Preparation and Performance Evaluation of Fatty Amine Polyoxyethylene Ether Diethyl Disulfonate for Enhanced Oil Recovery in High‐Temperature and High‐Salinity Reservoirs

To enhance oil recovery in high‐temperature and high‐salinity reservoirs, a novel fatty amine polyoxyethylene ether diethyl disulfonate (FPDD) surfactant with excellent interfacial properties was synthesized. The interfacial tension (IFT) and contact angle at high temperature and high salinity were systematically investigated using an interface tension meter and a contact angle meter. According to the experimental results, the IFT between crude oil and high‐salinity brine water could reach an ultra‐low value of 10^?3 mN m^?1 without the aid of extra alkali at 90°C after aging. The FPDD surfactant has strong wettability alternation ability that shifts wettability from oil‐wet to water‐wet. The FPDD surfactant with a high concentration also has good emulsion ability under high‐temperature and high‐salinity conditions. Through this research work, we expect to fill the lack of surfactants for high‐temperature and high‐salinity reservoirs and broaden its great potential application area in enhanced oil recovery.     

Enhanced oil recovery from high‐salinity reservoirs by cationic gemini surfactants

In order to enhance oil recovery from high‐salinity reservoirs, a series of cationic gemini surfactants with different hydrophobic tails were synthesized. The surfactants were characterized by elemental analysis, infrared spectroscopy, mass spectrometry, and ¹H‐NMR. According to the requirements of surfactants used in enhanced oil recovery technology, physicochemical properties including surface tension, critical micelle concentration (CMC), contact angle, oil/water interfacial tension, and compatibility with formation water were fully studied. All cationic gemini surfactants have significant impact on the wettability of the oil‐wet surface, and the contact angle decreased remarkably from 98° to 33° after adding the gemini surfactant BA‐14. Under the condition of solution salinity of 65,430 mg/L, the cationic gemini surfactant BA‐14 reduces the interfacial tension to 10^?3 mN/m. Other related tests, including salt tolerance, adsorption, and flooding experiments, have been done. The concentration of 0.1% BA‐14 remains transparent with 120 g/L salinity at 50 °C. The adsorption capacity of BA‐14 is 6.3–11.5 mg/g. The gemini surfactant BA‐14 can improve the oil displacement efficiency by 11.09%. © 2017 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018 , 135, 46086.     

Review on application of nanoparticles for EOR purposes: A critical review of the opportunities and challenges

Nanoparticles have already gained attentions for their countless potential applications in enhanced oil recovery.Nano-sized particles would help to recover trapped oil by several mechanisms including interfacial tension reduction, impulsive emulsion formation and wettability alteration of porous media. The presence of dispersed nanoparticles in injected fluids would enhance the recovery process through their movement towards oil–water interface. This would cause the interfacial tension to be reduced. In this research, the effects of different types of nanoparticles and different nanoparticle concentrations on EOR processes were investigated. Different flooding experiments were investigated to reveal enhancing oil recovery mechanisms. The results showed that nanoparticles have the ability to reduce the IFT as well as contact angle, making the solid surface to more water wet. As nanoparticle concentration increases more trapped oil was produced mainly due to wettability alteration to water wet and IFT reduction. However, pore blockage was also observed due to adsorption of nanoparticles, a phenomenon which caused the injection pressure to increase. Nonetheless, such higher injection pressure could displace some trapped oil in the small pore channels out of the model. The investigated results gave a clear indication that the EOR potential of nanoparticle fluid is significant.     

Investigation of Interfacial Tension Reduction,Wettability Alteration,and Oil Recovery Using a New Non-ionic Oil-Based Surfactant from Gemini Surfactants Family Coupled with Low-Salinity Water: Experimental Study on Oil-Wet Carbonate Rock

