Oleic Phase Research Articles

Liquid nitrogen freezing method for exploring the mixing characteristics of liquid/liquid heterogeneous in outer packing cavity of Impinging Stream-Rotating Packed Bed

Impinging Stream-Rotating Packed Bed (IS-RPB) is a reactor developed to strengthen the mass and heat transfer in liquid-liquid mixing processes. The impingement, packing and packing edge cavity zones are crucial features in which mass transfer is highly relevant. In a heterogeneous system composed of an oleic and an aqueous phase, understanding the droplet diameter distribution in the packing edge cavity of an IS-RPB is a key to modeling and evaluating its mass transfer performance. However, such pattern is still unclear. In this work, the flow pattern of the oleic and aqueous phases, including the transitions of fluid ligament flow and droplet flow, and the oil droplet in mixing of oleic and aqueous phases in the packing cavity were studied under different experimental conditions by using a liquid nitrogen freezing method and studied by Optical microscopy. The results showed that droplet determined by this method has good reproducibility with a deviation within 8.4 %, and with a detection limit below 1 μm.

An experimental approach to low cost, high-performance surfactant flooding.

Surfactant flooding plays a key role in chemical enhanced oil recovery due to its ability to reduce interfacial tension between the aqueous and oleic phases, thereby mobilizing the trapped oil droplets into a flowing oil bank which invariably reduces the amount of residual oil saturation thus accounting for additional oil recovery of about 20%. However, the cost of surfactant chemicals has made surfactant flooding less attractive. Interestingly, recent experimental studies have reported that certain local materials capable of acting as surface active agents can effectively recover residual oil. This has attracted more interest due to their low cost, availability and eco- friendly nature. This paper reviews the oil displacement efficiency of different local surfactants in comparison with synthetic surfactant. Commonly used synthetic surfactant, Sodium dodecyl sulphate (SDS) and three different local surfactants namely AlkaSurf X (a hibiscus plant extract), Palm kernel oil (Elaeis guineensis) and Moringa leaf (Moringa oleifera) was evaluated in the laboratory using various concentration in a bid to compare their performance, however only two local surfactants; Moringa leaf (Moringa oleifera) and AlkaSurf X were used as the third surfactant failed the initial compatibility test. To simulate actual formation brine, brine samples were prepared in the laboratory using sodium chloride and potassium chloride with Total dissolved solids (TDS) of 30,000 ppm. Critical micelle concentration (CMC) was calculated to ascertain the right concentration to flood with. Sandstone oil displacement experiments using core plugs with porosity values ranging from 22%-23% was carried out on medium crude oil to ascertain the effectiveness of the selected local surfactants in recovering oil. Results showed high compatibility of the brine with all the selected local surfactants. As the brine salinity increased, the pH of the surfactant concentration increased. In line with the results obtained from the CMC plot, the synthetic surfactant performed best at 0.2 wt.% while the local surfactants performed best at a higher concentration of 0.4 wt%. Of the two local surfactants, AlkaSurf X gave the highest additional recovery of 22.7% OOIP while the synthetic surfactant gave an additional recovery of 20% OOIP. This study underpins the oil displacement efficiency of these local surfactants. Moreover, Alkasurf X can be considered as a novel, low-cost, high performing surfactant capable of enhancing oil recovery.

A novel technique to simulate low tension gas (LTG) process in fractured reservoirs with commercially available simulator

Low tension gas (LTG) process attempts to employ microemulsion (MI) and foam to enhance oil recovery (EOR). It is challenging to model surfactant phase behavior as a function of salinity for commercially available simulators since they lack the capability to explicitly represent MI properties. In this paper, a novel approach is developed to simultaneously model foam flow and surfactant/oil/brine key characteristics, using the general framework of CMG/STARS. Measured phase behavior data is transferred into k-value based relationships with multi-components oleic phase, based on which phase viscosities are calculated with non-linear mixing equation as function of different key components. Winsor Type phase variations are tracked by a pseudo-component generated by kinetic reactions, as another invention here. The mobility control by foam is fulfilled by the novel bubble dispersion model when increasing aqueous phase viscosity through bubble characteristics. Investigations of phase viscosities, IFT and compositions in 1D and 2D section models show that the developed methodology correctly accounts for surfactant solution desaturation in matrix and for mobility control by foam flow in the fractures. As such, the developed techniques provide a methodology to model LTG process in naturally fractured reservoirs within the framework of commercially available simulators along with their limited functionalities.

