Predicting Hydrate Formation and Plugging in a Gas Condensate Subsea Tieback Using a Transient Hydrate Simulation Tool

Abstract

Abstract A case study based on the Norwegian Vega asset is presented to illustrate the application of a transient gas hydrate formation model to a gas condensate subsea pipeline. The study considers hydrate formation during continuous production and subsequent shut-in and restart of fluid flow in the gas condensate subsea tieback. A hydrate kinetics model is coupled with a dynamic multiphase flow simulator to predict when and where hydrate blockages occur during the transient operations of the subsea tieback. The predicted location of hydrate plugs has also been determined to further guide the design of hydrate plug remediation strategies in the field. A previous version of the hydrate kinetics model has been improved to predict hydrate plugging risks in transient (shut-in/restart) conditions. Observations and measurements from multiscale experiments, including high pressure micromechanical force measurements (HP-MMF) and flowloop tests, were incorporated to provide physical basis for the improved model. Mathematical models were implemented to account for surface area of hydrate formation during the shut-in condition in the subsea tieback. Shear stress and cohesive force were modified to account for hydrate agglomeration during restart. The transient hydrate model was then coupled with the one-dimensional multiphase flow simulator to simulate when and where hydrate formed in the gas condensate subsea tieback. The number and location of hydrate blockages were determined based on the simulation results and compared with field data. The simulation assumed phase separation of liquid phases (stratified water/condensate layers) in the pipeline during the shut-in condition. This assumption is based on prior flowloop experiments performed during shut-in conditions for a gas condensate system. The simulation results showed that 10 vol.% of hydrate formed during steady-state continuous production. During production shut-in, as the temperature of the entire pipeline further drops down and enters the hydrate equilibrium region, slightly more hydrate around 3 vol.% formed at the end of shut-in period of two days. Due to the long shut-in time, cohesive force between hydrate particles was assumed to be one order of magnitude higher than the cohesive force with shorter contact time, as demonstrated in prior measurements. With this input, the production restart simulation has demonstrated the presence of two hydrate blockages at 5.6 mile and 6.8 mile (at the downhill inclination of this 6.95 mile pipeline), based on the definition of plugs occurring where there is high liquid holdup and high relative viscosity. This work has provided a new tool to predict hydrate plug formation in a gas condensate field during transient operations. The interpretation of results from simulations in this work could be further fed into a hydrate plug dissociation model to determine hydrate dissociation time and facilitate remediation of hydrate plugs.