Low-salinity surfactant (LSS) flooding is a combined enhanced oil recovery (EOR) technique that increases oil recovery (OR) by altering the rock surface wettability and reducing oil–water interfacial tension (IFT). In this study, optimum concentrations of several types of salt in distilled water were obtained on the basis of IFT experiments for the preparation of low-salinity water (LSW). Then, a new oil-based natural surfactant (Gemini surfactant, GS) was combined with LSW to investigate their effects on IFT, wettability, and OR. Experimental results showed that LSW is capable of reducing IFT and contact angle, but the synergy of GS and the active ions Mg²⁺, Ca²⁺, and SO₄²⁻ in LSW was more effective on IFT reduction and wettability alteration. The combination of 1000 ppm MgSO₄ and 3000 ppm GS led to a decrease in contact angle from 134.82° to 36.98° (oil-wet to water-wet). Based on core flooding tests, LSW injection can increase OR up to 71.46% (for LSW with 1000 ppm MgSO₄), while the combination of GS and LSW, as LSS flooding, can improve OR up to 84.23% (for LSS with 1000 ppm MgSO₄ and 3000 ppm GS). Therefore GS has great potential to be used as a surfactant for EOR.     

Novel fluorinated surfactants for enhanced oil recovery in carbonate reservoirs

Novel surfactant‐polymer (SP) formulations containing fluorinated amphoteric surfactant (surfactant‐A) and fluorinated anionic surfactant (surfactant‐B) with partially hydrolyzed polyacrylamide (HPAM) were evaluated for enhanced oil recovery applications in carbonate reservoirs. Thermal stability, rheological properties, interfacial tension, and adsorption on the mineral surface were measured. The effects of the surfactant type, surfactant concentration, temperature, and salinity on the rheological properties of the SP systems were examined. Both surfactants were found to be thermally stable at a high temperature (90 °C). Surfactant‐B decreased the viscosity and the storage modulus of the HPAM. Surfactant‐A had no influence on the rheological properties of the HPAM. Surfactant‐A showed complete solubility and thermal stability in seawater at 90 °C. Only surfactant‐A was used in adsorption, interfacial tension, and core flooding experiments, since surfactant‐B was not completely soluble in seawater and therefore was limited to deionized water. A decrease in oil/water interfacial tension (IFT) of almost one order of magnitude was observed when adding surfactant‐A. However, betaine‐based co‐surfactant reduced the IFT to 10^?3 mN/m. An adsorption isotherm showed that the maximum adsorption of surfactant‐A was 1 mg per g of rock. Core flooding experiments showed 42 % additional oil recovery using 2.5 g/L (2500 ppm) HPAM and 0.001 g/g (0.1 mass%) amphoteric surfactant at 90 °C.     

Superior enhancement of imbibition recovery by novel surfactant mixtures with a large hydrophobic group combined with nanosilica

Low interfacial tension (IFT) drainage and imbibition are effective methods for improving oil recovery from reservoirs that have low levels of oil or are tight (i.e., exhibit low oil permeability). It is critical to prepare a high efficient imbibition formula. In this work, a novel 2,4,6-tris(1-phenylethyl)phenoxy polyoxyethylene ether hydroxypropyl sodium sulfonate (TPHS) surfactant was synthesized and evaluated for imbibition. Its structure was confirmed by Fourier transform infrared spectroscopy and the interfacial tension (IFT) of the crude oil/0.07% TPHS solution was 0.276 mN/m. When 0.1 wt% TPHS was mixed with 0.2 wt% alpha olefin sulfonate (AOS), the IFT was lowered to 6 × 10⁻² mN/m. The synergy between nanoparticles (NPs) and TPHS/AOS mixed surfactant was studied by IFT, contact angle on sandstone substrates, zeta potential, and spreading dynamics through microscopic methods. The results show that the surfactant likely adsorbs to the NP surface and that NP addition can help the surfactant desorb crude oil from the glass surface. With the addition of 0.05 wt% SiO₂ NPs (SNPs), the imbibition oil recovery rate increased dramatically from 0.32%/h to 0.87%/h. The spontaneous imbibition recovery increased by 4.47% for original oil in place (OOIP). Compared to flooding by TPHS/AOS surfactant solutions, the oil recovery of forced imbibition in the sand-pack increased by 12.7% OOIP, and the water breakthrough time was delayed by 0.13 pore volumes (PV) when 0.05% SNPs were added. This paper paves the way for enhanced oil recovery in low-permeability sandstone reservoirs using novel TPHS/AOS surfactants and SNPs.     

