Erlend Oddvin Straume

Currently, there are several deep drill geothermal projects that aim to discharge superheated or supercritical geothermal fluid for sustainable power production. In geothermal power utilisation, the well casing steel and surface equipment is susceptible to corrosion due to corrosive species in the geothermal fluid. The temperature and the phase state of the fluid greatly affect the extent and the forms of corrosion that can occur. To mitigate corrosion damage in the casing and surface equipment, the recently developed production method Extra High-speed Laser Application (EHLA) cladding is proposed as a solution. To simulate application of carbon steel and EHLA clads in superheated geothermal wells, the materials were tested in a superheated steam containing CO₂ and H₂S at 450 °C temperature and 150 barG pressure. Microstructural and chemical analysis was performed with SEM, EDX and XRD, and corrosion rate was analysed with the weight loss method. The carbon steel was prone to corrosion with a double corrosion layer but the corrosion of the EHLA clads was insignificant. The results show that the EHLA clads tested have good corrosion resistance in the test environment, and the study can aid in the selection of casing and clad materials for future deep geothermal wells. Furthermore, this study shows that the EHLA clads increase the variety of corrosion mitigation solutions for future geothermal projects.

Hydrate management, as opposed to avoidance, means allowing hydrates to form, but minimizing the risk of blockage formation, such that hydrates are transported with the production fluids. This strategy is starting to be a more viable approach in industry as a means to lower development and operational costs. Safe implementation of various hydrate management strategies requires a throughoutly understanding of how hydrates form and behave in diferent categories of multiphase systems of gas, oil and water. To further obtain insight into the different processes leading to hydrate blockage formation, a number of tests using a visual rocking cell have been performed to measure and observe the various stages for hydrate formation and the changes to the system evolve with continued mixing. This study has considered mineral oil + water + gas and condensate + water + gas systems. Tests were also performed with and without MEG and a model antiagglomerant. The experiments performed have shown that hydrates have a lower tendency to deposit on oil wetted surfaces than surfaces exposed to condensate or the gas phase. However, hydrate deposition was also observed in the oil system. The predominant processes in all experiments included hydrate particle growth, bedding and agglomeration. Hydrate deposits with high porosity formed under high subcooling conditions, resulting in sloughing of the hydrate deposit due to the wetting and weight of the deposit. The addition of antiagglomerant resulted in formation of transportable slurry in the mineral oil system with 30% water cut. The mineral oil and condensate are nonemulsifying, but the pseudo-flow induced in the rocking motion of the cell created shear stabilized emulsion of the liquid phases prior to hydrate formation. Upon hydrate formation onset, the liquid phases appeared to completely phase separate.