Parametric Investigation of Wettability Alteration of Reservoir Rocks by Asphaltene Deposition: Experimental and Modeling Approaches

Rock wettability plays an important role in water flooding process as it controls fluid flow, oil recovery and distribution of residual oil in any oil reservoir. In this context, polar oil components such as asphaltene contents may adsorb onto the pore mineral surfaces and alter wettability of the reservoir rock. Due to this importance, this study aims to investigate the effects of different parameters such as concentration of asphaltene, salinity, temperature and time on the rock wettability alteration process. For this purpose, dynamic contact angle measurement was performed. The results showed that the increment of asphaltene concentration in the oleic phase changes the wettability of water-wet sandstone rock to oil-wet condition; the increase in the concentration of asphaltene fraction from 0.1 to 5.0 g/lit increased the contact angle from 0 to 97 degrees. In addition, the increase in the brine salinity from 500 to 8000 ppm increased the ability of asphaltene to adsorb on the rock surface and consequently, increased oil wetness; the equivalent contact angle changed from 0 to 113 degree for 5 g/lit asphaltene content after 192 hours. Moreover, the results illustrated that a rise in temperature from 40 to 70 o C accelerates adsorption of asphaltene, but it has not significant effect on the final contact angle. Furthermore, the Adaptive Neuro-Fuzzy Inference System (ANFIS) is incorporated into the Particle Swarm Optimization (PSO) algorithm to correlate contact angle with the aforementioned parameters. To this end, the obtained experimental data are used to train and test the algorithm. The outputs of ANFIS-PSO algorithm are compared with the measured contact angles in both graphical and statistical manners. The training and testing determination coefficients (R 2 ) have been obtained as 0.99091 and 0.98761, respectively. The analysis indicates that the predictive model can be used with a high degree of confidence to investigate the effect of different parameters on wettability alteration

Effect of Components Concentration of ASP Chemical Flooding Solution on the Phase Behavior (Oil/ASP

In this research, the effects of the following factors on phase behavior of Oil/ASP solution were studied: Change of DDBSCa concentration in ASP solution on phase behavior of (Oil/ASP); Change of Na2CO3 concentration in ASP solution on phase behavior of (Oil/ASP) and Change of Xanthan Gum concentration in ASP solution on phase behavior of (oil /ASP) . Later The optimum concentrations of ASP components were restricted depending on phase behaviour The researcher has investigated this effect By studying change each of :oleic phase volume (Voleic) that result of emulsification between the oil and ASP solution - ASP solution volume that form emulsifier (Vd) . By relationship with (VASP%) which means : the percentage of ASP solution volume that added to the total volume (Oil+ASP solution) . The results referred to the following : the Miscibility of (ASP Oil) is affected strongly by components concentration of ASP solution. Also, The optimum concentrations of ASP solution components that achieve successful ASP flooding depending on phase behavior are compatible with the concentrations that I found from my previous studies that achieved : minimum interfacial tension at minimum concentration (regarding surfactant and alkaline). Maximum viscosity compatible with oil viscosity of the studied oil field (regarding the polymer).

Molecular insights in the temperature effect on adsorption of cationic surfactants at liquid/liquid interfaces

Surfactant adsorption at the oil-water interface plays a significant role in many industrial processes and natural phenomena. Electrolyte concentration and temperature are considered as controlling factors, which determine the surfactant adsorption, and, as a consequence, the associated interfacial tension. In this study, the influence of temperature on the interfacial tension of oil-water-surfactant (erucyl bis-(hydroxyethyl)-methylammonium chloride and cetyltrimethylammonium chloride) systems is examined by molecular dynamics simulations. The focus is on the fundamental difference in the molecular arrangements between surfactant molecules and their counterions at the water/n-decane interface when the temperature is increased. In addition, surfactant diffusion into the aqueous and oleic phases at different temperatures is also addressed. Clearly, as temperature increases, hydrogen bonding between water molecules and surfactant heads decreases, and thus surfactant molecule solubility in water also decreases. Results demonstrate that interfacial tension between water/n-decane in the presence of hydroxyl group containing surfactant differs from that predicted by Gibbs theory, and passes through minimum with temperature increase. This observation provides an important basis for studying the interfacial tension as a function of surfactant molecular structure at high temperatures, and can be used for primary evaluation of surfactants for their implementation in the oil recovery methods.

