Summary: High bottomhole temperature can lead to decreased downhole tool life in geothermal and high-pressure/high-temperature (HPHT) oil and gas wells. The temperature increase is exacerbated when circulation stops (e.g., during connection, tripping, and well control situations). While continuous circulation technology is an appropriate solution for managing temperature, it is not yet widely adopted in HPHT and geothermal drilling practices. This work investigates factors that impact downhole temperature (DHT) and recommends strategies to better manage the temperature when continuous circulation is not available. An integrated thermo-hydraulic model was developed to capture the transient behavior of DHT and was applied here to study the transient temperature profile when there is no fluid circulation. The model was validated using the open-source FORGE field data set, with the mean absolute percentage error between 1% and 4%. In addition, hundreds of case scenarios were numerically studied to investigate the impact of several key factors on the DHT. The evaluated factors include the pumps-off time, type and physical properties of the drilling fluid, wellbore hydraulic diameter, reservoir temperature, geothermal gradient, total wellbore depth and profile, and operational parameters before stopping the circulation. The cooling effects of different drilling parameters were compared to a benchmark case of continuous circulation. A correlation map was generated to visualize the impact of those parameters on the DHT distribution when circulation stops. A logarithmic relationship between the pump stop time and the DHT was observed. For the FORGE case scenario, the DHT increases by 27°C and 48°C after the pump stops for 30 minutes and 60 minutes, respectively. It was observed that water-based mud (WBM) with a high viscosity increases fluid convection heat resistance between the formation and wellbore. Also, drilling with a higher flow rate before stopping the pump can cool the near-wellbore formation faster and reduce the DHT even after circulation ceases. Wells with high geothermal gradients, like FORGE wells, have a higher temperature buildup during circulation stoppage than wells with low geothermal gradients targeting the same reservoir (formation) in-situ temperature. This study investigates the efficacy of different cooling strategies to avoid DHT buildup when there is no circulation. It thereby facilitates the optimization of geothermal and HPHT well design and construction to prevent downhole tool failures. The developed correlation map can aid drilling engineers in understanding the impact of different drilling conditions on the DHT.

Successful design and execution of slim-hole cementing operations depend on reliable prediction of the annular pressure and the efficiency of mud displacement by cement. A 3D model of the flow inside the casing and in the annulus during mud displacement/cement placement operations was created. The yield-power-law fluid model was used for the rheological behavior of mud, spacers, and cement. Mud displacement was analyzed by splitting the well into multiple sections and analyzing the efficiency of mud removal by spacers and cement, as well as the associated pressure gradients in each section for applicable combinations of pump rate and casing rotation speed. The results from the various computational steps were then integrated to compute the overall pressure and cement placement efficiency during the cementing operation. Using the new 3D model, a field case study was performed for a slim hole casing cementation on an unconventional shale well. The simulated peak surface pressure was only 0.3% lower than the measured data, and the trend of the pressure matched the measured data. This work provides a new tool for the well construction industry to predict and analyze the pressure during complicated cementing operations, thereby enabling safer and more cost-effective operations.

Chromium Carbide Overlay (CCO) has long been used in Canadian oil sands mining industry to protect process equipment and piping from severe abrasion, erosion, and erosion/corrosion. However, CCO with poor quality has led to many premature failures in the field service, and resulted in high production loss and maintenance cost for oil sands operators. Most of the failures were due to the spallation of CCO under sliding/impact wear. Extensive lab tests and assessments in conjunction with technical studies/literature reviews were applied toward common commercial CCO products to further understand the effects of overlay composition and welding parameters on underbead cracking, mechanical properties, and wear/abrasion resistance. The study revealed that the extent of underbead cracking is related to the welding heat input, consequently affecting the spallation resistance of CCO. Outcomes of this research include a proposed guideline on how to improve CCO performance under sliding and impact wear by optimizing composition, fabrication, and non-destructive examination (NDE) techniques, including development of an NDE procedure with respect to underbead cracking.

Four oil blobs (bright) are spinning in the EMG 700 water-based ferrofluid (dark) in a pore in a micromodel driven by a rotating magnetic field. It shows the immiscible fluid-ferrofluid two-phase flow in a pore under a rotating magnetic field. Ferrofluid is a potential flooding fluid for enhanced oil recovery and a potential tracer for reservoir characterization. Micromodels are used to visualize and study the flow in porous media at both pore-scale and core-scale. A pair of N52 magnets induce a 2.6 mT 8 rpm rotating magnetic field that provides the driving force.