Optimum Surfactant Concentration Research Articles

Experimental Study on Forced Imbibition and Wettability Alteration of Active Carbonated Water in Low-Permeability Sandstone Reservoir

Summary Imbibition is one of the main mechanisms for fluid transport in porous media. A combination of carbonated water and active water [active-carbonated water (ACW)] has great prospects in enhanced oil recovery (EOR) and carbon reduction processes. To date, the law of hydrocarbon recovery induced by ACW imbibition is not clear. In this paper, the optimal surfactant concentration was first selected through a spontaneous imbibition experiment, and on this basis, CO2 was dissolved to form ACW. The imbibition effects of formation water (FW), surfactant solution DX-1, and ACW under different pressures were compared. The changes in rock wettability in the three imbibition solutions during imbibition were studied by measuring the contact angle. The effect of fracture on ACW imbibition was studied. Finally, the improved NB−1 was calculated to elucidate the mechanism of forced imbibition for EOR. The results show that 0.1% DX-1 produces the optimal imbibition effect. Pressure is positively correlated with imbibition recovery. ACW can significantly improve the imbibition effect due to its wettability reversal ability being better than those of FW and DX-1. CO2 in ACW can be trapped in the formation through diffusion into small rock pores. The contact angles of the three imbibition solutions decrease with increasing pressure. The contact angle between the rock and oil droplet in the ACW is as low as 38.13°. In addition, the fracture increases the contact area between the matrix and the fluid, thereby improving the imbibition effect. The alteration of NB−1 indicates that FW imbibition is gravity-driven cocurrent imbibition. DX-1 and ACW imbibitions are countercurrent imbibitions driven by capillary force and gravity. The above results demonstrate the feasibility of ACW in low-permeability reservoir development and carbon reduction.

Molecular dynamics simulation of surfactant induced wettability alteration of shale reservoirs

Shale oil has recently received considerable attention as a promising energy source due to its substantial reserves. However, the recovery of shale oil presents numerous challenges due to the low-porosity and low-permeability characteristics of shale reservoirs. To tackle this challenge, the introduction of surfactants capable of modifying wettability has been employed to enhance shale oil recovery. In this study, we perform molecular dynamics simulations to investigate the influence of surfactants on the alteration of wettability in shale reservoirs. Firstly, surfaces of kaolinite, graphene, and kerogen are constructed to represent the inorganic and organic constituents of shale reservoirs. The impact and underlying mechanisms of two types of ionic surfactants, namely, the anionic surfactant sodium dodecylbenzene sulfonate (SDBS) and cationic surfactant dodecyltrimethylammonium bromide (DTAB), on the wettability between oil droplets and surfaces are investigated. The wettability are analyzed from different aspects, including contact angle, centroid ordinates, and self-diffusion coefficient. Simulation results show that the presence of surfactants can modify the wetting characteristics of crude oil within shale reservoirs. Notably, a reversal of wettability has been observed for oil-wet kaolinite surfaces. As for kerogen surfaces, it is found that an optimal surfactant concentration exists, beyond which the further addition of surfactant may not enhance the efficiency of wettability alteration.

Study on the microstructural characteristics of coal and the mechanism of wettability of surfactant solutions at different pH levels

The effect of acidity and alkalinity of mine water on the ability of surfactants to wet coal was studied with contact angle measurements to determine the optimal aqueous surfactant concentration, quantitative osmosis experiments to characterize the wettability of coal, and atomic force microscopy to analyze the surface microstructure of the coal. The contact angle measurements showed that the optimum concentrations of both selected surfactants, sodium dodecyl sulfate (SDS) and coconut oil diethanolamide (CDEA), were 1.0 wt%, with contact angles on the coal samples of 25.8° and 36.1°, respectively, which were lower than from other concentrations of the surfactants. The use of quantitative osmosis experiments revealed that the acid-base environment of the surfactant solutions impacted the effect of the surfactants to different extents depending on the type of surfactant. SDS at pH = 9 had the best wetting performance and its osmosis height was 17.2 × greater than the treatment with water at pH = 7. Analyses with atomic force microscopy determined the effect of the wetting mechanism of the surfactant in different acid-base environments on the microstructural characteristics of the coal. The experiments showed that the surface morphology and pore structure of the coal changed after surfactant treatment in different acid-base environments, with more pore structures appearing on the surface of the coal samples. Both acidic and alkaline conditions could enhance the surface roughness of coal. Coal treated with SDS at a pH of 9 had the highest surface porosity of 13.8%. These studies clarify the microscopic wetting mechanism of the surfactants SDS and CDEA at different pH levels of mine water in terms of the microscopic surface morphology and pore structure of the coal, and provide an experimental basis for improving the wetting of coal and the water injection process of a coal seam.