Synthesis of an Alkyl Polyoxyethylene Ether Sulfonate Surfactant and Its Application in Surfactant Flooding

Surfactant flooding as a potential enhanced oil‐recovery technology in a high‐temperature and high‐salinity oil reservoir after water flooding has attracted extensive attention. In this study, the synthesis of an alkyl alcohol polyoxyethylene ether sulfonate surfactant (C₁₂EO₇S) with dodecyl alcohol polyoxyethylene ether and sodium 2‐chloroethanesulfonate monohydrate, and its adaptability in surfactant flooding were investigated. The fundamental parameters of C₁₂EO₇S were obtained via surface tension measurement. And the ability to reduce oil–water interfacial tension (IFT), wettability alteration, emulsification, and adsorption was determined. The results illustrated that IFT could be reduced to 10^?3 mN m^?1 at high temperature and high salinity without additional additives, and C₁₂EO₇S exhibited benign wettability alternate ability, and emulsifying ability. Furthermore, the oil‐displacement experiments showed that C₁₂EO₇S solution could remarkably enhance oil recovery by 16.19% without adding any additives.     

A Zwitterionic Surfactant Bearing Unsaturated Tail for Enhanced Oil Recovery in High‐Temperature High‐Salinity Reservoirs

High‐temperature/high‐salinity (HTHS) reservoirs contain a significant fraction of the world's remaining oil in place and are potential candidates for enhanced oil recovery (EOR). Selection of suitable surfactants for such reservoirs is a challenging task. In this work, two synthesized zwitterionic surfactants bearing a saturated and an unsaturated tail, namely 3‐(N‐stearamidopropyl‐N,N‐dimethyl ammonium) propanesulfonate and 3‐(N‐oleamidopropyl‐N,N‐dimethyl ammonium) propanesulfonate, respectively, were evaluated. The surfactant with the unsaturated tail showed excellent solubility in synthetic seawater (57,643 ppm) and in formation brine (213,734 ppm). However, the unsaturated surfactant with a saturated tail showed poor solubility, and therefore it was not evaluated further. The thermal stability of the synthesized unsaturated surfactant solution in seawater was evaluated by heating the solution at 90 °C in a sealed aging tube for 2 weeks. The thermal stability of the unsaturated surfactant was confirmed by FTIR and NMR analysis of the aged samples at such harsh conditions. The critical micelle concentration (CMC) of the synthesized unsaturated surfactant in seawater was 1.02 × 10^?4 mol L^?1, while the surface tension at CMC was 30 mN m^?1. The synthesized unsaturated surfactant was able to reduce the oil–water interfacial tension to ~10^?1 mN m^?1 at different conditions. A commercial copolymer of acrylamide and 2‐acrylamido‐2‐methylpropane sulfonic acid (AM‐AMPS) was tested for EOR applications in HTHS conditions. The addition of the synthesized unsaturated surfactant to the AM‐AMPS copolymer increased the viscosity of the system. The increase in oil recovery by injecting the unsaturated surfactant solution and the surfactant–polymer mixture in solution was 8 and 21%, respectively. The excellent properties of the synthesized unsaturated surfactant show that surfactants with an unsaturated tail can be an excellent choice for HTHS reservoirs.     

The effect of mixed surfactants on enhancing oil recovery

Micelles composed of mixed surfactants with different structures (mixed micelles) are of great theoretical and industrial interest. This work pertains tomaximizing interfacial tension (IFT) reduction via surfactant pairs. In this respect, four types of fatty acid amides based on lauric, myristic, palmitic, and stearic acids were blended with dodecyl benzene sulfonic acid at a molar ratio of 4∶1 and designated as A₁, A₂, A₃, and A₄, respectively. The IFT was measured for each blend at different concentrations using Badri crude oil. The most potent formula (A₄) was evaluated for using in enhanced oil recovery (EOR). The IFT was tested in the presence of different electrolyte concentrations with different crude oils at different temperatures. Finally several runs were devoted to study the displacement of Badri crude oil by A₄ surfactant solution using different slug sizes of 10, 20, and 40% of pore volume (PV). The study reveled that Badri crude oil gave ultra-low IFT at lowest surfactant concentration and 0.5% of NaCl. The recovery factor at a slug size of 20% PV was 83% of original oil in place compared with 59% in case of conventional water flood.     

