(29g) Modelling and Comparative Assessment of Hydrate Inhibition Strategies for Arctic Subsea Tiebacks

Ensuring the uninterrupted flow of produced reservoir fluids from the wellhead to processing facilities is critical to the success and cost-effectiveness of production systems, particularly in Arctic conditions. The extreme operating environment presents significant technical challenges and high development and operational costs, necessitating a flow assurance assessment to determine the most reliable, cost-effective, and environmentally sustainable solution for gas hydrate inhibition. In this study, the PIPESIM multiphase flow simulator was used to model the thermal-hydraulic behavior of fluid along a 120 km subsea tieback from the Ormen Lange gas field to an onshore processing facility. Three industry-practiced approaches for gas hydrate mitigation were evaluated: thermal insulation, direct electric heating (DEH), and thermodynamic chemical inhibitors (methanol and mono-ethylene glycol (MEG)). The hydrate formation temperature (HFT) was determined to be 21°C at 220 bar, and the optimal pipeline diameter for stable production was found to be 30 inches (0.762 m). The results indicate that thermal insulation using polypropylene material (0.21 W/m/K thermal conductivity) was feasible but unreliable for transient conditions such as prolonged shut-ins due to the low thermal mass of gas and high heat loss to the ice-chilled environment. DEH, implemented via section heating at four locations, successfully maintained the pipeline temperature above the hydrate stability limit, requiring 195 megawatts of power at a daily operating cost of $196,802 USD. Conversely, thermodynamic inhibitors proved effective, with 27.7 wt.% methanol injection suppressing the HFT to 8°C, and 45.3 wt.% MEG injection lowering it further to 2°C. However, the associated capital costs of $878 million for MEG and $328 million for methanol, along with operating costs of $292 million and $449 million per year, respectively, raise economic concerns. Overall, the study revealed that all three approaches are technically viable for Arctic gas hydrate management, but each has distinct advantages and limitations. While thermal insulation offers a lower one-time investment ($126 million), its unreliability under transient conditions makes it less practical. Thermodynamic inhibitors are effective but come with high chemical consumption and environmental concerns. In contrast, DEH emerges as the most reliable, cost-effective, and environmentally friendly solution, making it the optimal strategy for hydrate inhibition in Arctic gas fields.

Keywords: Gas hydrate, subsea completion, Arctic pipeline, chemical inhibitors, thermal insulation, direct electric heating, multiphase flow simulation