The objective of surfactant formulation design is to achieve ultra-low interfacial tension (IFT) with the oil in place in reservoir conditions. Several parameters have to be investigated, the presence of dissolved gas in crude oil can greatly impact the surfactant/brine/crude oil microemulsion phase behavior and omitting it may degrade the formulation efficiency. We propose an experimental investigation of optimal salinity evolution as a function of live oil compositions and conditions varying the pressure independently to the gas to oil ratio (GOR), i.e. the amount of gas dissolved in crude oil. A specific High Pressure - High Temperature (HPHT) sapphire cell with a mobile piston is used to separately study the impact on the formulation optimal salinity of: (i) the GOR by adding different amounts of C1 to C5 n-alkanes at the corresponding saturation pressure; and (ii) the pressure cell – up to 500 bar – by varying the cell volume (without changing the live crude oil composition). Experiments were performed at 40°C and at the saturation pressure or above. Using the HPHT sapphire cell we show that GOR variations up to 135 Sm3/m3 induce important modifications of the {surfactant/brine/oil} microemulsion phase behavior. In the case of the studied fluid, experimental data indicate that the optimal salinity of the {brine/surfactant/oil system} decreases when increasing the amount of gas dissolved in the live crude oil. As a consequence, the equivalent alkane carbon number (EACN) of the live crude oil strongly depends on the gas to oil ratio. We demonstrate hereafter that the cell pressure– for a fixed composition (i.e. fixed GOR) –impacts neither the formation nor the stability of the microemulsion. Furthermore, preliminary results suggest that the composition of the dissolved gas has a slight effect on the microemulsion phase behavior. In this work, using a specific HPHT sapphire cell, we are able to dissociate the impact of the amount of added gas from the impact of the cell pressure and to consider pressures up to 500 bar. Whereas the pressure alone has a negligible influence on the surfactant/brine/oil microemulsion phase behavior, the dissolution of gases in crude oil leads to a decrease of the optimal salinity and a variation of live crude oil EACN.

An Alkaline-Surfactant-Polymer / Surfactant-Polymer (ASP/SP) design study generally includes intensive work. Hundreds formulations have to be tested to screen phase behavior and typically a dozen of corefloods are performed to select the best formulation and further optimize the injection strategy/slugs design to match economic criteria.To be extrapolated to the field, it is critical to perform these tests in conditions as close as possible to real reservoir conditions: reservoir temperature, injection brine, reservoir pressure and reservoir oil. Specifically, dissolved gas and highpressure tend to significantly impact crude oil properties, and subsequently formulation behavior and performance, even when limited amount of gas is present. Ideally, this parameter should be considered from the beginning of the formulation design. However, considering the high number of tests to perform, as well as the relatively high cost and technical challenges associated with live oil experiments, it is unrealistic to routinely perform all the required experiments in high-pressure environment.We will present here the methodology developed to design surfactant based process by mimicking the impact of reservoir gas and pressure on the reservoir stock-tank oil. First a thermodynamic model based on an equation of state is fitted to reservoir PVT data (Gas/Oil Ratio or GOR, stocktank oil and associated gas composition analysis, bubble pressure and volumetric factor Bo) to predict consistent thermodynamic behavior and properties of the live oil. This step allows us to validate the reservoir conditions. A recombination of stock-tank oil with gas should be then performed to obtain the fluid in the reservoir conditions. Then we will illustrate through case studies how to combine a high-throughput robotic platform and a high-pressure/high-temperature cell to determine a representative crude oil matching live oil main properties, namely viscosity and Equivalent Alkane Carbon Number (EACN). This representative crude oil is obtained from the reservoir stock-tank oil which has been adjusted, using solvents or alkanes, to present the same characteristics as the reservoir live oil. This oil will therefore be used for an exhaustive formulation design and process optimization. Finally, we will compare oil recovery performances with the representative crude oil and with the reservoir live oil.

