Experimental Investigation of Surfactant Partitioning in Pre-CMC and Post-CMC Regimes for Enhanced Oil Recovery Application

The applications of surfactants in Enhanced Oil Recovery (EOR) have received more attention in the past decade due to their ability to enhance microscopic sweep efficiency by reducing oil-water interfacial tension in order to mobilize trapped oil. Surfactants can partition in both water and oil systems depending on their solubility in both phases. The partitioning coefficient (Kp) is a key parameter when it comes to describing the ratio between the concentration of the surfactant in the oil phase and the water phase at equilibrium. In this paper, surfactant partitioning of the nonionic surfactant Alkylpolyglucoside (APG) was investigated in pre-critical micelle concentration (CMC) and post-cmc regimes at 80 °C to 106 °C. The Kp was then obtained by measuring the surfactant concentration after equilibration with oil in pre-cmc and post-cmc regimes, which was done using surface tension measurements and high-performance liquid chromatography (HPLC), respectively. Surface tension (ST) and interfacial tension (IFT) behaviors were investigated by performing pendant and spinning drop tests, respectively—both tests were conducted at high temperatures. From this study, it was found that APG was able to lower IFT as well as ST between water/oil and air/oil, and its effect was found to be more profound at high temperature. The partitioning test results for APG in pre-cmc and post-cmc regimes were found to be dependent on the surfactant concentration and temperature. The partitioning coefficient is directly proportional to IFT, where at high partitioning intensity, IFT was found to be very low and vice versa at low partitioning intensity. The effect of temperature on the partitioning in pre-cmc and post-cmc regimes had the same impact, where at a high temperature, additional partitioned surfactant molecules arise at the water-oil interface as the association of molecules becomes easier.

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EFFECT OF LOW TEMPERATURE CO2 INJECTION IN HIGH TEMPERATURE OIL RESERVOIRS USING SLIMTUBE EXPERIMENT

Jurnal Teknologi ◽

10.11113/jt.v78.9018 ◽

2016 ◽

Vol 78 (6-6) ◽

Cited By ~ 1

Author(s):

Zakaria Hamdi ◽

Mariyamni Awang

Keyword(s):

High Temperature ◽

Low Temperature ◽

Interfacial Tension ◽

Oil Recovery ◽

Early Stage ◽

Recovery Factor ◽

Effect Of Temperature ◽

Co2 Injection ◽

Sweep Efficiency ◽

Injection Point

A set of slimtube experiments is designed and presented to study the effect of cold temperature CO2 on recovery factor in reservoirs with high temperature. The comparison of the results indicates the positive effect of temperature on recovery trend in early stage as well as ultimate recovery in different injection pressures. The approach is based on a long slimtube to show the effect of temperature on the recovery. The study considers different temperatures and pressures of injection and reservoir allowing both miscible and immiscible flooding of CO2. Using non-isothermal conditions, the results show that, lowering temperature of injection can yield in higher recovery in early stage significantly. Also, considering ultimate recovery, it is observed that low temperature CO2 injection into high temperature reservoir can result in slightly higher recovery factor than isothermal injection. The reason for recovery increase is mainly due to elimination of the interfacial tension between CO2 and reservoir fluids especially near the injection point. Another finding is that the minimum miscibility pressures is lowered by means of lowering the temperature of injection which is again caused by elimination of interfacial tension between CO2 and oil. This is important because forming a single phase can increase the ability of CO2 to extract different components of the crude oil as well as lowering viscosity of the mixture, resulting in a better sweep efficiency. It appears that using liquid CO2 in high temperature reservoirs can be a promising method for better oil recovery in high temperature reservoirs.