Analysis of non-ionic surfactants on the rheological and interparticle response of polymer enhanced colloids for investment casting slurries

Dispersion of ceramic slurries for investment casting is governed by the colloidal solution and influenced by surfactants, where micelles form until a critical micelle concentration (CMC) is attained. Light scattering techniques and rheological methods were used to determine the CMC of three different non-ionic surfactants. The former provides an insight into the: zeta potential; electrical conductivity; and hydrodynamic diameter of the silica/polymer network, where the hydrodynamic diameter portrays a peak shift as the CMC is acquired. Rheological measurements display a reduction in the apparent viscosity with surfactant concentration before increasing by 3.7–15% upon approaching the CMC. The viscoelastic properties display an optimum surfactant concentration, where a stress softening behavior occurs at higher frequencies, known as the Payne effect. As the volume fraction increases, the elastic region extends to lower strains and the onset of recoverable energy occurs below the CMC, while the viscous response exhibits a resistance to flow.

Laboratory Study of Enhanced Oil Recovery with Used Palm Oil Surfactant Injection

Currently the waste generated from public consumption in Indonesia is very high. One such waste is used palm oil from households and food companies. Utilization of this waste in this research is by recycling waste oil into surfactants which will be used in the Enhanced Oil Recovery (EOR) process. The surfactant concentrations used were 1.3%, 1.5%, 2%, 2.2% and 2.5%. The research began with refining used cooking oil with banana peels for 24 hours. In order to make surfactants, the oil is mixed with KOH and distilled water. Additionaly, brine was made with a salinity of 15,000 ppm. With the interfacial tension test, a solution with an optimum surfactant concentration of 2.2% was obtained. The core flooding test was carried out using waterflooding followed by surfactant flooding at a temperature of 70 oC. From the test results obtained an incremental oil recovery factor of 8.57% and a total oil recovery factor of 47.43%.

Effect of chemicals on the phase and viscosity behavior of water in oil emulsions

Due to population growth, the need for energy, especially fossil fuels, is increased every year. Since the costs of exploring new reservoirs and drilling new wells are very high, most reservoirs have passed their first and second periods of life, and it is necessary to use EOR methods. Water-based enhanced oil recovery (EOR) methods are one of the popular methods in this field. In this method, due to the possibility of emulsion formation is high, and by creating a stable emulsion, viscosity and mobility improved. In this study, the parameters affecting the stability and viscosity of the emulsion have been investigated step by step. In the first step, 50% (v/v) of water has been selected as the best water cut. The type of salt and its best concentration was evaluated in the second step by measuring the average droplets size. The third step investigated the effect of SiO2 nanoparticles and surfactant (span80) on emulsion stability and viscosity. According to the results, the best amount of water cut was 50% due to the maximum viscosity. In salts the yield was as follows: MgCl2 > CaCl2 > MgSO4 > Na2SO4 > NaCl. The best yield was related to MgCl2 at a concentration of 10,000 ppm. Finally, it was shown that the synergy of nanoparticles and surfactants resulted in higher stability and viscosity than in the case where each was used alone. It should be noted that the optimal concentration of nanoparticles is equal to 0.1% (w/w), and the optimal concentration of surfactant is equal to 200 ppm. In general, a stable state was obtained in 50% water-cut with MgCl2 salt at a concentration of 10,000 ppm and in the presence of SiO2 nanoparticles at a concentration of 0.1% and span 80 surfactants at a concentration of 200 ppm. The results obtained from this study provide important insights for optimal selection of the water-based EOR operation parameters. Viscosity showed a similar trend with stability and droplet size. As the average particle size decreased (or stability increased), the emulsion viscosity increased.

