The Offshore Technology Conference (OTC), held each year in Houston, Texas, US, is one of the world's leading upstream oil and gas events. Before OTC 2020 was cancelled due to the COVID-19 pandemic, Oilfield Technology contacted a range of key players in the upstream industry and asked for their insight on the latest technologies that were due to be showcased at this year's OTC.
In this submission, Herman Artinian, Upwing Energy, USA, reviews the company's subsurface compressor system.
Upwing Energy recently completed a successful field trial of its first commercial Subsurface Compressor SystemTM (SCS), which uses advanced magnetic technologies to create higher reservoir drawdown and reduces liquid loading in gas wells. Test results revealed that the SCS increased gas production by 62% and liquid production by 50% in an unconventional shale gas well.
The SCS is a reliable, robust and cost-effective downhole solution that removes the primary failure points of conventional electric submersible pump (ESP) artificial lift systems. The hybrid wet gas compressor is driven by a hermetically sealed high-speed permanent magnet motor. A magnetic coupling conveys torque from the motor to the compressor with no mechanical shaft or seals, so there is no need for a motor protector to isolate the motor from downhole fluids. This ‘protectorless’ design removes a frequent point of vulnerability for conventional downhole systems. A sensorless wide-frequency variable speed drive (VSD) at the surface controls the motor at speeds up to 50 000 rpm.
Figure 1. The Upwing SCS is installed in a shroud, which carries the weight of the 1000-ft tail pipe in the horizontal section of the well.
The SCS creates a suction effect at the compressor inlet at the bottom of the wellbore, thus lowering the bottomhole flowing pressure and increasing gas velocities. This drawdown induces more gas flow from the formation to the wellbore. The SCS also generates higher gas velocities in the horizontal and vertical sections of the wellbore, enabling more liquids to be carried to the surface. Decreasing back pressure from liquid loading results in increased gas production, which in turn accelerates liquid unloading and prevents vapour condensation when exiting the compressor.
The SCS architecture simultaneously maximises gas and condensate production, recoverable reserves, gas-in-place recovery efficiency and liquid unloading. These benefits can be realised in any type of formation and wellbore geometry for both onshore and offshore environments.
The first full-scale unit was built and fully tested in the laboratory before being deployed over a two-month field trial in an unconventional shale gas well located in Indiana, US. The well has a 2000 ft vertical depth and a 5000 ft horizontal section, where liquid had accumulated. The compressor was installed at the bottom of the vertical section with a tail pipe extending approximately 1000 ft into the horizontal to provide enough velocity to carry liquids while minimising friction losses.
Prior to installing the SCS, the well’s gas production was approximately 185 million ft3/d and its liquid production through the rod pump was 5 – 7 bpd. Without the rod pump, the well choked in a few hours. With the SCS, the well stabilised at a gas production rate of 300 million ft3/d, a 62% increase. At 30 000 rpm, the gas velocity increased to 29 ft/sec. and liquid production increased by 50% over the steady-state performance with the rod pump.
Read the article online at: https://www.oilfieldtechnology.com/offshore-and-subsea/14052020/otc-technology-review-upwing-energy/
You might also like
The well was drilled by the ‘Deepsea Stavanger’ drilling rig, about 25 km southwest of the Oseberg field in the North Sea and 150 km west of Bergen.