In steam-assisted gravity drainage (SAGD) operations, the produced fluids are complex water-in-oil-in-water (W/O/W) emulsions. A diluent is often added to reduce the density and viscosity of the heavy crude oil. However, the quality and composition of the diluents may in some cases increase emulsion stability and cause the dehydration of the oil to be more difficult because there are more surface-active agents added to the oil coming from the diluent streams. Thus, this work was aimed at studying the effect of three different diluents on interfacial film formation of a Canadian heavy oil. Interfacial elasticity and compressibility were evaluated, and the results were then correlated with emulsion stability. The wettability of the systems was also studied. The systems studied behaved as if a bidimensional gel near its gelation point had organized at the interface, in which adsorbed amphiphilic materials, such as asphaltenes and resins, self-aggregated at the interface, forming a network that acts as a stabilizing mechanism for produced emulsions. When the interface was aged, its gel strength was much higher than the fresh interface, suggesting an explanation as to why aged emulsions are more difficult to treat. Unlike elasticity and interfacial tension measurements, it was demonstrated that compressibility measurements can predict emulsion stability under different conditions. The higher the crumpling film ratio and the lower the compressibility, the more stable the emulsion. This test method gives more insights into the mechanisms of emulsion stabilization caused by diluents and asphaltenes and can potentially be employed to study the structure and demulsifying performance relationships of emulsion breakers (EBs) and reverse emulsion breakers (REBs).

Selected cationic and amphoteric surfactants were effective in separating oil-in-water emulsions representative of produced emulsions expected during a surfactant/polymer (SP) process for enhanced oil recovery. The aqueous phase of the emulsion contained an anionic surfactant blend, alcohol, and partially hydrolyzed polyacrylamide. Brine composition was a suitable mixture of formation brine with brines from the surfactant slug and polymer drive. The crude oil had an American Petroleum Institute (API) gravity of 31°. Bottle tests were conducted at ambient temperature, which is near the reservoir temperature. Conventional non-ionic demulsifier resins and polymeric cationic flocculants were not effective in removing oil from the aqueous phase. The water content of the oil phase was still well above specification upon heating the emulsions to 50-60 °C. However, both oil and water phases of acceptable quality were obtained after 6 h of settling upon the addition of 200 ppm of octyltrimethylammonium bromide (C 8 TAB) at ambient temperature. Additionally, a commercial cationic surfactant at the same concentration yielded acceptable results for both phases in 2 h. Optical microscopy showed significant coalescence after only 1 min in the C 8 TAB system as the cationic surfactant reduced electrostatic repulsion among drops and shifted system phase behavior toward the balanced state between hydrophilic and lipophilic effects, actions well-known to reduce emulsion stability. Some amphoteric surfactants, such as cocobetaine, were also effective in separating these emulsions. The amount of cationic surfactant required could be reduced by adding it simultaneously with a non-ionic demulsifier resin. A commercial cationic surfactant was also found to significantly improve separation of emulsions produced during an alkaline/surfactant/polymer (ASP) process.