Boosting Reaction Rate of Acids for Better Acid Fracturing Stimulation of Dolomite-Rich Formations

Summary Carbonate reservoirs can be stimulated by injecting acids to boost the rate of hydrocarbon production from low-permeability zones via the creation of conductive pathways. The reaction rate between the acidizing fluid and rock matrix is a key parameter in determining the success of stimulation treatments. Dolomite-rich formations are known to exhibit slower reaction kinetics as compared to calcite. As a result, some acid fracturing treatments fall short of creating an extended fracture or the desirable etching pattern on the fracture faces, thus limiting hydrocarbon flow. Accordingly, the development of an acid package to boost the dolomite dissolution rate will be advantageous to the efficiency of the stimulation treatment in dolomite-rich reservoirs. Accelerating the reaction rate of dolomite with strong mineral acid (i.e., hydrochloric acid, HCl) can be achieved through an additive-driven chemical approach based on the addition of judiciously selected sulfonate-based surfactants. To pinpoint the optimal surfactant(s) type and concentration, static dissolution testing was performed under ambient conditions using outcrop dolomite core samples (Silurian and Guelph). Each core sample was reacted with 28 wt% HCl in the presence and absence of sulfonate-based surfactant additives for a predetermined time. Selected surfactants are used in comprehensive reaction kinetics studies at reservoir conditions using a rotating disk apparatus (RDA). Based on the results of the ambient screening tests, three formulations were found to accelerate the reaction rate by up to 30% as compared to using 28 wt% HCl without the additive(s). The kinetics data collected at a pressure of 3,000 psi and temperatures of 175 up to 300°F showed that the reaction rate of Guelph dolomite can be accelerated by as much as 17–55% with one of the formulations. Coreflood experiments showed an increase in the acid PV to breakthrough (PVBT) when the surfactant package was added to the acid formulation pointing to a rise in the reaction rate of dolomite and the developed acid formulations. The acid formulations showed an improvement in the dolomite and acid reaction rate, which creates the opportunity to apply these formulations in the field to improve the outcome of acid fracturing treatments in dolomite-rich reservoirs.

Formulation and characterization of nanoemulsions stabilized by nonionic surfactant and their application in enhanced oil recovery

Nanoemulsions are kinetically stable emulsions with droplet size distribution in the range of 10–500 nm. Low interfacial tension (IFT), small droplet size, and wettability alteration properties of nanoemulsions have led to their application for enhanced oil recovery (EOR) EOR. The current study deals with the formulation and characterization of Tergitol 15-S-9 surfactant stabilized oil/water nanoemulsion (NE). Optimal surfactant concentration accompanied by optimal salinity determination was done by observing long-term stability. The stability of the nanoemulsions was analyzed by Turbiscan and Zeta potential analysis. The optimal nanoemulsion was characterized in terms of droplet size, rheology, wettability, miscibility, and IFT. All the prepared nanoemulsion showed particle size < 300 nm. optimized nano emulsion, that is, 0.5 wt.% surfactant +0.5 wt.% salinity showed good IFT reduction and wettability alteration capability. Nanoemulsion also showed good miscibility behavior with actual crude oil at 60 °C. Rheology of the formed emulsion shows a mixed nature that is shear thinning as well as shear thickening nature which is favorable for heterogeneous reservoirs. Core-flooding experiments were conducted at optimized nanoemulsion formulation, and additional oil recovery of 13.93% of the original oil in place was obtained after the conventional water flooding. Highlights Experimental and mechanistic investigation of nanoemulsions for oil recovery. Enhanced miscibility of Tergitol 15-S-9 stabilized nanoemulsion with crude oil. Viscosity enhancement by macromolecular and supramolecular network structures. Low IFT achieved for the nanoemulsion resulting enhanced oil displacement. Encouraging oil displacement by injection of formulated nanoemulsion.

