CO2 Foam Behavior: Influence of Temperature, Pressure, and Concentration of Surfactant

Abstract

Abstract A high-pressure, high-temperature (HPHT) bubble chamber apparatus is used to determine carbon dioxide (CO2) foam stability, interfacial tension (IFT) between HPHT CO2 and surfactant solutions and critical micelle concentration (CMC). Chaser CD1045™ (CD) was used in this study. In this study, changes of temperature from 25 to 75ºC, pressure from 800 to 2000 psig, and surfactant concentration from 0.005 wt% to 1 wt% were tested for foam stability, IFT and CMC. The relationship of foam stability and IFT is also discussed in this paper. IFT decreased with surfactant concentration below the CMC and was essentially constant above the CMC, increasing with the increase of temperature and the decrease of pressure. Stability of CO2-foam is surfactant concentration-dependent. The coalescence of bubbles was observed only at CD concentration of 0.005 wt%, well below the CMC at 25ºC and 1500 psig. The foam was stable under all tested temperatures at surfactant concentrations of 0.1 wt% and above, and decreased with increase of temperature at surfactant concentrations of 0.05 wt% and below at 1500 psig. The foam was stable under all tested pressure at surfactant concentrations of 0.025 wt% and above, and decreased with increase of pressure at CD concentrations of 0.005 wt% at 25ºC, and similar behaviors were observed at high CD concentrations at 75ºC. Introduction CO2 flooding is generally considered the fastest-growing improved oil recovery (IOR) technique. In 2002 the number of reported CO2 projects in the United States exceeded the number of thermal projects for the first time.[1] This is due to recent research focusing on CO2 flooding, availability of CO2, reservoirs amenable to CO2 flooding, and success of CO2 floods. On the basis of laboratory displacement experiments and field applications, at pressures above the minimum miscibility pressure of CO2 and reservoir oil, a developed miscibility flood could be expected to produce a significant fraction of the oil remaining in the formation.[2–14] CO2 flooding can increase oil recovery by 7–15% of the original oil in place and can be sustained for 10–30 years.[2–14] The use of CO2 flooding for IOR is increasing, because of the following reasons:CO2 remains a dense fluid over much of the range of pressures and temperatures found in many oil reservoirs.CO2 fluid is miscible or partial miscible with many hydrocarbon components of crude oil at reservoir conditions.Dense CO2 has relatively low solubility in water compared to oil.The U.S has CO2 resources near many oil fields.[5]As a displacement fluid, CO2 costs are relatively low if the CO2 is found near an oil field.Environmental and economic benefits are derived from related CO2 sequestration and the worldwide potential increases for CO2 use in IOR.[5]