Surfactant Enhanced Oil Recovery in a High Temperature and High Salinity Carbonate Reservoir

The goal of this work was to find an effective surfactant system for enhanced oil recovery after water injection substituting for oil at a vuggy fractured reservoir with a high temperature and high salinity (220,000 mg/L). Four types of surfactants with concentrations (less than 0.2 %) were screened. Washing oil experiments were conducted in Amott cells. A surfactant system was established by mixing a surfactant with best ultimate recovery and one with best recovery rate. The optimized surfactant system could recover 50 % of remaining oil. To study the mechanism of enhanced oil recovery after water injection substituting oil, interfacial tension (IFT) and contact angle were measured. Experimental results showed that surfactants with good washing ability had low IFT, but surfactants with low IFT may not have a good washing ability. IFT had no obvious relationship with the increased oil recovery or washing ability. The optimized system could not alter carbonate to decrease the oil‐wetting capability. Though octadecyl trimethyl ammonium chloride had a good ability wet the carbonate with water, it could not recover much oil. Therefore, except for interfacial tension and wettability alteration, there must be other parameters dominating oil recovery after water injection substituting for oil.     

A Star-Shaped Anionic Surfactant: Synthesis,Alkalinity Resistance,Interfacial Tension and Emulsification Properties at the Crude Oil–Water Interface

In this research, a star‐shaped surfactant was synthesized through the chlorination reaction, alkylation reaction and sulfonation reaction of triethanolamine, which is composed of three hydrophobic chains and three sulfonate hydrophilic groups. The critical micelle concentration (CMC) of the surfactant was measured by the surface tension method, and the results showed that it had high surface activity with CMC of 5.53 × 10^?5 mol/L. The surfactant was superior in surface active properties to the reference surfactants SDBS and DADS‐C₁₂. The interfacial tension (IFT) of the studied crude oil–water system (surfactant concentration 0.1 g/L, NaOH concentration 0.5 g/L, and experimental temperature 50 °C) dropped to 1.1 × 10^?4 mN/m, which can fulfil the requirement of surfactants for oil displacement. An aqueous solution of the surfactant and crude oil was emulsified by shaking, which formed a highly stable oil‐in‐water (O/W) emulsion with particle size of 5–20 μm. The oil displacement effect was almost 12%.     

表面活性剂驱油效率的影响因素研究

在83℃下测定了3种表面活性剂DL-S、HL-Y/NNR、GZ-16的油水界面张力、乳化能力以及改变油藏岩石润湿性的能力。利用低渗透岩心驱油实验研究表面活性剂的这3种特性对驱油效率的影响。结果表明,表面活性剂的浓度在1 000 mg/L时,DL-S的油水界面张力达到10-3mN/m超低数量级,HL-Y/NNR表现出较为优越的乳化性能,GZ-16具有较好的润湿性能。在驱油实验中,具有最好乳化性能的HL-Y/NNR提高采收率的幅度最大为12.91%,其次为具有超低界面张力的DL-S,相较而言,改变润湿性的能力对驱油效率的影响最小。     

驱油用表面活性剂AF性能评价及驱油效果研究

评价了脂肪酸烷醇酰胺表面活性剂AF的界面张力和乳化性能,利用岩心驱替实验对其提高采收率效果进行了研究。结果表明,在模拟地层水的矿化度为5 119.63 mg/L时,AF浓度为0.2%～1.2%,其界面张力均能达到超低值;NaCl浓度为0.4%～2%,AF有效浓度为0.3%～0.6%时,体系的界面张力均能达到10-3mN/m数量级。AF具有较好的乳化原油的能力,在浓度为0.5%时,形成的O/W乳状液的稳定性最强,液滴粒径最小。岩心驱替实验表明,AF表面活性剂可在水驱基础上提高原油采收率20%以上,提高采收率效果明显,具有良好的应用前景。     

