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Alkali plays an important role in alkali/surfactant/polymer (ASP) technology. The mechanisms of alkali were reviewed in this paper and the advantages were significant. In this study, three main steps were conducted. Firstly, ethanolamine was selected from four organic alkalies (ethanolamine, diethanolamine, triethanolamine and triethylamine) by interfacial tension (IFT) tests. Then the selected organic alkali, ethanolamine, was compared with inorganic alkali (sodium carbonate) by IFT performance. The results showed that ethanolamine had low IFT like inorganic alkali and it has lower IFT than sodium carbonate when concentration was higher than 0.8%. Secondly, alkali consumption experiment was conducted to compare organic alkali and inorganic alkali. The results indicated that ethanolamine had lower consumption than inorganic alkali, which maintained the efficiency of ASP flooding. Finally, the concentrations of silicon and aluminum in solution were measured to evaluate the reservoir damage caused by alkali. The results found that ethanolamine system had the lower concentrations of silicon and aluminum than inorganic alkali, which means it caused less reservoir damage. Thus, ethanolamine may be a potential alkali which can replace inorganic alkali in ASP technology. [ABSTRACT FROM AUTHOR]

Alkaline-Surfactant-Polymer (ASP) flooding is an emerging chemical Enhanced Oil Recovery (EOR) technology which has significantly enhanced oil recovery of Daqing Oilfield. ASP flooding benefits from the synergy effects of alkali, surfactant and polymer to improve both volumetric and displacement efficiencies and meanwhile lower surfactant adsorption. However, ASP flooding also induces some negative formation damage effects such as scaling, adsorption, and mineral dissolution. In this paper, we investigated the formation damage caused during ASP flooding in Block Sanan-5 in Songliao Basin – one of the most productive blocks of Daqing Oilfield in China. It was found that the distribution of formation damage caused by ASP flooding followed flow paths of chemical solutions and was dependent on well locations. The severity of damage varies as distance increases from the near-injection-well area to the near-production-well area. Understanding the effects of well locations on formation damage during ASP flooding could provide more accurate evaluation of formation damage and helped to guide reservoir development strategies. To analyze the well location factor, we collected scaling samples and more than 970 m of core samples from Block Sanan-5 of Daqing Oilfield covering different wells on various flow paths before and after ASP flooding. The changes of some key petrophysical parameters such as porosity and permeability before and after ASP flooding were investigated. A series of experiments, including Scanning Electron Microscopy (SEM), Casting Thin Sections (CTS), X-Ray Diffraction (XRD) and ion analysis of produced water were performed to test properties of core samples. In addition, absorption of different components in the ASP solutions was also measured. Experimental results indicate that the ASP flooding has considerably different influences on different parts of flow paths. After ASP flooding, permeability distribution of core samples exhibits different variability trends from the near-injection-well areas to near-production-well areas. Due to absorption of alkali and polymer, grains migration and scaling of calcium and magnesium, permeability decreases at the near-injection-well area, then increases at an intermediate distance and decreases again at the near-production-well. Moreover, porosity of samples shows a similar tendency with variability of permeability, which is interpreted by the strong mineral corrosion due to high concentration of alkali in the near-wellbore area, while its extent of variation is smaller than permeability. [ABSTRACT FROM AUTHOR]

The objective of this paper is to investigate an oil-tolerant foam system as a displacing agent to improve the efficiency of oil recovery. To achieve this objective, several foaming agents are examined based on foam–oil interaction models and previous studies. By measuring the interfacial and surface tensions of surfactants, we investigate the implications of the value of spreading coefficient and the lamella number in a system of foaming agents. The foamability and foam stability of the preferred foaming agents were statically tested. At last, the oil tolerance of the foaming agent system in both static and core flow experiments was investigated. Results indicated that the oil tolerant foaming system performs best among the various surfactants tested. In static testing, both foamability and foam stability increase as concentrations of surfactant and salt increase. It was also observed that the polymer significantly increases the foam stability in the presence of oil. The oil droplets do not spread at the surface due to the properties of the oil-tolerant foam, so the foam can be stable in the presence of crude oil. The oil tolerant foaming system exhibits much greater foaming volume and longer drainage-half time than ordinary foam, either in the presence or absence of oil. The mobility reduction factor for dynamic displacement of oil-tolerant foam is much higher than those of pure foam and polymer solutions in the presence of oil. Experiments with different remaining oil saturations reveal that when the residual oil saturation is about 40%, the oil-tolerant foam can achieve the highest oil recovery. [ABSTRACT FROM AUTHOR]

