Improving Fluid Recovery and Permeability to Gas in Shale Formations
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Despite all advantages of slickwater fracturing such as low cost, high possibility of creating complex fracture networks, and ease of clean-up, large quantities of water are still left within the reservoir after flowback. Invasion of aqueous fracturing fluids can reduce the relative permeability to gas and thereby cause a water blockage. Compared to conventional surfactants that lose activity after contacting the first few inches of the formation due to adsorption to the rock surface, microemulsions with advantage of having combined effect of microemulsion-forming surfactants and organic solvents, outperform pure organic solvent or pure surfactant when used independently. Microemulsions can provide maximum surface area of contact with the formation due to their structure and can increase penetration and cleaning efficiency. The research proposed in this study has been designed to assess the performance of microemulsions when it is used as an additive to the fracturing fluid to stimulate the gas bearing formations. Microemulsions formulated with a blend of anionic surfactant, nonionic surfactant, oil and water were used to prepare the microemulsion systems. The average size of the microemulsion-V droplet (as received) was detected by transmission electron micrographs (TEM). Microemulsions were tested to assess their efficiency in reducing the surface tension and in wettability alteration. Experiments were conducted using cores from an outcrop of Bandera sandstone to measure the effect of microemulsions on the gas permeability enhancements. The increase in gas permeability was quantified by comparing the relative gas permeability before and after treatment. The alteration of wettability after the chemical treatment was evaluated by measuring the contact angles between the treatment fluid and rock. Thermal stability tests were conducted using hot rolling cells for temperatures up to 400°F, which proved the high stability of microemulsions at high-temperature conditions. Microemulsions caused enhancement in the relative gas permeability, when compared to the mutual solvent, fluoropolymer surfactant, anionic, and non-ionic surfactant solutions. Microemulsions altered the wettability of water-wet rocks to less water-wet. Aging the shale rock particles in contact with different treatment solutions, showed an increase in the concentration of tested elements including Ca, Mg, Al, and Si in the solutions that can be an explanation of high total dissolved solid (TDS) in the flow back fluid after completion.
Rostami, Ameneh (2015). Improving Fluid Recovery and Permeability to Gas in Shale Formations. Doctoral dissertation, Texas A & M University. Available electronically from