In this study, a design of experiments was used to investigate the importance of several parameters (alkaline concentration, anionic surfactant concentration, polymer concentration, temperature, shear rate, water cut, and salinity) and their interactions (i.e., synergism or antagonism) that govern emulsion stability in chemical enhanced oil recovery (CEOR). Emulsion stability decreased with an increase in salinity or water cut. An increasing surfactant concentration, polymer concentration, temperature, or shear rate enhanced emulsion stability. One of the main contributions for the tight emulsion from alkaline surfactant polymer (ASP) flood was the addition of alkaline. The surfactant, alkaline, and polymer decreased the size of oil droplets, increased the surface charge of oil droplets, and increased the film elasticity, thereby making oil–water separation difficult. Selected cationic surfactants (patents pending) proved much more effective than conventional non-ionic resins and polymeric cationic flocculants in separating oil-in-water emulsions. The chemistry was also investigated by studying the effect of alkyl chain length (C8–C18) of benzyl and methyl quaternary compounds (quats) on demulsifying efficiency. As the surfactant concentration in the brine decreased, the concentration of the cationic demulsifier required to separate the emulsion decreased and the optimum chain length of the cationic demulsifier also changed. The particle video microscope and focused beam reflectance measurement probes showed a significant increase of the size of oil droplets and reduction in the number of oil droplets in the presence of a cationic surfactant. This is in agreement of a decrease of the anionic charge on the surface of the oil droplets and a reduction of the film elasticity in the cationic system. Measurements of interfacial properties, such as the interfacial tension reduction rate, interfacial tension, elastic modulus, and ζ potential, at the oil/brine solution interface were also conducted. A qualitative correlation was found between the interfacial tension reduction rate, elastic modulus, ζ potential, and phase separation. The interfacial tension reduction rate decreased, ζ potential became less negative, elastic modulus decreased, and the size of oil droplets remarkably increased when a cationic demulsifier or an amphoteric demulsifier (patents pending) was added to the emulsion. However, there appears to be no direct correlation with interfacial tension. Without direct information, this preliminary correlation may provide guidelines for selecting demulsifiers for emulsions produced by chemical enhanced oil recovery.

Driven by the need to enhance heavy oil production, we have investigated the emulsification properties of poly(vinyl alcohol)s (PVAs) to generate oil-in-water (O/W) emulsions and achieve a significant viscosity reduction. O/W emulsions were successfully prepared using Canadian heavy oil with an American Petroleum Institute (API) gravity of 12°and a water cut of 25%. The effects of PVA molecular weight and degree of hydrolysis as well as emulsifier concentration and mixing method on emulsion stability and water quality were studied. For this purpose, phase separation kinetics was monitored by means of the Turbiscan Lab Expert particle dispersion analyzer, and the results were then correlated with interfacial tension, wettability, and droplet size measurements. For PVAs having comparable molecular weight, less hydrolyzed samples proved to induce more stable emulsions; this is in agreement with reduced particle size resulting from the increased reduction in interfacial tension. On the other hand, for a similar degree of hydrolysis, the increase of the molecular weight improved emulsion stability. These results, together with the measured droplet sizes and contact angles, indicated that a favorable adsorption of higher molecular weight PVAs at the oil−water interfaces occurs, thereby enhancing steric repulsions between oil droplets. Water quality showed a complex dependency upon the particle size, and the method of mixing was also demonstrated to be critical for emulsion stability. Of the PVAs tested, the PVA with the highest molecular weight (146 kg/mol) and lowest degree of hydrolysis (87%) was found to be the most effective.

Most shale reservoirs (e.g., Bakken Shale and Eagle Ford) have a low permeability, low porosity, and oil-wet character with natural fractures. As a result, the oil recovery factors are very low, only a few percent of original oil in place. Injection of water into oil-wet reservoirs (i.e., water flooding) is not effective due to small or negative capillary pressure. In this study, various surfactants (non-ionic, cationic, anionic, and amphoteric) were studied for spontaneous imbibition into oil-wet shale cores. Surfactant imbibition into Eagle Ford shale outcrop cores and Bakken reservoir cores increased oil recovery compared to brine only. Oil recovery can be seen for surfactants that alter the reservoir from oil-wet to water-wet. For example, the incremental oil recovery was about 24% % for 0.1% cationic surfactant and 57% for 0.1% nonionic surfactant. The goal of this work is to investigate the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and provide mechanisms. Contact angles and interfacial tensions (IFT) were measured and correlated with spontaneous imbibition. Wettability alteration from oil-wet to water-wet (i.e., low contact angle) appeared to be more important than a low interfacial tension in increasing the oil recovery rate from fractured oil-wet reservoirs, especially for nonionic surfactants and amphoteric surfactants. Wettability alteration is maximum and IFT is minimum for anionic and cationic surfactants at an optimal salinity. However, as the reservoir salinity increases, the maximum wettability alteration decreases and IFT increases.