Fracturing With Foam

Abstract

Abstract Foam has been successfully applied as a circulating fluid for workovers and drilling for several years. Now a new oilfield application has been developed for foam: formation stimulation by fracturing. Over 150 wells have been treated to date in Canada using foam as the fracturing fluid, with a high degree of success. Unique 'rheological properties of foam make it well suited to this application: high sand carrying capacity, low fluid loss coefficient, low fluid friction loss, quick load fluid recovery low formation damage, and little or no reduction of fracture conductivity due to residual fluid saturation. The cost of the treatment is competitive with that of conventional systems. Introduction Fracturing of oil and gas wells involves the injection of a fluid into a well at a sufficient rate and pressure to physically rupture the rock down hole. A crack, or fracture, is developed and extended deep into the reservoir with continued fluid injection. Sand is carried in the fracturing fluid to prop the crack open when pumping is stopped, leaving a new, more permeable route for oil and gas to flow into the wellbore. Foam has recently been successfully used in place of conventional fracturing fluids, such as oil or water, for this process. The type of foam normally used is comprised of water, surfactants and a discontinuous gaseous phase of nitrogen. The volumetric gas content, referred to as "foam quality", is generally in the range of 65% to 95% under calculated downhole treating conditions: Equation (1) Available In Full Paper. Field Operations During a Foam Frac ™ treatment, water from a tank is continuously mixed with sand in a blender, at sand-water ratios progressively increasing to as high as 8 lbs/gallon. A surfactant, or foaming agent, is then proportioned into this slurry at a ratio of .2%; to 1.0%, and the resultant fluid blend is transferred to a high-pressure triplex pumper. High-pressure nitrogen gas is manifolded into the discharge line of the triplex, and it is at this point that the foam is developed. KCl, gellants or other chemical treating agents may be added to the base water if required to improve its compatibility with the reservoir rock or fluids. Figure 1 schematically shows this process. The blender and high-pressure pumper are conventional oilfield service equipment, modified to accurately proportion the high sand ratios pumped at slow discharge rates. The high-pressure N2 gas is also available from conventional oilfield N2 service units. Figure 2 illustrates an actual job in progress. The foam injection rates and volumes are in the order of 4 to 5 times those of the liquid pump rates and volumes at the blender because of the expansion by introduction of N2. These total volumes and rates are increased by a factor F, as follows: Equation (2) Available In Full Paper. For example, using a 75% foam quality, the foam injection rate will be 4 times the fluid pump rate at the blender.