Liquid Management in Gas Wells: Exploring the Impacts of Tubular Restrictions

Abstract

Abstract Liquid accumulation in gas wells impairs their production capabilities and reduces their operational lifespan. Various techniques have been explored to address this issue, yet no optimum solution has been identified for all wells. Operators continue to seek cheap and efficient methods to mitigate liquid loading in gas wells. Previous works have suggested that partial tubing restrictions, or inserts, have the potential to increase interfacial shear and droplet entrainment, thus delaying liquid loading. Due to increases in frictional pressure losses when inserts are present, a challenge remains in finding the operational conditions where their use results in a net positive effect for the well. In this work, experiments are conducted in a flow loop with a 25-ft vertical section, made from 2″ ID clear acrylic pipes, using air and Isopar-L oil at room temperature and near-atmospheric pressures. The accuracy of various two-phase flow models and correlations is evaluated for low superficial liquid velocities. Tests are conducted using insert rings with two internal diameters, 1.5″ and 1.75″. Liquid-gas flow pattern, liquid holdup, and pressure gradient are recorded and analyzed for each test. Results are compared with previous studies to assess the locality of the effects caused by the inserts and identify optimal conditions for their implementation The combined effects of insert size and spacing are analyzed on well deliquification at various flowrates. Video recordings show the dual mechanism by which inserts enhance liquid lifting, droplet generation promotion and liquid film fallback retention. Results indicate that inserts are particularly effective in modifying flow behavior within the churn flow region. Commonly used models are inadequate to predict pressure gradient and liquid holdup in this flow pattern, particularly at low liquid rates. The use of a single insert shows positive changes in the liquid holdup compared to the tests without inserts. Yet, better outcomes are obtained for both liquid holdup and pressure gradient when two inserts are used. This configuration, with an 18-ft spacing between inserts, closely matches tubular joints length. This suggests that properly designed tubing joints can function similarly to inserts, offering a cost-effective and passive solution to mitigate liquid loading in gas wells. The optimum range to use this technique is for low liquid loading conditions and gas rates of churn flow. The results of the analysis can provide a guideline on the best conditions to apply this technique and significantly reduce the operational costs and improve the revenues.