Optimizing inhibitor injection in geothermal wells with electrical submersible pump

Abstract

Electrical submersible pump (ESP) is a reliable artificial lift method to extend productive lifespan of geothermal wells. In the geothermal industry a common practice involves installing ESPs below the well's flashing depth. This placement approach aims to mitigate the risk of mineral precipitation, which can occur when hot geothermal fluids transition to a two-phase state (liquid and vapor) as pressure decreases. Positioning the pump below the flashing depth also prevents pump's underloading and gas cavitation. The inhibitor injection line usually integrated around the ESP string and installed downstream of the ESP motor. However, this standard practice introduces a challenge regarding inhibitor performance. While this placement ensures effective distribution of inhibitors throughout the production flow, the extended travel time from the surface to the point of application at the ESP can diminish inhibitor effectiveness due to continuous exposure to high temperatures throughout the wellbore. This study proposes relocating the inhibitor injection point within the production tubing closer to the flashing depth. This reduces inhibitor travel time from 108 min to 48 min and has the potential to significantly improve inhibitor effectiveness. Consequently, the implementation of capillary tubing is anticipated to yield annual cost savings per wellbore of approximately USD 10,000, coupled with the mitigation of mineral deposits within the studied well equipped with ESP. To evaluate this approach, a wellbore simulation tool and PHREEQC were employed to dynamically model the pressure and temperature profiles alongside the geochemical evolution of the produced fluids in the wellbore. This modeling approach offers significant value by potentially enabling the optimization of inhibitor usage and reducing the length of required inhibitor injection line.