Effects of the capillary-entrapped phase on fines migration in porous media

A residual gas or oil present during fines migration in porous media can highly affect particle detachment, migration, and straining and thereby decrease rock permeability. Those effects are due to capillary forces and partial accessibility of the attached fines to the injected water under the presence of capillary-entrapped gaseous or oleic phase. We performed systematic study of fines migration in engineered sand-packs that contain different percentage of kaolinite and residual oil. Each coreflood consists of seven injections, the first with seawater ionic strength and the last with fresh water, and with piecewise-constant salinity decrease from step to step. Higher decline of permeability is found to occur during fresh water injection and to be accompanied by intensive fines production. Compared with fines migration under single-phase flow, having a residual phase significantly decreases the formation damage and the amount of produced kaolinite. For the first time, we determined dependencies of end-point saturations and end-point relative permeabilities versus kaolinite content. We established the phase permeability decrease with decrease in salinity for different kaolinite contents. The coreflood data are found to be in close agreement with the analytical model of 1D linear flow under the presence of residual phase. The laboratory-tuned model coefficients are used for well behaviour prediction using numerical 1D axisymmetric injection model.

Development of pickering emulsified polymeric gel system for conformance control in high temperature reservoirs

In the matured oil fields, the water production beyond the economical limits is a serious concern for oil and gas industry. The use of polymer gel systems for water production control is a reliable method, but has its own major complications. The major problem associated with polymer gel is the blocking of oil-producing zones along with other water producing zones. To solve this problem an organically cross-linked emulsified polymer gel system (Pickering emulsion) was proposed in this research article. The emulsion was supposed to break into aqueous phase and oleic phase encountering reservoir conditions. The aqueous phase was temperature triggered and converted into a gel in the pore spaces, which reduces the relative permeability to water. Whereas, the oleic phase forms thin film and provides a smooth channel for oil flow in the porous media. The prepared pickering emulsion was characterized and tested using confocal microscope, dilution test and emulsion droplet size distribution, etc. The effectiveness of the prepared emulsified gel was tested and analyzed by core-flooding experiments at 105 °C. The CT (tomographic) images of the core samples were also analyzed to clearly understand the effect of the emulsified gel on the core matrix. The core flooding experiments showed that the developed emulsified gel systems provide effective conformance control even at higher temperatures and found to be effective even in highly fractured reservoirs.

Nanoencapsulation of oleic acid phase change material with Ag2O nanoparticles-based urea formaldehyde shell for building thermal energy storage

Nanoencapsulated phase change material (NEPCM) was prepared with oleic acid as phase change material by its encapsulation into Ag2O nanoparticles (NPs)-based urea formaldehyde (UF) resin. NEPCMs were synthesized by in situ polymerization with different surfactants, to obtain a better shell material in terms of energy release, leak arrest and enhanced thermal properties. The morphology and particle size of the prepared NEPCM were analyzed by digital microscope and scanning electron microscope. Fourier transform infrared spectroscopy was used to determine the chemical structure. X-ray diffraction studies were carried out to ensure the presence of Ag2O NPs containing UF resin as shell material and its cubic crystal system. Thermo-physical properties were evaluated using differential scanning calorimetry (DSC), thermogravimetric analysis and thermal diffusivity analysis. DSC results revealed that the cationic surfactant-assisted synthesis of shell material has a comparatively good encapsulation ratio of 45.52%, and to further enhance the encapsulating capacity, Ag2O NPs was introduced. Addition of Ag2O NPs into the shell material shows improved encapsulation ratio of 54.82% with latent heat of 71.7 J g−1 for melting at 5.21 °C and hence better surface morphology, good thermal stability, better thermal conductivity and more suitability toward thermal energy storage in buildings.