Strategy to Enhance Geological CO2 Storage Capacity in Saline Aquifer

AbstractGeological CO2 storage is an emerging topic in energy and environmental community, which is, as a commonly accepted sense, considered as the most promising and powerful approach to mitigate the global carbon emissions during the transition to net‐zero. Of the geological media which initially considered cover the saline aquifers, oil and gas reservoirs, coal beds, and potentially basalts, up to now only the first two choices have been proven to be the most capable storage sites and successfully implemented at pilot/commercial scales. Here, two tandem papers propose novel strategies for the first time, by synthesizing and utilizing new high‐dryness CO2 foam, to enhance geological CO2 storage capacity in saline aquifer and oil and gas reservoirs. In this paper, a new high‐dryness CO2 foam is synthesized and injected into the saline aquifers to explore the storage capacity enhancement, with the unique foam‐induced advantages of sweep area expansion and storage efficiency improvement. Such a new idea is specifically evaluated and validated through a series of static analytical and dynamic performance experiments. With the optimum surfactant concentration of 0.5 wt%, the foaming volume and quality are determined to be 521 mL and 80.81%, respectively, which also shows excellent salt tolerance with 45,000 ppm Na+, 25,000 ppm Ca2+, and 25,000 ppm Mg2+. Moreover, the water consumption for CO2 storage decreases from 464.31 g/mol at 25% foam quality to 67.38 g/mol at 85% foam quality by using the new CO2 foam. Overall, the newly synthesized CO2 foam could effectively enhance geological CO2 storage capacity and concurrently diminish water consumption, therefore realizing the win‐win environment and economic benefits.

Enhancement of the wettability of a coal seam during water injection: effect and mechanism of surfactant concentrations above the CMC.

This paper determines the optimal surfactant concentration for enhancing coal's wettability and explores the wetting mechanism at surfactant concentrations above the critical micelle concentration (CMC) during coal seam water injection. In this study, laboratory experiments and field tests were used to investigate the influence of monomeric surfactants and compound surfactants at various concentrations on coal's wettability. The results showed that when the surfactant solution concentration was greater than the CMC, the coal's wettability was significantly enhanced as the surfactant concentration increased. However, the coal's wettability did not monotonically increase with the concentration, and the maximum value was reached in the range of 0.5-3 wt.%. Increasing the surfactant adsorption density and changing the adsorption state on the coal surface were the essential reasons surfactants continued improving the coal's wettability at concentrations above the CMC. The Marangoni flow effect and changes in the viscosity of the surfactant solution with concentration were also important factors that affected the coal's wettability.

The Influence of the Surface Chemistry of Cellulose Nanocrystals on Ethyl Lauroyl Arginate Foam Stability.

Guanidine-based surfactant ethyl lauroyl arginate (LAE) and cellulose nanocrystals (CNCs) form complexes of enhanced surface activity when compared to pure surfactants. The LAE-CNC mixtures show enhanced foaming properties. The dynamic thin-film balance technique (DTFB) was used to study the morphology, drainage and rupture of LAE-CNC thin liquid films under constant driving pressure. A total of three concentrations of surfactant and the corresponding mixtures of LAE with sulfated (sCNC) and carboxylated (cCNC) cellulose nanocrystals were studied. The sCNC and cCNC suspension with LAE formed thin films, with stability increasing with surfactant concentration and with complex rheological properties. In the presence of LAE, the aggregation of CNC was observed. While the sCNC aggregates were preferentially present in the film volume with a small fraction at the surface, the cCNC aggregates, due to their higher hydrophobicity, were preferentially located at film interfaces, forming compact layers. The presence of both types of aggregates decreased the stability of the thin liquid film compared to the one for the LAE solution with the same concentration. The addition of CNC to LAE was critical for foam formation, and foam stability was in qualitative agreement with the thin films' lifetimes. The foam volume increased with the LAE concentration. However, there was an optimum surfactant concentration to achieve stable foam. In particular, the very resistant foam was obtained with cCNC suspensions that formed the interfaces with a complex structure and rheology. On the other hand, at high LAE concentrations, the aggregates of CNC may exhibit antifoaming properties.

