projects.