Microemulsion vs. Surfactant Assisted Gas Recovery in Low Permeability Formations with Water Blockage

Abstract

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 their activity after contacting just first few inches of formation due to quick adsorption to the rock surface and limited thermal stability, microemulsions with smaller droplet sizes and lower surface tension can penetrate deeper to the formation and will result in significant gas recovery from low permeability formations. Micro-emulsions have shown to be an effective remedy for improving gas relative permeability due to their structure which can pro-vide maximum surface area of contact between surfactant and formation. Experiments were conducted using outcrop of Bandera sandstone cores to measure the effect of liquid blocking on gas relative permeability. Microemulsion treatment was developed to reduce the damage caused by water and condensate blocking. The chemical treatment alters the wettability of water-wet rocks to less water-wet and increase the gas relative permeability. The increase in gas relative permeability was quantified by comparing the gas relative permeability before and after treatment. The alteration of wettability after the chemical treatment was evaluated by measuring the contact angles between the solution and rock. Thermal stability tests were conducted using hot rolling cells for temperatures up to 400°F which proved the high stability of microemulsion solutions at HP/HT conditions. Microemulsion solutions showed very good results in gas permea-bility regain, when compared to the other treatment solutions. They can provide excellent fluid cleanup by flowing out of the well to the surface where the entrapped water can be recovered.

When Less Flowback Is More: A Mechanism of Permeability Damage and its Implications on the Application of EOR Techniques

“…How this practice relates to long-term fluid recovery as flowback has not been investigated, although the expectation in such cases is to have little to no produced water. On the other hand, several fluid additives aimed to enhance flowback and hydrocarbon permeability have been designed and tested in the laboratory (Penny et al, 2012;Rostami and Nasr-El-Din, 2014;Zelenev et al, 2010). In these studies, an increase in relative permeability to the hydrocarbon was always accompanied by an increase in fluid flowback, agreeing with expectation from the point of view of relative permeabilities but not necessarily with field observations.…”

Interfacial Tension Measured at Nitrogen–Liquid and Liquid–Liquid Interfaces Using Model Microemulsions at High-Pressure and High-Temperature Conditions

“…Water that remains in the pores near the wellbore forms water blocks that prevent the flow of hydrocarbon into the wellbore. As shown in Rostami et al’s study, displacement of the hydrophobic hydrocarbon gas phase is, in particular, problematic. , Applying microemulsions may lower the capillary pressure between the water and the oil, which increases flowback recovery and hydrocarbon production . Frequently, the laboratory experiments described in the literature involved aging tests of the respective treatment fluids at high temperatures.…”

The Applicability of Surfactants on Enhancing the Productivity in Tight Formations

“…The use of surfactant-based fluid additives to enhance fracturing fluid recovery and hydrocarbon production has also been investigated (Penny and Pursley, 2007;Rostami and Nasr-El-Din, 2014;Zelenev and Ellena, 2009). While these studies show enhancements in flowback and/or hydrocarbon permeability when surfactant-based additives are used, the physical mechanism responsible for such enhancements was not described and remains unknown.…”