The Potential of Gas Lift in Low-Pressure Geothermal Wells: It Can Replace ESPs Where Applicable, According to Modeling Study

 

      Two of the most important parameters for conventional geothermal wells are temperature and flow rate. Flow rate can be seen as the rate of water production. Artificial lift, including gas lift, is commonly used to successfully increase production in oil wells. Typically, production is enhanced via electric submersible pumps (ESPs).

     Some areas that host geothermal resources, including some sedimentary basins, are not overpressured enough to sustain high flow rates. This is the case for the Molasse Basin in Germany, for instance. In those cases, ESPs are the norm for geothermal wells. ESPs are vulnerable to scaling, which is a significant problem in geothermal wells in general. High fluid flow can also damage ESPs.

     As noted below by Henk Kombrink in his GeoExPro article, gas lift involves injecting gas into the hydrothermal fluid, which lowers its density and hydrostatic pressure, allowing it to flow more easily toward and up the wellbore.

     As shown in the abstract and the graphs below, the researchers modeled several different gases, including methane, compressed air, nitrogen, and CO2. They found that all of the gases increased production significantly. Methane was slightly higher than compressed air and nitrogen, and CO2 was lowest. CO2 is also quite undesirable since it aids corrosion by about 16%, according to the study. Compressed air also aids corrosion by nearly 10%. This suggests that methane or nitrogen would be better gas candidates. Since the other gases are roughly similar in effect, I would think that the cheapest gas available near the project would be chosen for pilot projects, except for the corrosion vulnerability.

     Kombrink notes that previous gas lift projects in geothermal wells, including one that used nitrogen in Indonesia, ceased due to unfavorable economics. However, the new modeling suggests that water production rates can increase by an average of 80%, and subsequent power production rates can increase by an average of 118%. These numbers include the energy loss from running the gas injection system and, presumably, the total of parasitic loads, but as noted later, they do not include transient well processes.

     The study, published in the journal Geothermal Energy, utilized field data from a geothermal well in the Brawley Geothermal Field in California. The modeling considered parameters including fluid properties, wellbore geometry, and operational conditions. More specific parameters modeled include fluid temperature, flow rate, gas injection temperature, and thermal properties of the materials.

     The figures below from the paper show wellbore schematics, modeling workflow, and the surface equipment that would be used in the gas injection system.

     The researchers stress that they utilized a steady-state modeling approach for the study, which excludes the transient processes that routinely occur in geothermal wells, as they explain below. It is unclear how much excluding transient processes would affect real-world performance.

“The steady-state modelling approach assumes that the wellbore and surface system have reached equilibrium for each simulated condition. Transient processes like well unloading, start-up behavior, cyclic gas injection, short-term pressure fluctuations, gas lift valve dynamics, and time-dependent reservoir pressure decline are not explicitly modeled. Therefore, the results should be interpreted as quasi-steady performance estimates for specified conditions rather than predictors of transient field operation. Despite these limitations, this steady-state framework is appropriate for the objective of this study, which is to screen gas lift scenarios and quantify their relative impacts on production rate, wellhead temperature, compressor load, and net power output.”

     Some of the model assumptions, mainly for equipment efficiency, are given in the table below.

     The researchers also modeled injecting gas at different depths. They found that deeper injection depths increased the mass production rate significantly and the temperature slightly, as indicated below.

     The paper’s conclusions are summarized below. It is important to note that the greatest improvements will be found in wells with lower reservoir pressure. This is similar to artificial lift in oil wells. Finding the ideal gas injection rate is also important. Also noted is that while injecting gas at lower depths can increase production by 15%, it also requires higher injection pressures, which use power and so become more parasitic.

   

References:

 

Injecting gas in a geothermal well can double its net energy output: That is what a new published modelling study using the parameters of a Californian geothermal project suggests. Henk Kombrink, GeoExPro. September 22, 2026. Injecting gas in a geothermal well can double its net energy output - GeoExpro

Modeling of gas lift in liquid-dominated geothermal wells in Brawley field. Orkhan Khankishiyev & Hamid Karami. Geothermal Energy. Volume 14, article number 20. July 3, 2026. Modeling of gas lift in liquid-dominated geothermal wells in Brawley field | Geothermal Energy | Springer Nature Link