A series of surfactants were evaluated in this study and the results were compared with conventional foaming agents used in fracture fluids. These surfactants were examined by surface tension measurements, bench-top foam height and half-life experiments, and viscosity measurements on a circulating foam rheometer. The foam rheometer allowed viscosities to be measured under conditions that are representative of those found in formations. Both nitrogen (N2) and carbon dioxide (CO2) foams were investigated. This paper presents detailed results obtained from laboratory experiments, which led to the identification of foamer A that exhibited excellent performance in the presence of nitrogen and carbon dioxide over a wide range of temperatures. Foamer A was found to be superior compared with conventional foamers, particularly at high temperatures. It is compatible with linear gels as well as crosslinked fluids commonly employed for fracturing treatments. Numerous fracturing treatments with foamer A have been successfully executed in the field.
It is emphasized in the paper that the type of foamer used in fracturing treatments has a great impact on the resulting foam stability and viscosity. In addition, bench-top foam height and half-life experiments can give an indication of the performance of a specific surfactant, but its behavior under downhole conditions cannot necessarily be inferred accordingly.
Foams are stable mixtures of a gas dispersed in a liquid base material with the gas constituting the internal phase and liquid the external phase. The gas phase typically is nitrogen (N2) or carbon dioxide (CO2), and the liquid is often a viscous fluid for oilfield fracturing applications. Foamed fluids have been used in hydraulic fracturing since the 1970s (Schramm 1994). Among many benefits foamed fluids offer over nonfoamed fracturing fluids is that they have stored compressed gas for quick cleanup, efficiently returning the injected fracturing fluid to the surface. Thus, foamed fluids are particularly suitable for depleted or underpressured gas wells. Foams also minimize the amount of water injected into a well while providing superior rheology (Reidenbach et al. 1986), making them excellent treatment fluids in water-sensitive formations (Ward 1986). Furthermore, foams provide good fluid-loss control, improving the fluid efficiency. In addition to applications in hydraulic fracturing, foams can also be utilized as diverting agents (Burman and Hall 1986; Parlar et al. 1995) and employed in wellbore cleanout applications (Ozbayoglu et al. 2003).
For optimal performance, the foam must remain stable throughout the treatment. Several factors affect its stability, including the viscosity of the base fluid, the type and concentration of the foaming agent or foamer, the formation temperature, and the type and volume percentage of the gas phase. Water without a polymer is not commonly used as the liquid phase because of limited stability. Improved stability can be achieved by using linear polymer fluids or cross-linked gels. The foamer is a surfactant that facilitates dispersion of the gas into the liquid phase by lowering the interfacial tension. Furthermore, the foamer stabilizes the thin liquid films surrounding the bubbles and inhibits the coalescence of bubbles. As temperature increases, the drainage of the liquid phase in the foam structure accelerates due to thermal thinning of the liquid, leading to reduced foam stability. For this reason, maintaining the foam stability becomes increasingly challenging at high temperatures. The challenge further increases for CO2 foams because the high solubility of CO2 in aqueous media facilitates mass transfer between bubbles. Selecting foaming agents is critical in formulating stable foams, especially at elevated temperatures.