Abstract

For liquids-rich shale plays, a primary completion strategy is to enhance flow conductivity near the wellbore region by placing large-mesh proppant inside the fractures. One potential drawback of doing so is that the created fractures could be more planar in nature because of softer and more ductile rocks and therefore less contact could occur between fractures and the matrix during pumping. In addition, no external hydraulic force exists to drive fracturing fluids farther into the matrix after pumping is stopped at the surface. As a result, wells completed using this method could potentially suffer from a low fluid penetration rate into the reservoirs because of the resistance of capillary forces imparted by oil-wet or mixed-wet pores, which could result in lower-than-expected liquid production.

In this study, a new mechanism is proposed for increasing the contact area between fracturing fluids and the matrix. The working hypothesis is that a surfactant, when properly tailored to treatment fluids, can help achieve this objective by spontaneously spreading in the matrix, thereby accessing additional hydrocarbon reserves. To investigate this hypothesis, two primary experimental techniques were used.

  • Fluid penetration depth into mixed-wet formation core plugs was monitored using computer-assisted tomography imaging. Scans indicated that the fluid containing surfactants tends to penetrate almost twice as deep as that without surfactant. This observation is consistent with the finding of an earlier microfluidic study [1] that the use of surfactant significantly improved the rate of penetration of the non-wetting phase (water and surfactant solution) and the displacement efficiency of the wetting phase (oil).

  • The addition of surfactant reduced the interfacial surface tension, both elastic and viscous moduli (by means of the pulsating pendant drop method) of the oil-water interface to close to zero, making it deformable in the emulsion, which significantly aids oil mobilization.

The study results imply that the shut-in time immediately after fracturing could be crucial for enhanced well productivity. An extended shut-in time could result in farther penetration of fracturing fluids into the matrix and lead to greater oil recovery in liquids-rich shale plays.

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