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Enhanced Oil Recovery: Chemical Flooding

Geophysics and Ocean Waves Studies ◽

10.5772/intechopen.90335 ◽

2021 ◽

Author(s):

Ahmed Ragab ◽

Eman M. Mansour

Keyword(s):

Interfacial Tension ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Recovery Phase ◽

Mobility Ratio ◽

Chemical Flooding ◽

Sweep Efficiency ◽

Oil Displacement ◽

Remaining Oil ◽

Oil Displacement Efficiency

The enhanced oil recovery phase of oil reservoirs production usually comes after the water/gas injection (secondary recovery) phase. The main objective of EOR application is to mobilize the remaining oil through enhancing the oil displacement and volumetric sweep efficiency. The oil displacement efficiency enhances by reducing the oil viscosity and/or by reducing the interfacial tension, while the volumetric sweep efficiency improves by developing a favorable mobility ratio between the displacing fluid and the remaining oil. It is important to identify remaining oil and the production mechanisms that are necessary to improve oil recovery prior to implementing an EOR phase. Chemical enhanced oil recovery is one of the major EOR methods that reduces the residual oil saturation by lowering water-oil interfacial tension (surfactant/alkaline) and increases the volumetric sweep efficiency by reducing the water-oil mobility ratio (polymer). In this chapter, the basic mechanisms of different chemical methods have been discussed including the interactions of different chemicals with the reservoir rocks and fluids. In addition, an up-to-date status of chemical flooding at the laboratory scale, pilot projects and field applications have been reported.

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Effects of Interfacial Tension, Emulsification, and Surfactant Concentration on Oil Recovery in Surfactant Flooding Process for High Temperature and High Salinity Reservoirs

Energy & Fuels ◽

10.1021/acs.energyfuels.5b01393 ◽

2015 ◽

Vol 29 (10) ◽

pp. 6165-6176 ◽

Cited By ~ 54

Author(s):

Cheng-Dong Yuan ◽

Wan-Fen Pu ◽

Xiao-Chao Wang ◽

Lin Sun ◽

Yu-Chuan Zhang ◽

...

Keyword(s):

High Temperature ◽

Interfacial Tension ◽

Oil Recovery ◽

Surfactant Concentration ◽

High Salinity ◽

Surfactant Flooding

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Advances in Evaluation of Surfactant Performances at High Temperature by Static Foam Tests

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.1133.634 ◽

2016 ◽

Vol 1133 ◽

pp. 634-638 ◽

Cited By ~ 2

Author(s):

Mudassar Mumtaz ◽

Isa Mohd Tan ◽

Muhammad Mushtaq ◽

Muhammad Sagir

Keyword(s):

High Temperature ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Foam Stability ◽

Foam Height ◽

Surfactant Molecule ◽

Sweep Efficiency ◽

Endurance Time ◽

Alpha Olefin ◽

Designed Experiment

—Foam stability and mobility reduction are the key parameters for foam assisted enhanced oil recovery. The harsh conditions such as high temperature, pressure and salinity present in an oil reservoir tend to destabilise the foam leading to poor sweep efficiency. Screening for the best performing foaming recipes has been performed to ascertain foam stability in the presence and absence of oil. Static foam test has been performed in order to study the foam stability and foam oil interactions at 90°C. Two anionic surfactants, alpha olefin sulphonate (AOS14-16) and methyl ester sulphonate (MES16-18) were mixed with betaine (foam booster) in different proportions to design the formulations. In addition to the ternary formulations, binary formulation involving surfactant and betaine were also evaluated for foam stability. For the study of oil effects on foaming performance of surfactant formulation, n-decane, diesel and Dulang crude oil are used. The recipes were evaluated by static foam tests to note the foam height and endurance time. It was found that the anionic surfactant played a major role in foam stability and the betaine was found less significant. However, the betaine alone was found effective for foaming and was poor for endurance time. While in mixture, the surfactant and betaine were found to interact strongly and a profound synergistic effect was noted. During oil interaction studies, the alkane type oils of low molecular weight become solubilised with surfactant molecule forming an emulsion and hence decimate the foam stability. However, higher alkanes with molecular chain more than ten carbon atoms (decane) stabilised the foam because of low solubilisation efficiency between surfactant and oil to form emulsions. The obtained results of the designed experiment have been analysed and discussed in detail to understand the contribution of individual component as well as their interactions with each other in order to stabilize foams.Keywords—Static Foam, Foam-Oil interactions, AOS, MES, Enhanced Oil Recovery