Surfactant-assisted aqueous extraction of palm-pressed mesocarp fiber residual oil with Tween 80 solution

The potential of Tween 80, a commercial food-grade non-ionic surfactant, was evaluated for the extraction of residual oil from palm-pressed mesocarp fibre (PPMF). Results show that the critical micelle concentration (CMC) was achieved at 0.05 wt% surfactant with an interfacial tension (IFT) of 0.51 mN/m. The extraction yield however depends not only on the IFT but also on the viscosity and the solid to liquid ratio of the extracting solution. The highest percentage of oil extraction (47.36%) was obtained at 1 wt% Tween 80 with 6% NaCl, temperature of 60°C and a solid–liquid ratio of 8 g PPMF: 200 g solution.     

Optimization of Dynamic Interfacial Tension for Crude Oil–Brine System in the Presence of Nonionic Surfactants

In this study, interfacial tension (IFT) is measured between brine and crude oil (a sample of heavy oil from an Iranian oil reservoir) in the presence of two nonionic surfactants, KEPS 80 (Tween 80) and Behamid D, at different concentrations in order to optimize the concentrations of the surfactants. The surface response method is used to design the IFT measurement experiments. The experimental design and optimization is performed using the IFT as an objective function and temperature, concentration, and time as independent variables. In addition to the IFT measurement, various experiments such as stability tests of the surfactants in NaCl brine solutions, adsorption experiments on the carbonated rock surface, and phase behavior tests are performed to investigate the behavior of KEPS 80 and Behamid D in the enhanced oil recovery process. At the end, a model using the response surface statistical technique is designed for optimization of the concentrations of the surfactants, and a surfactant molecular migration mechanism is used for explanation of the dynamic IFT variation versus time. In the case of IFT experiments, the effect of surfactant concentration (at 1000, 3000, and 5000 ppm) on the dynamic IFT is investigated. The experiments are performed at four temperatures (25, 40, 50, and 67°C). The results show that the oil–brine IFT values can be reduced to about 4 mN m⁻¹ in the presence of Behamid D and to about 1 mN m⁻¹ in the presence of KEPS 80 at low concentrations.     

Acidic Heavy Oil Recovery Using a New Formulated Surfactant Accompanying Alkali–Polymer in High Salinity Brines

The strength of a newly formulated surfactant with an alkali and polymer (AS/ASP) to improve an acidic heavy oil recovery was laboratory evaluated by various flooding experiments. The comparative role of the parameters like chemical nature, surface wettability, salinity, temperature and injection scheme were explored at high temperature and pressure on Berea sandstone rocks. According to the results the anionic surfactant is capable of providing proper oil displacement under high salinity conditions around 15 wt%. Continuous monitoring of differential pressure response and effluents’ state clearly represented the formation of an emulsified oil in high saline solutions with both alkali and surfactant. Adding sodium metaborate to the surfactant solution reduced the interfacial tension (IFT) to ultra low values and decreased the surfactant emulsion generation capability at higher salinities. Besides, adding Flopaam AN113SH to the chemical slug increased the residual oil removal owing to lower mobility ratios. So, while high capillary number and an emulsion phase were generated by the A/S slug phases, adding polymer could further enhance the performance of these chemicals. On the other hand, chemical flooding through the oil-wet medium resulted in shorter break through time, lower differential pressure, finer emulsion formation, and lower oil recovery in comparison to the similar water-wet cases.     

From Phase Behavior to Understand the Dominant Mechanism of Alkali-Surfactant-Polymer Flooding in Enhancing Heavy Oil Recovery

The primary objective of this work was to understand the dominant mechanism(s) of alkali‐surfactant‐polymer (ASP) flooding in enhancing heavy oil recovery. Chemical formulations were first optimized based on phase behavior studies. The data indicated that alkali and surfactant created a synergistic effect at the oil/water interface, which further decreased the interfacial tension (IFT) and improved the emulsification. However, it was also found that the addition of alkali was detrimental to the viscous properties of the chemical systems and caused the ultimate oil recovery to decrease. In other words, the macroscopic sweep efficiency as a result of viscosity was the primary factor determining the overall recovery of heavy oil followed by emulsification, which was verified by the phase behavior of the effluent. Based on the experimental results, we found that for this targeted heavy oil reservoir, surfactant‐polymer (SP) flooding was more appropriate than ASP flooding and it was not necessary to decrease the IFT to the ultralow level (10^?3 mN/m) using alkali. Through chemical flooding, the incremental oil recovery was increased up to 27% of original oil in place, indicating the potential of this technique in heavy oil reservoirs.     