Designing Smart drilling fluids using modified nano silica to improve drilling operations in Geothermal wells

High pressure and high temperature (HPHT) conditions in geothermal wells have necessitated the need to develop thermally stable geothermal drilling mud systems to combat potential drilling complications. This is because mud fluids degrade under HPHT conditions due to high temperature effects. This study therefore aims to establish the optimum concentration of a cationic surfactant that would successfully modify the surface of silica nanoparticles and thereafter, evaluate the performance of modified nano silica as a rheological and filtration property enhancer in water-based muds (WBMs). The surface of silica nanoparticle was successfully modified by adding Hexadecyltrimethylammonium bromide (CTAB) to silica solution. Different mud formulations containing modified nano silica with varying zeta potential values, SNP3 -S2, SNP3 -S4, SNP3 -S5, SNP3 -S6, and SNP3 -S7 with -17.7 mV, 20 mV, 28.2 mV, 35.4 mV, and 37.1 mV respectively were investigated. Results showed that modified nano silica with the highest absolute value of zeta potential enhanced drilling mud rheology as temperature increased from 149°C to 232 °C. The optimal amount of CTAB was found to be between 1.0 and 2.0 wt.%. Filtration loss was reduced by 11.4, 17.6, and 29.5% on average for mud samples SNP3-S5, SNP3-S6, and SNP3-S7, respectively, at all temperatures. Mud cake thickness was reduced by 19.9, 11.6, and 28.7% on average by mud samples SNP3-S5, SNP3-S6, and SNP3-S7 respectively at all temperatures.

Eucalyptus saponin- and sophorolipid-mediated desorption of polycyclic aromatic hydrocarbons from contaminated soil and sediment

The potential for biosurfactant-mediated desorption of polyaromatic hydrocarbons (PAHs) was evaluated using PAH-spiked soil and sediment. PAH desorption behaviors and toxicity of novel saponin biosurfactant extracted from Eucalyptus camaldulensis leaves and sophoro-lipid biosurfactant were investigated. Their PAH desorption efficiencies were compared with rhamnolipid biosurfactant and the industrial-chemical surfactant, Tween 20. Based on the emulsification indices, the salt tolerance of surfactants up to 30 g/L NaCl followed the order of saponin > Tween 20 > sophorolipid > rhamnolipid, while the thermal stability over the range of 15 to 50 °C was in the order of sophorolipid > rhamnolipid > saponin > Tween 20. The saponin biosurfactant emulsion demonstrated the highest stability under a wide range of acidic to basic pHs. PAH extraction percentages of saponin and sophorolipid under the optimized surfactant concentration, volume, and incubation time were 30–50% and 30–70%, respectively. PAH desorption capacities of saponin and sophorolipid were comparable to that of rhamnolipid and Tween 20 for all matrices. Sophorolipid more efficiently desorbed low molecular weight PAHs in soil and sediment compared to the other three surfactants. Microbial respiration was used to determine biosurfactant toxicity to the soil/sediment microbiome and indicated no inhibition of respiration during 60 days of incubation, suggesting that sophorolipid- and saponin-mediated remediation may be sustainable approaches to remove PAHs from contaminated soils and sediments.

Optimization of surfactant-polymer formulations for improving oil production

This study investigated the optimal concentration of an anionic surfactant (APA-H1) and a sulfonated polyacrylamide (SPAM-A5) formulation for SP flooding at high temperature high salinity conditions. IFT, viscosity and oil production rate in micromodel tests of the formulation were evaluated from 200 to 2000 ppm in high salinity water at 90 °C. Results showed by injecting 1000 ppm APA-H1 and 1,500 ppm SPAM-A5 with ∼10−4 mN/m IFT and 5.4 cP viscosity, the highest incremental oil production was 27%, which were not improved by increasing chemical concentrations. The work reveals there exists an optimal range of surfactant polymer concentrations in SP flooding.

The Effects of Surfactant on the Stability of SiO2 nanofluid Prepared by Bead-milling Method

Typical nanofluid containing metal or non-metallic nanoparticles dispersed in water with high surface energy. This condition causes aggregation and leads to the instability of the nanofluid dispersion in media. The inclusion of surfactants during the bead-milling process can increase the amount of dispersion stability of nanofluids with bigger particle sizes. The aim of this study was to determine the optimum surfactant in stabilizing SiO2 nanofluid and investigate the effect of surfactant addition during the bead-milling process since the effect of different types of surfactant in the bead mill remains unclear and varied. The sol-gel method was used to synthesize SiO2 particles from waterglass. The preparation of SiO2 nanofluid began with screening surfactants to determine the optimum surfactant concentration. Then, the SiO2 nanofluid was prepared by using a bead mill with the addition of the surfactant. The Zeta potential analysis and particle size analyzer (PSA) were used to visualize the dispersion stability of all the prepared nanofluid samples. The results showed that adding 0.1 weight percent of PEG 6000 as a nonionic surfactant increased the stability of the dispersion, producing an average particle distribution of 502.7 nm and a zeta potential of -48.9 mV. The average value of particle size can be reduced using bead mill down to 241.7 nm (aggregate size) with 39.8 nm primary particle resulting in -45 mV zeta potential.

