Salty Flowback Research May Explain Fluid Movement in Shale

Topics: Reservoir characterization
Image courtesy of the University of Alberta.
Developed with scanning electron microscopy and energy dispersive X-ray spectroscopy, elemental maps of the salts found in flowback water from an Evie Lake shale well in Canada reveal their complex composition.

An area of great interest to those researching flowback is the interaction of water and salt inside the shale reservoir. After a well is stimulated, the flowback fluids tend to show a rising concentration of salt that falls back to near zero over time.

The goal is to analyze this salt concentration curve to determine the complexity of a well’s fracture network. This is important since complex fractures are estimated to have a flowing surface area of 50 to 1,000 times greater than a simpler, or planar, fracture.

The applications for this area of study could be far reaching because nearly all North American shale plays were once covered by salty seas. As the water evaporated over the eons, the salt was left behind. In some shales, the salt is contained in formation water, but not always. So figuring out how exactly that salt ends up in the wellstream may explain how oil and gas move through the shale matrix, into the fracture network, and eventually the wellbore.

The University of Alberta (UA) researchers are using core samples from different Canadian shales to model the increased fracture area based on the dissolved salt content in the flowback fluid. So far, they have established three types of salt that may explain how it moves: loosely attached, moderately attached, and strongly attached.

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Salty Flowback Research May Explain Fluid Movement in Shale

Trent Jacobs, JPT Senior Technology Writer

08 November 2015

Volume: 67 | Issue: 12