The impacts of solubilized and dispersed crude oil on foam in a porous medium

Dispersed and solubilized oil can impact bulk foam stability differently. Though aromatic components are more soluble in water than straight-chain aliphatic components, solubilized aromatics do not necessarily impact the stability of foam in bulk or porous media, whereas straight-chain aliphatic components can have a detrimental impact (Bergeron et al., 1993; Lee et al., 2013). However, to our knowledge there is no published research on the impact of a solubilized crude oil on foam, as distinct from a separate oil phase, in a porous medium.To investigate whether the behaviour of steady-state foam with crude oil can be explained by solubilized oil components, we perform foam-flooding experiments with surfactant solution previously equilibrated with crude oil. Furthermore, we conduct foam-flooding experiments with hexane solubilized in the surfactant solution, to determine whether straight-chain aliphatic components can explain the behaviour of the solubilized crude oil on steady-state foam mobility, in the same way that they impact bulk foam in the literature.The impact of crude oil, as a separate, dispersed oleic phase, is studied here by co-injection of crude oil, surfactant solution and gas in core-floods, focusing on steady-state mobility, captured by the pressure gradient within the core. In our experiments crude oil, as a separate oleic phase, reduces the pressure gradient within the core up to a factor of twenty compared to the case without oil. Nonetheless, this pressure gradient is about a factor three greater than we observe by co-injecting crude oil, water without surfactant, and gas. With a simplified model we fit our three-phase co-injection experimental data by increasing the viscosity of both the gas and water, indicating that some weak foam and emulsion is generated. Neither effect by itself can fit the data.In contrast, with crude oil or hexane solubilized in the surfactant solution, the pressure gradient is of the same order of magnitude as for co-injection gas and surfactant with or without solubilized oil. These results indicate that solubilized crude oil does not reduce foam mobility as much as does the crude oil as a separate oleic phase. Furthermore, the effect of solubilized crude on foam is not due only to straight-chain aliphatic components such as hexane: our experiment with solubilized hexane showed a less-significant impact on foam mobility.The major result of our work is that we find that both gas and oil mobility are reduced when co-injecting oil, gas and surfactant solution in a porous medium. Another result is that the solubilized crude oil slightly reduces foam mobility, but does not explain the much-larger detrimental impact of crude oil in a separate phase on foam in a porous media.

Numerical simulation and laboratory evaluation of alkali–surfactant–polymer and foam flooding

Tertiary recovery techniques such as alkali–surfactant–polymer flooding (henceforth ASP) and foam flooding have been widely administered in production operations of oil reservoirs which have led to the higher value of oil recovery factor, especially in heavy-oil reservoirs. The objective of this extensive study is to provide a comparative study between numerical simulation which was used by the commercial software implicit pressure and explicit composition (henceforth IMPEC) and experimental investigation for different injectivity scenarios of foaming agent and ASP solution after water and gas flooding on the oil recovery enhancement. To do this, simulation parameters for each scenario were considered in the simulator to investigate the results of each scenario on the oil recovery enhancement. Due to the presence of a gas phase in the realistic performances, the experiments were performed in the presence of three-phase fluids to match the results with the operational circumstances. Moreover, regarding the lack of information about the considerable influence of in situ gas which is in the trapped and continuous phase, the dissolved gas is taken into the evaluation. To validate the simulation analysis, an experimental investigation was performed for different scenarios and selected the optimum injectivity scenario. Consequently, regarding the presence of gas phase, ASP flooding after gas and water flooding had the maximum oil recovery factor and was considered as the optimum technique to produce initial oil in place. The reason for this phenomenon is elaborated to the more feasibility of gas phase which had led to the more mobilization of the oleic phase in the porous medium.

RSM optimization of oil-in-water microemulsion stabilized by synthesized zwitterionic surfactant and its properties evaluation for application in enhanced oil recovery

Recent advances in formulation and designing of microemulsion with improved viscosity and an ability to reduce interfacial tension, miscibility with oil, have led to their application in enhanced oil recovery (EOR). The physicochemical properties of microemulsion varies widely depending on its composition, stability and temperature. In present study, an investigation has been made to formulate microemulsion using zwitterionic surfactant as amphiphile and mineral oil as oleic phase. The optimization of formulation of microemulsion with desired properties was obtained by response surface methodology (RSM). The accuracy and significance of model developed by RSM was tested by analysis of variance (ANOVA) and the model generated was used to analyse the effect of individual components on microemulsion formulation. The optimized microemulsion obtained using RSM was characterized by particle size and zeta potential analysis. The stability and miscibility tests of microemulsion showed excellent results for applicability in chemical EOR. The viscosity of the microemulsion was found to be around 300mPaS at 10s−1 shear rate, which is highly encouraging for its application in EOR to improve the mobility ratio. The interfacial reduction and wettability alteration properties of microemulsion was also found to be superior to that of surfactant solution. The core flooding experiment showed that the optimized microemulsion was able to recover 26.83% of additional oil as compared to 20.01% of oil recovery by surfactant flooding, over the conventional water flooding.

