Downhole Temperature Estimation of a Growing High-Temperature Wellbore Using a Modified Drift Flux Modeling Approach

Abstract

Abstract Downhole temperature (DHT) estimation is very important for heat management while drilling high-pressure, high-temperature (HPHT) and geothermal wells to prevent premature bit and downhole tool failure. Existing transient models neglect the impact of wellbore growth / deepening on the downhole temperature, treating the wellbore). as having fixed dimensions. This leads to inaccurate temperature estimation, especially when drilling at a higher rate of penetration (ROP This paper presents a new modeling approach to overcome this shortcoming. A coupled model of thermohydraulic flow in a growing wellbore was created based on a drift-flux model. It incorporates three key features. First, a dynamic, real-time meshing method appends new calculation cells to the bottomhole location as the well is deepened. Second, geometry and drilling fluid physical properties near the interfaces between drillstring sections and wellbore sections are updated dynamically as the drillstring moves forward. Finally, the drift-flux equation is adjusted to account for the well geometry changes associated with a moving drillstring. The new model was validated using the open-source Utah FORGE field dataset and a previously validated model in a non-growing static wellbore. The DHT results from the new model converged to those from a well-calibrated model without wellbore growth when the rate of penetration (ROP) approached zero. Simulation results for a growing wellbore show that the DHT is generally higher compared to a static / non-growing wellbore and that this difference increases with higher ROP. The new model also provides new insights into the impact of the ROP relative to the pump rate on the DHT. When DHT estimation is needed for multiple wellbore sections, the new model only requires one set of input data to analyze the DHT at different well depths during the drilling operation. This is a major advantage in comparison to static-well models which require multiple input datasets, one for each wellbore section, with each input requiring carefully selected initial conditions to obtain realistic results. This work provides a new modeling tool, validated against a static-wellbore solver and field data, to estimate and manage the DHT in higher-temperature oil, gas and geothermal wells. The model, which has the potential to run in real time and thereby digitally twin the drilling operation, may contribute to preventing premature temperature-related failures of bits and downhole tools while drilling future wells in high-temperature environments.