The technical feasibility of using organic alkali instead of an inorganic one during alkaline/surfactant/polymer (ASP) flooding in a heterogeneous reservoir under a high temperature of 95 °C in China was investigated. Laboratory experiments were performed to evaluate the alkali consumption, adsorption, and retention in formation and its formation damage. Also viscosity of the ASP compound flooding system, oil/water interfacial tension, and chromatographic separation were investigated. A comparison of results obtained through organic alkali with those obtained from inorganic alkali was conducted to evaluate the flooding effect of this system, and the mechanism of increasing recovery ratio was analyzed. Experimental results indicated that the consumption and dynamic adsorption of ethanolamine and formation damage observed through the organic alkali were significantly lower than those observed through the inorganic alkali. When compounded with the surfactant, ethanolamine could further decrease the oil/water interfacial tension. Moreover, ethanolamine exerted a protective effect on the surfactant, thereby decreasing adsorption loss. A flooding experiment with a 5-spot pattern was performed on a heterogeneous reservoir. Findings revealed that the organic ASP (OASP) compound flooding system achieves good displacement effects and mobility control even under high temperature conditions and significantly improved recovery ratios. As such, the proposed method is feasible for compound flooding in high-temperature reservoirs. The mechanism of OASP compound flooding was discussed to provide a theoretical basis for optimizing compound flooding systems for high-temperature heterogeneous reservoirs. [ABSTRACT FROM AUTHOR]

• A pH-responsive emulsifier composed of SDS and EAB was proposed. • The interaction strength between SDS and EAB could be adjusted by regulation of pH. • The emulsions stabilized by SDS and EAB could demulsify once 0.1M HCl was added. In order to improve the recovery of crude oil and realize rapid demulsification of produced fluid, a pH-responsive zwitterionic/anionic surfactant system was proposed. The pH-responsive zwitterionic/anionic surfactant system consists of zwitterionic surfactant EAB (erucic amide carboxylic betaine) and anionic surfactant SDS (sodium dodecyl sulfate). By adjusting the pH value, the protonation degree of EAB could be controlled. Accordingly, the interaction between surfactants in the mixed system could be strengthened or weakened in neutral environment (pH = 6–8) or acidic conditions (pH = 2–4), respectively. In consequence, transformation between the emulsification and demulsification states for the emulsions stabilized by zwitterionic/anionic surfactant system could be effectively controlled by variation of the pH values. Meanwhile, the interfacial tension, average droplet size, microstructure and stability analysis of the mixed system emulsifying at various pH values were studied. For the emulsion stabilized by the pH-responsive zwitterionic/anionic surfactant system, the droplets size was evenly distributed and the average particle size was the lowest when the molar ratio of EAB to SDS was 4:6, whilst the average particle size increased significantly once the pH value was reduced down to 2 or 3. Above all, this study provides a new approach for the development of chemical flooding agents for enhancing oil recovery. [ABSTRACT FROM AUTHOR]

Abstract: The emulsification and entrainment of crude oil into displacing water is one of the mechanisms of alkaline flooding for conventional oil. If this mechanism is applied in heavy oil reservoirs, the flow of viscous oils and subsequently the oil recovery can be greatly improved. The formation brine of heavy oil reservoirs usually has a high salinity and high content of multiple cations that make the in situ emulsification of heavy oil a challenge. In this work, a heavy oil of 14° API is used to study the mechanism of emulsification of heavy oils in brine under slight interfacial disturbance. Emulsification tests and interfacial measurements are carried out to screen alkalis and surfactant additives for emulsifying the oil in the diluted formation brine. The results show that if only alkali or only surfactant is added into the brine, emulsification of the oil in brine cannot be triggered. When alkali (Na2CO3) and very dilute surfactant are used together, the oil can be easily emulsified. The synergy of alkali and surfactant in emulsifying the heavy oil in brine is investigated by measuring the dynamic interfacial tension (IFT) and zeta-potential of emulsions. It is found that the interaction of added surfactant and in situ surfactant from the reaction of alkali and organic acids in oil can significantly reduce the dynamic interfacial tension between oil and water and increase the surface charge density of emulsions. The synergistic enhancement between alkali and surfactant is the key mechanism of emulsifying heavy oils in brine under slight interfacial disturbance. [Copyright &y& Elsevier]