Effect of Newtonian and non-Newtonian viscosifying agents on stability of foams in enhanced oil recovery. Part I: under bulk condition

Foams show poor stability in enhanced oil recovery applications and stimulation processes in oil-well operations of oil fields. This paper presents a laboratory study to investigate the effect of Newtonian and non-Newtonian viscosity enhancement materials on improving the stability of foams at bulk conditions. For this goal, glycerol and hydrolyzed polyacrylamide (HPAM) were utilized to enhance the viscosity of foaming agents, which were composed of α-olefin sulfonate surfactant and salinity. To this end, a comparative study of the foam stability in surfactant solution containing different percentages of glycerol, HPAM polymer and a mixture of polymer with glycerol was undertaken. In a foam stability analysis, which was examined in the absence of an oleic phase, several characteristics such as foam volume evolution, foam half-decay time and a liquid fraction of foam were measured over a wide range of concentrations. Evaluating the conductivity and volume of injected gas during foam generation and foam decay provided the foam capacity and the maximum density parameters to characterize the foamability and stability of the generated foam in more detail. The results of bulk foam experiments indicated that polymer and glycerol could either increase or reduce the foamability, but both materials substantially increased foam stability within a certain range of concentrations. This could be explained by increasing the viscosity of the liquid phase of foam in the lamellae that attributed to decreased velocity of liquid drainage from the foam structure. Two regimes of foam drainage and coalescence demonstrated a different behavior for the same viscosity of solutions containing either glycerol or HPAM polymer. The solutions containing glycerol exhibited a small but sharp decay right after stopping the sparging gas, while for high polymer concentrations this did not happen.

Incorporation of multi-phase solubility and molecular diffusion in a geochemical evaluation of the CO2 huff-n-puff process in liquid-rich shale reservoirs

Despite the development of horizontal well and hydraulic fracturing technologies, natural depletion is limited in low productivity, and thereby considerable hydrocarbon remains in low permeable shale reservoirs. Recent researches proved that the deployment of CO2 huff-puff process could extract the remained hydrocarbon. They quantified various mechanisms behind the process and proposed the potential for CO2 sequestration in the shale formation. However, thorough understanding of fluid transport in the CO2 huff-n-puff process has not been completed due to complexity in tight shale formations. They had a lack to analyze potential factors affecting fluid flow in the system of oil/CO2/brine/shale formation: 1) aqueous solubility; 2) molecular diffusion in aqueous and oleic phases; and 3) geochemistry. Therefore, this study diagnoses the potential factors affecting fluid flow during CO2 huff-n-puff process in the shale oil reservoirs. Then, their effects are quantified by analyzing shale oil recovery and CO2 storage capacity.Since a fraction of injected CO2 dissolves in water and oil during the CO2 huff-n-puff process, transportability is acquired by molecular diffusion in aqueous and oleic phases. In addition, dissolution of CO2 changes the pH of in-situ brine, which is a sensitive factor in geochemistry, and thereby would change physical properties of formation. Implementing these mechanisms, this study simulates the CO2 huff-n-puff process in shale oil reservoirs. It is observed that effects of aqueous solubility and geochemistry decrease oil production by 3.2% and 6%, respectively. Approximately, up to 9.5% of CO2 to be injected is sequestrated in depleted shale formation via solubility mechanism. Molecular diffusion in oleic phase increases the oil production by 2%, but that in aqueous phase is negligible. For the accurate estimation of oil production and CO2 storage capacity in the simulation of CO2 huff-n-puff process for shale oil reservoir, the comprehensive model should consider potential factors such as aqueous solubility, molecular diffusion, and geochemical reactions. Because the potential factors have been neglected in the works of other types of shale reservoirs, the proposed approaches expect to expand our understanding in the CO2 injection to tight and shale gas/oil reservoirs.

