Effect of Pressure, Temperature, and Solution Gas on Oil Recovery From Surfactant Polymer Floods

Abstract

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.

A Four-Phase Flow Model to Simulate Chemical EOR with Gas

“…,Roshanfekr et al (2009), Southwick et al (2012,Sagi et al (2013) andJang et al (2014).Jang et al (2014) used sapphire cells to measure the phase behavior for eight different oil samples over a wide range of pressure, temperature and solution gas and is the most complete set of data available at this time Roshanfekr et al (2009), Southwick et al (2012. andJang et al (…”

Enhanced Oil Recovery: An Update Review

“…Therefore and despite the volatility of oil prices, it is fair to conclude that operators and surfactant manufacturers are showing a growing interest in EOR chemical flooding [132,133]. This trend is also noticed with an increase of screening and lab studies to evaluate or re-estimate EOR potential of chemical flooding in different basins [134][135][136][137][138][139][140][141].…”

Alkaline Surfactant-Polymer Formulation Evaluation in Live Oil Conditions: The Impact of Temperature, Pressure and Gas on Oil Recovery Performance

“…Nelson (1983), Puerto and Reed (1983), Austad and Strand (1996), Roschanfekr et al (2009) andSoutwick et al (2010) showed experimentally that dissolving methane increases the surfactant relative solubility with oil and then decresases the optimal salinity. The impact of pressure on phase diagram has been studied by Skauge and Fotland (1990), Kahlweit et al (1988), Austad et al (1990), Sassen et al (1991), Austad and Strand (1996) and Roschanfekr et al (2009) who observed that an increase in pressure shifts the optimal salinity to higher salinities. Few models are presented to explain surfactant phase behavior with crude oil, pressure and dissolved gas.…”