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.

Horizontal and maximum reservoir contact (MRC) wells are intended to increase productivity and minimize water production due to water conning. Their complex geometry makes cleaning up of drilling fluids filter cake a difficult task. It is hard to distribute the acid uniformly over long horizontal sections. Poor acid distribution occurs during matrix acidizing. Coiled tubing cannot reach the total depth of the well because of some limitations such as large washouts, length of the reel and diameter of the coil, which make acidizing horizontal wells ineffective. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, chelating agents, and enzymes are limited at certain conditions. This paper introduces a new method for filter cake cleaning using a self-destructing water-based fluid to drill long horizontal and MRC wells, which results in higher productivity. This fluid is a water-based mud that is weighted with calcium carbonate and has both functions of drilling and completion fluids, can reach total depth of MRC wells. It has the ability to effectively stimulate the whole horizontal sections after drilling. This can result in significant cost savings by elimination of acidizing using coiled tubing or any other means and improvement in filter cake removal and thus enhances performance of the treated wells.

Summary One of the challenges in slickwater fracturing of gas reservoirs is post-treatment fluid recovery. More than 60% of the injected fluid remains in the critical near-wellbore region and has a significant negative impact on the relative permeability to gas and well productivity. The trapping of water could be caused by capillary forces around the fractured formation. Commonly available surfactants are added to slickwater to reduce surface tension between the treating fluids and gas. The problem with surfactants is that, upon exposure to the formation, they adsorb on the surface of the rock. The addition of microemulsions to the fracturing fluids can result in a reduction in the pressure needed to displace injected fluids and/or condensate from the formations. This alteration of the fracturing fluid effectively reduces the capillary forces in the near-wellbore region, and in the case of fracturing, the fluids that have been trapped in the region surrounding the fracture. This will result in the removal of water and condensate blocks, as well as the mitigation of phase trapping, and therefore, an increase in permeability to gas. This paper examines the effectiveness of microemulsions in the improvement of fluid recovery by use of sandstone cores with permeability greater than 10 md. Compatibility tests were performed for microemulsions to investigate their compatibility with the condensate and stability upon dilution with brine. One microemulsion showed incompatibility and was excluded from further experiments. Coreflood runs that used 20-in. Bandera sandstone cores with permeabilities greater than 10 md showed that the improvement factor in effective gas permeability because of treatment with microemulsions was up to 2.5, depending on the type of microemulsion. Thermal stability tests were performed on microemulsions, and the results showed stability of the microemulsions at high temperatures up to 400°F. A newly developed microemulsion (Nguyen 2013) that was formulated with a blend of anionic and nonionic surfactants, short-chain alcohol, oil, and water was tested and showed a significant reduction in the surface tension between water and nitrogen gas when compared with mutual-solvent and fluoropolymer-surfactant solutions. Among the tested chemicals, ME-V with a contact angle of 63.4° had the lowest capillary pressure, which makes this microemulsion the best treatment fluid among the four chemicals tested for gas-permeability enhancement and cleanup of the fluid in the near-wellbore region. The resulting capillary pressure for the fracture fluid treated with 0.25 wt% of this chemical in 2 wt% KCl is nearly six times lower than that of the untreated fluid with no microemulsion.