Wettability and connectivity of overmature shales in the Fuling gas field, Sichuan Basin (China)

The Fuling gas field in Sichuan Basin, China, has produced greater than 1.5 × 1010 m3 (0.53 tcf) of natural gas from overmature Upper Ordovician Wufeng and lower Silurian Longmaxi shales. To systemically investigate the characteristics of wettability and connectivity and to understand the underlying causes of production behavior, we study five samples of Wufeng and Longmaxi shales with different total organic carbon contents and mineral compositions. Complementary approaches include mercury intrusion capillary pressure (MICP), contact angle measurement, spontaneous imbibition and saturated diffusion, and tracer (both nonsorbing and sorbing) migration mapped via laser ablation inductively coupled plasma mass spectrometry. According to measured contact angles and imbibition tests conducted on aqueous (deionized water and brine) and oleic (n-decane) phases, Wufeng and Longmaxi shales are strongly oil wet and moderately strong water wet. The lower boundary of estimated permeability obtained from n-decane imbibition can reach 137 nd, which is higher than the geometric mean permeability derived from the MICP method (5.5–68.8 nd). Effective diffusion coefficients of the Wufeng and Longmaxi shales are in the range of 10−13 m2/s (1.1 × 10−12 ft2/s). Tests of imbibition and saturated diffusion using tracer-containing brine show that concentrations of nanometer-sized tracers decrease rapidly (a factor of >10) over a migration distance of a few millimeters from the sample edge, suggesting the presence of poorly edge-connected water-wet pores. Sparsely connected hydrophilic pores, mixed wettability, and highly restricted pathways collectively contribute to the limited migration of nano-sized tracers, which probably results in the production behavior of initial steep decline and low overall recovery in the Fuling gas field.

Biphasic reaction of glycerol and oleic acid: Byproducts formation and phase transfer autocatalytic effect

Abstract This work investigates two new aspects of the biphasic esterification reaction of glycerol (G) and oleic acid (A), i.e. the formation of several oxidation/dehydration co-products and the effect of the ester products as phase transfer agents to accelerate the reaction. Potentiometric titration, FTIR, TG and especially paper electrospray mass spectrometry (PS-MS) were employed to analyze the products. Reactions with different G:A molar ratios (1:0.5, 1:1 and 1:2) without catalyst at 140, 160 and 180 °C showed oleic acid conversions of 50–80% to form the mono, di and triesters with several other by co-products due to dehydrogenation/oxidation of the oleic chain and dehydration of the glycerol moiety identified by PS-MS. The phase transfer autocatalytic effect was investigated by the addition of the oleate esters (2, 4 and 10 wt%) to the reaction. It was observed a strong acceleration of at the initial stage of the process indicating an autocatalysis likely due to a phase transfer effect. The reaction is discussed in terms of three stages. In the initial biphasic Stage 1, oleic acid suffers some dehydrogenation/oxidation and the esterification reaction takes place slowly at the glycerol-oleic acid interface to form mainly the monooleate ester which is an amphiphilic/tensoactive molecule. In the Stage 2, the amphiphilic ester products act as phase transfer agents taking glycerol molecules to the oleic acid phase for the formation of mono and mainly dioleate ester. At the Stage 3 in the presence of relatively high concentration of the tensoactive ester products the reaction becomes homogeneous/monophasic.

Visual investigation of viscous cross-flow during foam injection in a matrix-fracture system

A micromodel setup has been implemented to visualize foam propagation into the matrix and recovery of the matrix’s fluid. For simplicity, the experiments have been conducted in the absence of oleic phase; however, the achievements of this study can significantly affect the knowledge of foam flow in fractured reservoirs for enhanced oil recovery processes. New qualitative descriptions have been presented in terms of viscous cross-flow using well designed experiments and discussions. The effect of viscous cross-flow on the recovery of the matrix’s fluid has been evidenced via a mechanistic study based on the comparison of the recovery variation versus the foam quality, injection rate, and injectant type. Meanwhile, generation and coalescence mechanisms have been investigated. The results of these experiments demonstrate that a convective viscous cross-flow orthogonal to the direction of the mainstream (flow direction in the fracture) has been generated during foam injection that can significantly recover the bypassed fluid. In addition, it has been shown that foam invasion within the matrix controls the amount of ultimate recovery factor and is proportional to the foam viscosity in the fracture. Furthermore, the amount of recovery of the bypassed fluid increases as the foam quality increases. However, increasing the total injection rate causes a decrease in fluid recovery due to shear thinning behavior of foam.

