Shale Producers Piloting Downhole Compression To Solve Liquid Loading

Abstract

Almost all gas wells that co-produce liquids share a common and troublesome fate: liquid loading. A new artificial lift technology is being tested across different US shale plays with Equinor to avoid this inevitability. If successful, the system will become a viable alternative to the way in which these wells are produced today. Liquid loading crops up as the natural drive provided via early-stage gas production falls below the point required to move the associated water and/or natural gas liquids to the surface. The problem is progressive, and ultimately leads to a water column in the well. This slows and eventually stops flow until an intervention is executed or if the well is shut in to build up pressure. Though liquid loading occurs in both conventional and unconventional wells, it poses the biggest economic risk to the latter because of the inherently rapid decline rates. After a couple of years, their flow is often only a quarter of what it was during initial production. These are the factors driving Upwing Energy to develop a magnetically driven subsurface compressor system. As explained by Chief Executive Officer Herman Artinian, the company’s technology boils down to this concise concept: “Suck the gas, and the liquids will come with it.” Like all artificial lift systems, the compressor is meant to be used when natural flow has stopped. The Cerritos, California-based Upwing believes that after 2–3 years the bottomhole pressure in most horizontal gas wells is low enough for the compressor to be used as a way to draw down pressure even further, both in the well and the reservoir’s fracture network. “It turns out, the same thing that is happening in the wellbore with the liquid loading is happening inside the reservoir—the little pores are getting liquid loading due to the capillary effect,” explained Artinian. With a constant source of suction, the trapped liquids can be moved from the nanosized pore throats, creating new pathways for free gas flow. Work done so far suggests a pressure-reduction ratio of roughly 3:1 does the job, e.g. a bottomhole pressure of 900 psi would set the compressor’s target at around 300 psi. As the gas and liquids exit the compressor, the increased velocity carries a continuous stream all the way to the wellhead, preventing liquid build up and slugging. Initial field tests of a prototype showed the compressor was able to lift 150 bbl of water per 1•mmscf. “That’s a significant amount of liquids—more than what most unconventional wells are producing today,” said•Artinian. Pilots to Prove Reservoir Response In 2016, shortly after the firm was founded, Upwing tested four prototype compressors in wells in Texas. Production in these wells saw an increase ranging between 30–58%. The aim for the fully developed version is a 75–100% boost in gas output, “which directly translates to a minimum of 10–20% more recoverability of an unconventional well,” said Artinian, adding that the return on investment is expected to be between 6 months and a year.