Selection of suitable surfactants for the incorporation of organic liquids into fresh geopolymer pastes

• Torque monitoring during emulsification of OL into fresh GP allows to have one-line viscosity. • Torque evolution allows to predict if OL will be successfully incorporated in GP or not. • Quaternary ammonium salts such as CTAB are well adapted to adjust the viscosity of fresh GEOIL. • Capillary forces between OL and MK were shown using Zêta potential measurements and Washburn tests. Geopolymers (GP) have recently emerged as suitable binders for the conditioning of radioactive organic liquids (OL). The condition for suitably incorporating high amounts of OL into GP is assessed in this research. A series of OL has been selected, comprising alkanes (dodecane and 2 paraffinic mineral oils), an industrial gear oil and tributylphosphate (TBP), in order to cover a wide range of viscosities (0.0018–2.33 Pa.s). The incorporation of viscous OL (>0.2 Pa.s) into fresh GP results in a regular torque increase, indicating a suitable process with the dispersion of the OL in the form of fine micrometric droplets. When the torque remains stable, for OL of low viscosity (<0.2 Pa.s) like TBP/Dodecane mixtures, the incorporation is not possible, or only partial in the form of large droplets quickly coalescing and leading to an organic supernatant above the hardened GP. For low viscosity OL, surfactants are required. The use of quaternary ammoniums (QAs) like cetyltrimethylammonium bromide (CTAB) has been studied. Torque monitoring shows that the OL is incorporated similarly in the GP slurry, whether the surfactant is introduced at the beginning, through the course or at the end of the mixing process. The torque evolution also provides the optimum surfactant concentration, by evidencing that beyond a certain concentration, the medium hardens too quickly, preventing the incorporation of OL. Finally, torque monitoring highlights that QAs with shorter alkyl chains, such as hexamethyltrimethylammonium, are able to replace CTAB with the same efficiency. Therefore, the powerful action of CTAB on the incorporation of alkanes into GP is attributed to its positive charge rather than to its surfactant effect.

Experimental Investigation of Foam Flooding Using Anionic and Nonionic Surfactants: A Screening Scenario to Assess the Effects of Salinity and pH on Foam Stability and Foam Height.

Gravity override and viscous fingering are inevitable in gas flooding for improving hydrocarbon production from petroleum reservoirs. Foam is used to regulate gas mobility and consequently improve sweep efficiency. In the enhanced oil recovery process, when the foam is introduced into the reservoir and exposed to the initial saline water saturation and pH condition, selection of the stable foam is crucial. Salinity and pH tolerance of generated foams are a unique concern in high salinity and pH variable reservoirs. NaOH and HCl are used for adjusting the pH, and NaCl and CaCl2 are utilized to change salinity. Through analyzing these two factors along with surfactant concentration, we have instituted a screening scenario to optimize the effects of salinity, pH, surfactant type, and concentration to generate the most stable state of the generated foams. An anionic (sodium dodecyl sulfate) and a nonionic (lauric alcohol ethoxylate-7) surfactants were utilized to investigate the effects of the surfactant type. The results were applied in a 40 cm synthetic porous media fully saturated with distilled water to illustrate their effects on water recovery at ambient conditions. This most stable foam along with eight different stabilities and foamabilities and air alone was injected into the sand pack. The results show that in optimum surfactant concentration, the stability of LA-7 was not highly changed with salinity alteration. Also, we probed that serious effects on foam stability are due to divalent salt and CaCl2. Finally, we found the most water recovery that was obtained by the three most stable foams by the formula of 1 cmc SDS + 0.5 M NaCl, 1 cmc SDS + 0.01 M CaCl2, and LA-7@ pH ∼ 6 from porous media flooding. Total water recovery for the most stable foam increased by an amount of 65% compared to the state of air alone. A good correlation between foam stability and foamability at higher foam stabilities was observed.

