Laboratory Studies on Fluid-Recovery Enhancement and Mitigation of Phase Trapping by Use of Microemulsion in Gas Sandstone Formations
- Ameneh Rostami (Texas A&M University) | Duy T. Nguyen (Nalco Champion) | Hisham A. Nasr-El-Din (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- May 2016
- Document Type
- Journal Paper
- 120 - 132
- 2016.Society of Petroleum Engineers
- fracturing, microemulsions, water blockage, condensate banking, tight formations
- 4 in the last 30 days
- 421 since 2007
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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 then 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 sandstine 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.
|File Size||1 MB||Number of Pages||13|
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