Laboratory Studies to Determine Suitable Chemicals to Improve Oil Recovery from Garzan Oil Field

Garzan oil field is located at the south east of Turkey. It is a mature oil field and the reservoir is fractured carbonate reservoir. After producing about 1% original oil in place (OOIP) reservoir pressure started to decline. Waterflooding was started in order to support reservoir pressure and also to enhance oil production in 1960. Waterflooding improved the oil recovery but after years of flooding water breakthrough at the production wells was observed. This increased the water/oil ratio at the production wells. In order to enhance oil recovery again different techniques were investigated. Chemical enhanced oil recovery (EOR) methods are gaining attention all over the world for oil recovery. Surfactant injection is an effective way for interfacial tension (IFT) reduction and wettability reversal. In this study, 31 different types of chemicals were studied to specify the effects on oil production. This paper presents solubility of surfactants in brine, IFT and contact angle measurements, imbibition tests, and lastly core flooding experiments. Most of the chemicals were incompatible with Garzan formation water, which has high divalent ion concentration. In this case, the usage of 2-propanol as co-surfactant yielded successful results for stability of the selected chemical solutions. The results of the wettability test indicated that both tested cationic and anionic surfactants altered the wettability of the carbonate rock from oil-wet to intermediate-wet. The maximum oil recovery by imbibition test was reached when core was exposed 1-ethly ionic liquid after imbibition in formation water. Also, after core flooding test, it is concluded that considerable amount of oil can be recovered from Garzan reservoir by waterflooding alone if adverse effects of natural fractures could be eliminated.     

Ionic liquids as novel surfactants for potential use in enhanced oil recovery

The screening and use of benign chemicals for enhanced oil recovery (EOR) applications is important because of their properties and relationship to the embedded fluids. We investigated a special type of ionic liquids (ILs) called “Ammoeng” for potential use in surfactant EOR to replace the currently used surfactants that have many disadvantages. The interfacial tension (IFT) between a representative oil sample from Saudi reservoirs and solutions of Ammoeng? ILs at different concentrations in 10 wt% NaCl aqueous solutions were measured as a function of temperature. It was found that the IFT values decreased with the increase of IL concentration. However, the effect of temperature on the IFT depended on the type of IL. Ammoeng? 102 gave the lowest IFT values among the screened ILs. The comparison of the results to those resulting from TritonX100, a commercially used surfactant, showed that the IFT values using Ammoeng? 102 were smaller than the corresponding values when TritonX100 was used at the same conditions. The possibility of having a synergetic effect when using a mixture of Ammoeng? 102 and Triton X 100 was also investigated. The results showed that the IFT values depended on the total concentration, the surfactant to IL mass ratio, and the temperature.     

新型弱碱表面活性剂在三次采油中的应用

以α-烯烃为初始原料，经过烷基化，再经磺化、中和研制出了组分相对单一、结构合理的新型弱碱烷基苯磺酸盐表面活性剂。室内评价结果表明，该表面活性剂具有良好的界面活性，配制的复合体系在较宽的表面活性剂浓度和碱浓度范围可与原油形成10^-3mN／m数量级的超低界面张力。同时，该表面活性剂对大庆油田不同区块、不同油层的油水条件表现出了很强的适应性。另外，由于表面活性剂组成较为单一，可大大降低表面活性剂在地层中因吸附滞留而产生的色谱分离效应。室内天然岩心驱油实验表明，三元复合体系平均驱油效率可比水驱提高约20％。所开展的小井距三元复合驱矿场试验，取得了比水驱提高采收率24．66％的显著效果，为三元复合驱技术在大庆油田的工业化推广，特别是在二类油层的应用奠定了坚实基础。