Development and Evaluation of Telmisartan Self Nano Emulsifying System

Self nano-emulsifying system drug delivery system (SNEDDS) is promising for drugs of BCS class II. The objective of present study to develop self nano-emulsifying drug delivery system for Lipophillic drug Telmisartan (TEL) to enhance the oral bioavailability of poorly water-soluble drug. TEL is an angiotensin II receptor blocker (ARB) and antihypertensive drug. Screening of Surfactant, Co-surfactant is done by percent transmittance and is also observed for turbidity or phase separation visually. Pseudo ternary phase diagram are constructed to identify the self-emulsifying regions and also to establish the optimum concentration of oil, surfactant and co-surfactant. For prepared formulation further characterization studies are done. Various studies like FTIR, SEM, Particle size, zeta potential is carried out for prepared SNEDDS. Further they are formulated into tablets and evaluated. All the results obtained are found to be in limits. From the present study it is clear that SNEDDS can be formulated to improve the dissolution and oral bioavailability of poorly water-soluble drug Telmisartan. Keywords: Bioavailability; poor water solubility; self-nanoemulsifying drug delivery system; telmisartan.

Utilization Of Methyl Ester Sulfonate As a Surfactant Raw Material in the Scouring, Bleaching and Dyeing Process of Rayon Fabric

The use of surfactants from palm oil as a wetting agent can be applied in the textile wet processes. Used cooking oil that has been through esterification and transesterification processes can be used as a raw material for surfactants. During this process, methyl ester sulfonate has been formed as a surfactant raw material. MES surfactant as an active ingredient in detergents has a detergency ability in water with a high hardness level, has a tolerance property to Ca 2+ ions, has a low foaming rate, and has good stability to pH. The purpose of this research is to utilize used cooking oil that has been processed through esterification, transesterification, and sulfonation for the surfactant manufacturing process which will later be used for wet textile processes and to determine the optimum concentration of surfactant produced in the cooking and dyeing process of rayon compared to commercial surfactants (teepol). The experiments carried out were the process of making surfactants from methyl esters into sulfonate methyl esters, through the processes of sulfonation, purification and neutralization. Then, testing the wetting time, absorbency of the fabric and testing the resistance of acid, base, and hardness. Then the surfactant product is applied to the cooking and bleaching processes simultaneously, then the dyeing process is continued with the surfactant as a cloth wetting agent in the dyeing process. Then tested the age and evenness of the dyed fabric color. The results showed that MES surfactant has almost the same properties as a teepol, which holds it hard and not resistant to acids and bases. It has a good wetting ability and can reduce surface tension so that the fabric can absorb water in 23,36 seconds. The optimum conditions were achieved in MES surfactant concentrations using 2 ml / L in the scouring bleaching process (simultaneous) and 2 ml / L in the dyeing process. The color saturation is 25.6148 and the color evenness results in a standard deviation of 0.395.

Performance of CO2 Foam Huff and Puff in Tight Oil Reservoirs

The challenges associated with unconventional reservoirs are related to their intrinsic nature: extremely low porosity and permeability. Combinations of horizontal wells and multistage hydraulic fracturing techniques have been developed to overcome the production obstacles and unlock the vast amount of oil in place in such formations. However, oil production still exhibits a sharp decline within the first 2 years after the stimulation, leading to an oil recovery of less than 15%. Thus, enhanced oil recovery methods need to be investigated to further increase the production rates and the recovery. In this study, laboratory experiments and numerical simulations were conducted to evaluate the performance of the CO2 foam huff and puff process and its impacts on oil recovery in tight oil formations. More specifically, the foam half-life was measured as a function of surfactant concentration and followed by the foam drainage ratio and its rheological properties in the subsequent tests. Reservoir simulations were conducted using the lab data and the field data collected from Cardium formation. Sensitivity analyses were finally carried out to investigate the effects of controlling variables on the CO2 foam performance. Experimental results revealed that the optimal surfactant concentration was found to be 0.2%, which is the critical micelle concentration point. Simulation results show that CO2 foam huff and puff can increase the oil recovery by more than 11% compared to that of the primary production. Moreover, sensitivity analyses show that the production time, injection time, and soaking time are the main effecting parameters, while the injection rate and the incremental injection rate are less important.