Abstract

Success of the stimulation treatments in low-permeability, gas-producing formations largely depends on the fracture-face damage mitigation and cleanup of stimulation fluids from the propped fracture and formation matrix. These factors become even more critical in deep, conventional gas reservoirs, unconventional coalbed-methane reservoirs, shale, and ultralow-permeability tight-gas sands. Traditionally, in the industry, the focus for the success of the stimulation-fluid cleanup had been placed on conductivity damage of the proppant pack. It has more recently been realized that gas recovery and post-fracturing treatment results can be strongly dependent on other factors like wettability issues, phase trappings, water/gas relative permeability, and saturation states. The efficiency with which the fluids get extruded from the matrix or from the hydraulic fractures to the wellbore gets greatly diminished if conventional stimulation fluids are used without appropriate surfactant systems, leading to longer ROI times. Many microemulsion-surfactant systems have and are currently being developed based on the study of factors affecting the dynamic-displacement behavior through the application of surfactants. Many so-called optimized treatments are not designed to adequately deal with all the issues within a particular well or reservoir and might actually create or cause more damage than originally existed.

This paper describes laboratory test methods, comparisons, and results used for evaluating and selecting surfactants for deep, gas-bearing formations, such as shales and tight sandstones. Data presented here will aid operators in choosing the best surfactant/microemulsion package for optimizing hydrocarbon production.

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