Fluid displacement mechanisms by foam injection within a microfluidic matrix-fracture system

In this study, the researchers visually investigated changes in the saturation of fluids and the oil recovery factor (RF) during foam injection in a two-dimensional matrix-fracture micromodel system. The effects of the 1) presence of oleic phase (comparison of the results of foam injection tests with and without oil), 2) viscous force (comparison of the results of foam and gas injection tests), and 3) gravity force (comparison of the results of gas/foam injection tests in vertical and horizontal states) were mechanistically studied. The results showed that the presence of oleic phase has the potential to cause foam to degrade at the beginning of the test. However, as the experiment advanced and oil saturation was reduced, foam injection resulted in the recovery of the fluid in the matrix. Pressure decline in the fracture due to the high viscosity of the foam acted as a driving force perpendicular to the fracture in the matrix and caused a viscous cross-flow leading to a dramatic increase in oil recovery. Although the gravity force reduced the foam stability due to the foam film drainage process and the gravity segregation of gas and surfactant solution, a comparison of the performances of gas and foam in the vertical state revealed the superiority of foam injection.

Stabilization of Dispersed Oil Droplets in Nanoemulsions by Synergistic Effects of the Gemini Surfactant, PHPA Polymer, and Silica Nanoparticle.

Nanoemulsion systems comprising n-heptane (oleic component), stabilized by the {gemini surfactant (14-6-14 GS) + polymer [partially hydrolyzed poly-acrylamide (PHPA)] + silica (SiO2) nanoparticle} shell and dispersed in aqueous phase, were synthesized by ultrasonication (high-energy method). Influence of ultrasonication time on nanoemulsion kinetics was investigated to predict the saturation droplet diameter. Morphological analysis by transmission electron cryomicroscopy imaging showed that oleic phase appears as uniformly dispersed spherical droplets in 14-6-14 GS-stabilized nanoemulsion, which on PHPA addition changes into a network structure consisting of larger oil droplets. 14-6-14 + PHPA + SiO2 nanoemulsion systems show more effective packing arrangement with irregular-shaped (nonspherical) droplets. Dynamic light scattering studies identified droplet size distribution profiles in the range 4.2-25.4 nm for the surfactant-stabilized nanoemulsion, 125.9-358.8 nm for the surfactant-polymer nanoemulsion, and 88.4-222.3 nm for the surfactant-polymer-nanoparticle-based nanoemulsion in optimal dosage(s). Statistical analyses were performed using normal, log-normal, and Cauchy-Lorentz distribution functions. A modified form of Hinze theory was employed to model droplet behavior in analyzed nanoemulsion systems. Zeta potential values of nanoemulsions were studied at different time intervals to determine kinetic stability as well as corroborate Hinze model findings. In summary, this article aims at investigating nanoemulsion droplet stability by thorough examination of electrostatic repulsive barrier and steric hindrance effects.

Quantification of Viscosity for Solvents−Heavy Oil/Bitumen Systems in the Presence of Water at High Pressures and Elevated Temperatures

In this study, a new and pragmatic methodology has been developed to accurately predict the viscosity for light solvents (i.e., methane, ethane, propane, n-butane, n-pentane, N2, and CO2)–heavy oil/bitumen/water systems as a function of pressure in the temperature range of 287.9–463.4 K. The LV and ALV (L is the oleic phase, V is the vapor phase, and A is the aqueous phase) phase equilibria of the aforementioned systems are calculated using the Peng–Robinson equation of state (PR EOS) with modified alpha functions and binary interaction parameters (BIPs). The six widely used mixing rules for predicting viscosity of solvents−heavy oil/bitumen systems pertaining to vapor–liquid equilibria are compared and evaluated, while the linear mixing rule is used for hydrocarbons−water mixtures. Plus, effective density is for the first time successfully introduced into the volume-based mixing rules. The volume-based power law, weight-based power law, and weight-based Cragoe’s mixing rules are found to well reproduce t...