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Abstract

One of the challenges in slickwater fracturing of tight sand gas reservoirs is post-treatment fluid recovery. More than 60% of the injected fluid remains in the critical near wellbore area and has a significant negative impact on the relative permeability to gas and well productivity. The trapped water could be due to capillary forces around the vicinity of the fractured formation. For strongly water-wet tight gas reservoirs, capillary forces promote the retention of injected fluids in pore spaces. 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 microemulsion to the fracturing fluid can result in lowering the pressure needed to displace injected fluids and/or condensate from low permeability core samples. This alteration of the fracturing fluid effectively lowers the capillary forces in low permeability reservoirs. This will result in removal of water and condensate blocks, the mitigation of phase trapping, and therefore an increase in permeability to gas. This paper examines the effectiveness of microemulsions in the improvement of fracturing fluid recovery. Coreflood runs using 20 in. Bandera sandstone cores with residual condensate and water showed that the percentage of permeability regained due to treatment with microemulsion solutions was up to 150% depending on type of microemulsion. An environment-friendly microemulsion formulated with a blend of a novel anionic surfactant, nonionic surfactant, short chain alcohol and water showed very good results in lowering interfacial tension between water and oil, when compared with competitive technologies. The performance of this microemulsion was excellent in high salinity fluid as well as low salinity fluid. It was excellent for solubilizing liquid condensates which can be found in wet gas wells. Contact angle of 63.45 degrees makes this microemulsion an optimal solution for cleanup of the near wellbore area. The resulting capillary pressure for a frac fluid treated with 0.25 wt% of this chemical in 2 wt% KCl is nearly 300 times lower than untreated fluid and 30 times lower than a fluid treated with competitive technologies.

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/content/papers/10.3997/2214-4609-pdb.395.IPTC-17675-MS
2014-01-19
2024-06-20
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