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The critical micelle concentration (CMC) of surfactants represent the concentration at which surfactant monomers start to form aggregates in order to minimize the energy of the electrostatic and hydrophobic interactions of the system. At this concentration, any additional surfactant molecules are not available at the interface but in aggregates in the bulk of the solution. A measure of CMC for a field surfactant gives an indication of the concentration needed for its effectiveness as an enhanced oil recovery (EOR) agent. This has been shown to be dependent on several factors including the nature of the brine, temperature, and ionic species strength. As such, for field applications, CMCs need to be measured for the particular environment that the surfactant will be used in. In this work we have measured the CMCs for three types of EOR surfactants. The Du Noüy ring method was used with an automatic dispenser to dilute and measure surface tensions of the various surfactants at different temperatures and in different field brines. The effect of other chemical species, especially polymer was also investigated. Of the three surfactants studied, the betaine surfactant showed the lowest CMC in both injection seawater and field produced brine. It also out-performed the others in temperature stability for all types of brines. The other two surfactants were an amine oxide and an alpha olefin sulfonate. For the field brine conditions, the amine oxide proved to be the poorer performer in terms of CMC while the anionic alpha olefin sulfonate was close to the amphoteric surfactant. Determination of CMC for real field brine conditions and at elevated temperatures provides a good insight into the performance and potential of different surfactants. Coupled with other tests like phase behavior and interfacial tension (IFT) measurements, very quick decisions can be make about the efficacy of surfactants for field application.

Changes in crude oil wetting of carbonate rock when treated with various surfactants was evaluated using the Washburn method by the sorption of crude oil into packed rock powders. This method served to circumvent the difficulties of direct contact angle measurements on rock-chips where the low interfacial tension between the crude oil and surfactant leads to the spreading and eventual escape of the oil droplet without being attached to the rock chip. Four surfactants were used in the study including an anionic alfa olefin sulfonate, a cationic quaternary ammonium salt, an amphoteric surfactant and a nanosurfactant. Rock powders from a carbonate rock with a mesh size between 80 and 100 were coated with the tested surfactant solutions and compacted in a sample holder for the sorption experiments. Crude oil was raised to the bottom of the powder pack and allowed to rise into the powder by capillarity. A sensitive balance was used to measure the mass of crude oil imbibing into the powder until imbibition ceased. A plot of the square of oil mass against time enabled calculation of the contact angle using the modified Washburn equation. Earlier, a sorption experiment using n-hexane was used to deduce the rock constant for the grain packing, which was necessary for calculation of the crude oil contact angle. The contact angle results demonstrated the surfactant solution's efficiency in altering the crude-oil wetting behavior. An increasing washburn contact angle through coating indicates that the carbonate rock is rendered less oil-wet, which implies better oil displacement. At ambient temperatures, the nanosurfactant gave the highest contact angle implying the least oil-wetting; in second place was the amphoteric surfactant. The anionic surfactant had little effect on oil-wetting while the cationic surfactant decreased oil-wetting to a lesser extent. At higher temperatures, the nanosurfactant maintained its superior effectiveness followed by the cationic and amphoteric surfactants. The anionic surfactant saw little change. The use of sorption to obtain contact angle of crude oil for rock surfaces treated with surfactants eliminates the difficulties associated with direct contact angle measurements for low and ultra-low surfactant solutions where attachment an oil-droplet is almost impossible. With the Washburn method rapid evaluation of surfactants ability to change rocks wettability can be made to better guide further evaluations of such processes. As the washburn method measures contact angle between solids and a liquid surrounded by air, the contact angles obtained are not to be interpreted directly as those obtained in a liquid-liquid environment.

A thorough review of past chemical EOR projects illustrate that chemical EOR implementation can result in produced-fluid handling issues. However, in all projects such issues were resolved, mainly through a combination of improved demulsifiers and oversized vessels. In previous work, we have demonstrated the potential of surfactant/polymer flooding for a high temperature and high salinity carbonate. In lieu of future plans to pilot the process, further assessments were conducted to evaluate any side effects of those EOR chemicals on upstream facilities and come up with mitigation plans if needed. In this work, we investigate the surfactant-polymer compatibility with additives used in processing facilities for demulsification, and scale and corrosion inhibition as well as their possible impact on oil/water separation and metal corrosion. We firstly conduct a sensitivity-based simulation study to estimate the volumes of back-produced EOR chemicals. Secondly, a comprehensive compatibility study were conducted to evaluate EOR chemicals compatibility with oilfield additives (i.e. demulsifier, corrosion inhibitor, and scale inhibitor). Bottle tests were also conducted using surfactant-polymer solutions prepared in both injection and produced water to evaluate EOR chemicals impact on oil/water separation. Separated water qualities were evaluated using solvent extraction followed by ultraviolet visibility testing. Finally, static and dynamic corrosions tests were performed to evaluate EOR chemicals possible side effects. Based on simulation, the peak polymer and surfactant concentrations at the separation plant would be 83, and 40 ppm, respectively. The sensitivity study suggests a worst case scenario in which peak polymer and surfactant concentrations of 174 and 128 ppm are back-produced. Comprehensive compatibility testing confirmed the compatibility of EOR chemicals with the additives used in upstream facilities. In those tests, neither precipitation nor phase separation were observed. Bottle tests indicated an overall negligible impact on oil/water separation speed. However, analyses of separated water quality indicated a noteworthy deterioration in separated water qualities. Oil-in-water concentrations increased from 100 to 750 ppm and from 300 to 450 ppm at injection and produced-water salinities, respectively. Finally, corrosion tests suggest surfactant-polymer presence results in a significant reduction in corrosion rates by 70 and 86% at static and dynamic conditions without any pitting issues. Based on those results, the selected surfactant-polymer implementation will have negligible impact on separation facilities, if any. The main side effect was on oil/water separation. However, we shall stress that, at produced-water salinities, gravity-settling rates were not affected; yet, a slight but manageable deterioration in separated water quality was observed. However, a slightly more pronounced impact on separation could be observed at a late stage of the pilot once the polymer overflush (hence only polymer without surfactant) is back-produced. Nonetheless, we believe, such side effects if any can be addressed by adapting the demulsifier dose rate and will probably be small due to the reduction in polymer backflow concentrations at later stages and the continuous degradation of the polymer at reservoir high temperatures.