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Interfacial Tension Measurement of Light Oil from Thailand to Enhance Oil Recovery for Surfactant Flooding Application

Materials Science Forum ◽

10.4028/www.scientific.net/msf.890.235 ◽

2017 ◽

Vol 890 ◽

pp. 235-238 ◽

Cited By ~ 1

Author(s):

Chitipat Chuaicham ◽

Kreangkrai Maneeintr

Keyword(s):

Interfacial Tension ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Surfactant Concentration ◽

High Salinity ◽

Surfactant Flooding ◽

Sodium Dodecylbenzenesulfonate ◽

The North ◽

Light Oil ◽

Enhance Oil Recovery

To enhance oil recovery, surfactant flooding is one of the techniques used to reduce the interfacial tension (IFT) between displacing and displaced phases in order to maximize productivity. Due to high salinity of crude oil in the North of Thailand, surfactant flooding is a suitable choice to perform enhanced oil recovery. The objective of this work is to measure the IFT and observe the effects of parameters such as pressure, temperature, concentration and salinity on IFT reduction. In this study, sodium dodecylbenzenesulfonate is used as surfactant to reduce IFT. The results show that the major factor affecting reduction of IFT is surfactant concentration accounting for 98.1%. IFT reduces with the increase of salinity up to 86.3% and up to 9.6% for temperature. However, pressure has less effect on IFT reduction. The results of this work can apply to increase oil production in the oilfield in the North of Thailand.

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Laboratory evaluation of an efficient low interfacial tension foaming agent for enhanced oil recovery in high temperature flue-gas foam flooding

Journal of Petroleum Science and Engineering ◽

10.1016/j.petrol.2020.107580 ◽

2020 ◽

Vol 195 ◽

pp. 107580 ◽

Cited By ~ 2

Author(s):

Huanquan Sun ◽

Zhiwei Wang ◽

Yeheng Sun ◽

Guanghuan Wu ◽

Baoquan Sun ◽

...

Keyword(s):

High Temperature ◽

Interfacial Tension ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Flue Gas ◽

Laboratory Evaluation ◽

Foaming Agent ◽

Low Interfacial Tension ◽

Foam Flooding

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Experimental Study on Low Interfacial Tension Foam for Enhanced Oil Recovery in High-Temperature and High-Salinity Reservoirs

Energy & Fuels ◽

10.1021/acs.energyfuels.7b02624 ◽

2017 ◽

Vol 31 (12) ◽

pp. 13416-13426 ◽

Cited By ~ 9

Author(s):

Jiaping Tao ◽

Caili Dai ◽

Wanli Kang ◽

Guang Zhao ◽

Yifei Liu ◽

...

Keyword(s):

Experimental Study ◽

High Temperature ◽

Interfacial Tension ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

High Salinity ◽

Low Interfacial Tension

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The Effect of Temperature on Gelation Time for Polyacrylamide/Chromium (III) Systems

Society of Petroleum Engineers Journal ◽

10.2118/10059-pa ◽

1982 ◽

Vol 22 (04) ◽

pp. 463-471 ◽

Cited By ~ 28

Author(s):

