Temperature profiles for both the production and injection (during gas lift operations) flow paths are calculated according to the user-selected settings. The temperature profiles play a key role in determining the PVT properties, bottomhole pressure, gas lift valve opening/closing pressures, and overall production performance. Multiple modeling methods are developed and available for selection, each offering their own advantages.

Earth's surface temperature is requested from the user which will be used to generate a linear geothermal temperature profile from the surface temperature to the reservoir temperature.

ProdX assumes that the injection fluid does not affect the production fluid's temperature, and therefore solve the production fluid temperature profile based on the given geothermal temperature. The following methods and configurations are available in ProdX model settings:

In this method, the production fluid temperature is set equal to the given geothermal temperature at any given depth. This is relatively accurate for low temperature reservoirs and low production rates.

Developed based on the experimental work of Shiu and Beggs, this method estimates the shape of the production temperature profile based on the Shiu-Beggs equations. Modifications are applied that allow modeling deviated wells, varying tubing/casing diameters, annular production, and user-defined bottomhole temperature values that could differ from the reservoir temperature.

The method requires only the bottomhole fluid temperature (if not set to geothermal), and a correction factor, allowing profile to be calibrated to match available measurements. The model provides a relatively accurate temperature profile without any significant computational burden.

The CHTC method discretizes the wellbore and solves for temperature at every node from bottomhole to surface. The model dynamically changes the discretization to ensure numerical stability and accurate solutions. The starting bottomhole temperature is either provided by the user or set equal to the geothermal temperature (i.e. Wellbore Formation temperature). CHTC method solves the energy equation at every node by equating the heat transfer to the production fluid from formation and the internal energy changes within the formation fluid. This method requires water, oil and gas specific heat capacities, and the heat transfer coefficient, which is assumed to be constant along the entire wellbore. This coefficient can be calibrated to match available measurements.

The injection fluid temperature is affected by the production fluid temperature (when injecting through the tubing), and by both the production fluid and geothermal temperatures (when injecting through the annulus). Three models are available to choose from for estimating injection fluid temperatures:

In this method, the injection fluid temperature is set equal to the given geothermal temperature at any given depth. This method may be suitable for gas lift operations where gas is injected into the annulus. In practice, gas temperature profile is observed to approach the geothermal temperature profile for such cases and therefore, the geothermal assumption can provide a reasonable estimate.

In this method, the injection fluid temperature is set equal to the calculated production temperature at any given depth. This method may be suitable for gas lift operations where gas is injected into the tubing. In practice, gas temperature profile is observed to approach the production fluid temperature profile for such cases and therefore, the production assumption can provide a reasonable estimate.

For more accurate solutions, the CHTC method can be used to solve for gas temperatures. Similar to production temperature modeling, flow path is discretized dynamically to ensure numerical stability. Injection temperature is provided by the user, and energy equation is solved for temperature at each segment starting from the surface node. This method asks for gas specific heat capacity as well as heat transfer coefficient between the injection and production fluids and heat transfer coefficient between the injection fluid and the formation (the latter is only applicable when injecting into the annulus). These heat transfer coefficients determine how closely gas temperatures follow the production and geothermal temperature profiles in the model.