Surfactants, which possess ability to alter rock surface wettability and reduce interfacial tension (IFT), are effective additives for imbibition enhanced oil recovery (IEOR) in low sandstone permeability reservoirs. However, the imbibition efficiencies vary from different surfactants, and some surfactants even have a negative effect on IEOR. Thus, it is necessary to research optimum surfactants suitable for IEOR. Considering that the surfactant properties are closely related to its molecular structure, this study systematically investigated the static imbibition efficiencies of different surfactants based on molecular structures, which contain different surfactant types, ionic head groups, hydrophilicity, and carbon chain lengths. In addition, the imbibition performance of surfactant solutions with different IFTs were also researched. The imbibition tests were conducted with Amott cells at 80 °C, using Changqing low permeability outcrop sandstones. Subsequently, IFT tests, viscosity measurements, contact angle (CA) measurements, and zeta potential tests were conducted to explore the IEOR mechanisms of different surfactant solutions. The experimental results showed that the IEOR potential of different types of surfactants was: anionic > nonionic > brine > amphoteric > cationic. Sulfate anionic surfactants showed better ability of wettability alteration than sulfonate surfactants, and achieved the most imbibition efficiency. Increasing the hydrophilicity of surfactants by introducing the ethylene oxide (EO) groups to the surfactant structures was effective in enhancing wettability alteration ability of surfactants and improving imbibition recovery. Surfactants with longer carbon chain (C 16 surfactants) enhanced more imbibition recovery than short carbon chain surfactants (C 12 surfactants), which was mainly depending on better IFT reduction ability of C 16 surfactants than C 12 surfactants. Appropriate IFT reduction, such as 10−1 mN/m levels, which reduced the adhesion work, enhanced the gravity dominated imbibition and avoided too much capillary pressure reduction, was the most desirable for IEOR. Too low IFTs, such as less than 10−2 mN/m, were not suitable for IEOR, because the capillary pressure reduced greatly, resulting in the imbibition process mainly dominated by gravity. This study provides fundamental information about the selection and design of surfactants for IEOR in low sandstone permeability reservoirs. • The spontaneous imbibition efficiencies of different surfactant solutions based on molecular structures were investigated systematically. • The reasons for the imbibition efficiency differences of different solutions were investigated in detail. • The optimum surfactant types and IFTs suitable for imbibition were obtained. [ABSTRACT FROM AUTHOR]

Alkyl polyglucoside, an eco-friendly, stable and low-cost available biobased surfactant, was chemically modified to develop ultra-low interfacial tension (IFT) surfactants for crude oil recovery from low permeability reservoirs. The modified anionic surfactant alkyl polyglucoside sodium hydroxypropyl sulfonate (APGSHS) was structurally characterized by FT-IR, 1H NMR and TGA methods. Following that, the cationic surfactant cetyl trimethyl ammonium bromide (CTAB) was combined with APGSHS to formulate the ultra-low oil/water IFT catanionic surfactants, which exhibits higher water-solubility than DTAB/APGSHS mixtures at various concentrations and combined ratios. Furthermore, the surface properties, thermodynamic parameters of the sole and combined surfactants show that the combined APGSHS/CTAB catanionic surfactants have lower surface tension (22.90 mN/m) at cmc , smaller area occupied per molecule and stronger micellization capacity, which indicates that the surfactant molecules are tightly absorbed onto the two-phase interface for catanionic surfactants. The mechanism underlying the strong electrostatic attraction between the ion head groups in APGSHS and CTAB could be proven by the high absolute value of interaction parameters (12.23) in binary systems. Besides, the salinity resistance effect tests indicate that the ultra-low IFT formula exhibits excellent performance in both monovalent and divalent ions conditions. Notably, the APGSHS/CTAB surfactants with total concentration of 3000 mg/L and molar ratio of 6:4 can effectively enhance oil recovery and decrease the injected pressure for low permeability reservoirs. Hence, the newly formulated green catanionic surfactants exhibit remarkable abilities for maintaining the ultra-low IFTs and can be used for EOR in low permeability and high salinity reservoirs. Unlabelled Image • A biobased surfactant alkyl polyglucoside is chemically modified for crude oil recovery from low permeability reservoirs. • Ultra-low interfacial tension (IFT) catanionic surfactants were formulated. • The ultra-low IFT formula exhibits excellent tolerance capacities against both monovalent and divalent ions. [ABSTRACT FROM AUTHOR]