Deborah S. Jordan ◽

Don W. Green ◽

Ronald E. Terry ◽

G. Paul Willhite

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Reaction Rate ◽

Gelation Time ◽

Reducing Agent ◽

Effect Of Temperature ◽

Sweep Efficiency ◽

Temperature Range ◽

Production Wells ◽

Low Efficiency

Abstract Gelled polymers are being applied to modify the movement of injected fluids in the vicinity of injection and production wells in secondary and enhanced oil-recovery projects. One approach to gelation is to form a bulk gel in situ by injecting a slug of a polyacrylamide polymer solution containing chromium (VI) followed by a polymer slug containing a reducing agent such as sodium bisulfite. Upon mixing, CR(VI) is reduced to Cr(III), and in the subsequent reaction a gel is formed. The gelation time controls the volume of fluid that can be injected in the treatment and thus is an important variable in the process. Gelation time is known to be a function of the concentration of the reactants (chromium ion, reducing agent, and polymer) as well as the polymer type, and some data relating these variables to gelation time have been reported. Another variable affecting the reaction rate is temperature, but no data relating gelation time and temperature have been published. The purposes of the work described in this paper were to obtain experimental data on the effect of temperature on gelation time for typical polyacrylamide/Cr(III) gel systems over the range of temperatures commonly encountered in reservoirs and to develop a method of correlating the data. Gelation times were measured for five different polymers, including polymers with various degrees of hydrolysis and polymers with nonionic, anionic, and cationic character. The temperature range was 25 to 80 deg. C. Polymer, metal ion, and redox system concentrations and salinity also were varied. It was determined that, for a given polymer-reducing agent system at a specified concentration, the gelation time decreases as temperature is increased. The data were correlated in a manner analogous to the Arrhenius method of correlating chemical reaction rate data. That is, plots of the logarithm of gelation time vs. the reciprocal of the absolute reaction temperature were linear over the temperature range studied. By use of a simple nth-order reaction rate model, the slope of the Arrhenius-type plot was related to activation energy. These activation energies were found to vary only slightly for the polymer systems and concentrations investigated. The results have direct application in the design of gel treatments for injection or production wells. The correlation method provides a way of predicting the effect of temperature on the time required for a given system to gel. It is recognized that in field applications factors beyond the scope of data taken in this paper may affect the gelation process. Introduction The volumetric sweep efficiency of a secondary or enhanced oil-recovery process is a major factor in determining the amount of oil recoverable by that process. In waterflooding, low efficiency results in high WOR's that lead to high operating costs in handling produced water relatively early in a project. When the WOR becomes high enough that the project is no longer economically justified, the process is terminated, and a significant amount of oil may be left unrecovered. In enhanced oilrecovery methods that involve the injection of expensive chemicals, low efficiency is even more costly. Economics may not justify the initiation of such a treatment if the expected efficiency is not sufficiently high. Reservoir heterogeneity is the primary reason for poor sweep efficiency. Particularly common are permeability variations in the vertical direction. The injected fluids tend to flow in the zones of higher permeability, bypassing the oil in the tighter zones if the permeability differences are significant. The resulting low sweep efficiency could be improved if the high permeabilities could be reduced. SPEJ P. 463^

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Study of Enhanced Oil Recovery and Adsorption Using Glycerol in Surfactant Solution

Energies ◽

10.3390/en13123135 ◽

2020 ◽

Vol 13 (12) ◽

pp. 3135

Author(s):

Fabiola D. S. Curbelo ◽

Alfredo Ismael C. Garnica ◽

Danilo F. Q. Leite ◽

Amanda B. Carvalho ◽

Raphael R. Silva ◽

...

Keyword(s):

Interfacial Tension ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Coconut Oil ◽

Surfactant Solution ◽

Recovery Factor ◽

Sweep Efficiency ◽

Brine Solution ◽

Flow Through ◽

Over Time

Over time, oil production in a reservoir tends to decrease, which makes it difficult to flow through the reservoir to the well, making its production increasingly difficult and costly. Due to their physical properties, such as reducing the water/oil interfacial tension, surfactants have been used in enhanced oil recovery (EOR) processes, however, their adsorption presents as an undesirable and inevitable factor and can decrease the efficiency of the method. This work’s main objective is to evaluate the effect of glycerol in the adsorption of surfactants in sandstones, as well as in the recovery factor during EOR. Brine solutions containing the nonionic surfactant saponified coconut oil (SCO), with and without glycerol, were used in the adsorption and oil recovery tests in sandstone. Adsorption, recovery, rheological, and thermogravimetric analysis were carried out. Regarding the surfactant/glycerol/brine solution, there was an improvement in the oil mobility, as the glycerol contributed to an increase in the viscosity of the solution, thereby increasing the sweep efficiency. The recovery factor obtained for the surfactant solution with glycerol was satisfactory, being 53% higher than without glycerol, because it simultaneously provided an increase in viscosity and a decrease in interfacial tension, both of which are beneficial for the efficiency of the process.

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