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Surfactant/polymer (SP) and alkali/surfactant/polymer flooding is of current interest because of the need to recover residual oil after primary and secondary recovery. If designed properly, these enhanced-oil-recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by performing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature, and the importance of those experimental results is conflicting.This paper investigates the effect of pressure and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor Type IIþ) to lower microemulsion (Winsor Type II-), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. Using a numerical simulator, we show that these changes in the optimum conditions can significantly impact oil recovery if not accounted for in the SP design.

Surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) flooding is of great current interest owing to the need to recover oil left behind after primary and secondary recovery. If designed properly, these enhanced oil recovery processes can give very high oil recoveries. Microemulsion phase behavior plays a central role in process performance and is typically measured by doing salinity scans in glass pipettes at atmospheric pressure and reservoir temperature using dead crude oil from the reservoir of interest. There have been only a few experiments reported in the literature on live oil at reservoir pressure and temperature and the importance of those experimental results are conflicting. This paper investigates the effect of pressure, temperature, and solution gas on microemulsion phase behavior and its impact on oil recovery. We examine previous data reported in the literature, and report new measurements with live oil to show that the optimum parameters can change significantly. The experiments show that while pressure induces a phase transition from upper microemulsion (Winsor type II+) to lower microemulsion (Winsor type II-), solution gas does the opposite. An increase in pressure decreases the optimum solubilization ratio and shifts the optimum salinity to a larger value. Adding methane to dead oil at constant pressure does the reverse. Thus, these effects are coupled and both must be taken into account. We derive a new thermodynamic model to explain why the logarithm of oil and water solubilization ratios is linear with pressure or inverse temperature. We also use a numerical simulator to show how to design the chemical processes to account for phase behavior shifts with pressure and solution gas to achieve good oil recovery. Introduction Surfactant-polymer (SP) flooding relies on achieving ultra low interfacial tension (IFT) to increase the capillary number and thus decrease the residual oil saturation trapped by capillary forces. The salinity plays an important role in achieving low IFT between both the microemulsion and oil, and the microemulsion and brine. The optimum salinity is defined as the salinity where the IFTs are equal (Healy et al. 1976). The optimum condition depends on the oil composition, salinity, pressure, temperature, and properties of surfactant/co-surfactant/co-solvent. Huh (1979) derived a theoretical equation showing that the interfacial tension varies inversely as the square of the solubilization ratios. Very few experiments of phase behavior on live oil at pressure have been done. Nelson (1983) was one of the first who examined the effect of pressure on the microemulsion phase behavior using an anionic surfactant. He did one experiment at high pressure and observed that diluting stock tank oil with methane increased the oil solubilization ratio. He stated, however, that the effect on phase behavior was very small. Puerto and Reed (1983) also studied the effect of pressure and methane on microemulsion phase behavior. They observed that when oil is pressurized with methane, optimum salinity decreases. Their observation, however, was based on only two measurements and they did not identify how solubilization ratios change. More recently the effect of pressure on the oil and water solubilization ratios at constant salinity was investigated (Austad and Strand 1996, Austad et al. 1996). They concluded that optimum pressure increased as methane was added to the oil. Skauge and Fotland (1990) showed that for a dead oil the optimum solubilization ratio decreased and the optimum salinity increased as pressure increased. Kahlweit (1988) and Sassen et al. (1991) showed that the Type III invariant point (microemulsion composition) on a ternary diagram for dead oil shifted towards type II- as pressure increased. None of these investigators reported systematic data showing the effects of salinity, pressure and solution gas on microemulsion phase behavior.

The goal of surfactant-polymer flooding (SP) is to reduce interfacial tension (IFT) between oil and water so that residual oil is mobilized and high recovery is achieved. The optimum salinity and solubilization ratio that correspond to ultra-low IFT have recently been shown to be a strong function of the methane mole fraction in the oil at reservoir pressure in some cases. We incorporate a recently developed methodology to determine the optimum salinity and solubilization ratios at reservoir pressure into a chemical flooding simulator (UTCHEM). The proposed method determines the optimum conditions based on density estimates using a cubic equation-of-state and measured phase behavior data at atmospheric pressure. The microemulsion phase behavior (Winsor I, II, and III) are adjusted based on these predicted optimum salinity and solubilization ratio in the simulator. Parameters for surfactant phase behavior equation are modified to account for these changes and the trend in equivalent alkane carbon number is automatically adjusted for pressure and methane content in each simulation gridblock. We use phase behavior data from several potential SP floods to demonstrate the new implementation. The implementation of the new phase behavior model into a chemical flooding simulator can greatly aid in the design of SP floods so that SP flooding failures are less likely to occur. The simulator will also make more accurate estimations of oil recovery. The new approach could also be used to handle free gas that may form in the reservoir. We show that not accounting for the phase behavior changes that occur when methane is present at reservoir pressure can greatly affect the oil recovery of SP floods. Improper design of a SP flood can lead to more oil being produced as a microemulsion phase than as an oil bank. This paper describes the procedure to implement the effect of pressure and solution gas on microemulsion phase behavior in a chemical flooding simulator, which requires the phase behavior data measured at atmospheric pressure.