E&P-backed shale gas tech firm tests new pump in Indiana

By Luke Geiver | February 10, 2020

Equinor-backed Upwing Energy has gone to Indiana to test a new shale innovation capable of improving gas production and recoverable reserves by decreasing bottom hole flowing pressure and causing higher reservoir drawdown.

Upwing is a spin-off from Calnetix Technologies, a company that develops and manufactures high-speed motors, magnetic bearings and power electronics. Working with Riverside Petroleum, Upwing completed a trial of its subsurface compressor system. The trial showed a 62 percent increase in gas production and a 50 percent increase in liquid production over a steady state system previously installed with a rod pump.

“Upwing has the technology and system-level integration capabilities to not only make a step change in the reliability and economic feasibility of downhole artificial lift systems, but also to recover significantly more gas and liquids from reservoirs than has been possible previously,” said Herman Artinian, President and CEO of Upwing Energy. “We greatly value our partnership with Riverside Petroleum. In addition to providing us with a trial well, they have been extremely supportive throughout the evaluation, deployment and trial process.”

According to the company, The SCS carries liquids to the surface by creating higher gas velocities throughout the vertical and horizontal wellbores and prevents vapor condensation by increasing the temperature of the gas when exiting the compressor.

More takeaways from the field trial:

This was the first time a system comprised of a high-speed permanent magnet motor, magnetic coupling, passive magnetic bearings with electronic dampers and sensorless high-frequency controls has been deployed successfully in the downhole environment.

Upwing’s SCS was deployed in an unconventional well with a 2,000-foot vertical wellbore and a 5,000-foot horizontal wellbore, where liquid had accumulated. The compressor was installed at the bottom of the vertical section with a tail pipe extending approximately 1,000 feet into the horizontal to provide enough velocity to carry liquids while minimizing friction losses. The installation was very similar to electric submersible pump (ESP) systems in that the SCS unit was tubing deployed, and the electrical cable with the instrumentation was secured around the tubing. The trial period started at the end of October, and the SCS was pulled out in early December.

When the SCS operated at 30,000 RPM, the gas velocity increased to 29 feet per second, and a high rate of liquid was carried to the surface. The hybrid axial compressor was able to atomize the liquid into a very fine mist, which together with the increased velocity and heat generated from the exit of the compressor helped carry the liquids to the surface. The compressor blades showed no sign of degradation despite moving a significant amount of liquids.