Chemical enhanced oil recovery techniques progressively emerge as a means to increase mature oil fields production. In particular, surfactant flooding allows increasing oil production by lowering the interfacial tension between injection water and crude oil. The effectiveness of surfactants depends on their chemical stability over an extended period of time, which could be impaired by reservoir conditions in terms of temperature, salinity and oxidative conditions. Within the frame of this work, we monitored the chemical stability of several families of anionic surfactants in water, including alkyl ether sulfates, alkyl glyceryl ether sulfonates, alkyl benzene sulfonates and internal olefin sulfonates. Analytical methods were first developed to evaluate the chemical stability of these surfactants, including high pressure liquid chromatography (HPLC) and mixed-indicator titration techniques. The thermal stability of industrially representative surfactants was then monitored as a function of time at high temperature. Anionic surfactants designed to withstand high temperature conditions proved to be stable in oxygen controlled environments over a very long storage time. Alkyl benzene sulfonates, internal olefin sulfonates and alkyl glyceryl ether sulfonates (or alkyl alkoxyl glyceryl sulfonates) notably showed a very good stability over a year–long storage at 100°C. Alkyl ether sulfates (or alkyl alkoxy sulfates) showed by contrast a poor stability at 100°C as all the active contents were degraded in twenty four hours in deionized water and around four months in an alkaline buffer. The hydrolysis of the sulfate moiety at high temperature is probably responsible for the limited stability of alkyl ether sulfates at high temperature. This study highlights the strong benefit of using sulfonated anionic surfactants in EOR processes applied at high temperatures. In particular, it demonstrates the advantage of replacing alkyl ether sulfates by alkyl glyceryl ether sulfonates in order to insure the long term stability of a formulation developed to be injected during several years.

The mobility of Winsor III microemulsions, which can form in reservoirs when a surfactant formulation contacts oil, has become a critical parameter for feasibility evaluations of surfactant flooding EOR. The reason is that these bicontinous phases with low mobility are likely to impair the sweep efficiency of the remobilized oil. The common procedures to evaluate microemulsion's mobility are based on viscosity measurements. As they involve rheometers, namely pure shear flows, and conditions where microemulsions are separated from the water and oil phases they should remain equilibrated with, they are not satisfactory. We present a new method to directly determine the mobility of microemulsions at equilibrium and in-situ, namely when flowing in porous media. The method consists in preforming the Winsor III microemulsion in a buffer cell and then injecting it in a small sized core plug. The bicontinous phase stays at equilibrium because the oil and water phases, present in the buffer cell, remain in contact with it. The mobility is assessed through the resistance factor (or mobility reduction factor), relative to the water phase injected first. This observable accounts for both viscosity and potential permeability impairment effect. As it directly represents the reduction of the mobility of the water phase, it is representative of phenomena taking place in the reservoir. During a typical experiment, the same microemulsion is also injected in a capillary tube, in order to determine its viscosity in a pure shear flow. Winsor III microemulsions were injected in sandstone plugs of three different permeabilities (1700 to 45 mD), and in a 170 mD carbonate plug. The first outcomes are that the resistance factors in the porous media and capillary relative viscosities have a marked shear-thinning behavior but are always of the same order of magnitude. This indicates that the flow of microemulsions entails no or little permeability impairment. Based on the experimental determination of the porous media's shape factors, the resistance factors and capillary viscosity data were also plotted against the equivalent wall shear rate. For the highest permeability sandstone, the capillary and porous medium data scaled almost perfectly, showing that, in this case, the microemulsion's transport properties are that of an ideal non-Newtonian fluid. However, increasing deviations were observed when decreasing the sandstone permeability as well as for the carbonate porous medium. This suggests that microemulsions are strongly affected by the composite deformations taking place in complex microscopic pore structures. These outcomes show the importance of determining the microemulsion-induced resistance factor in representative conditions in order to forecast for the impact of microemulsion's mobility in reservoirs. Furthermore, the method proposed can be applied to investigate close to optimum conditions as well as to study the propagation of microemulsions.