Predicting Hydrate Plug Movement During Subsea Flowline Depressurization Operations
Authors: Xiao J.J. , Shoup George , Hatton Greg , Kruka Veet 
Published: October 2008

Abstract
Hydrate blockage formation can occur in multiphase pipelines operated at high pressure and low temperature conditions. One method frequently used to decompose or dissociate a hydrate plug is to depressurize the pipeline. This operation is best done from both sides of the blockage while maintaining pressure balance across the plug at all times. However, for subsea deepwater flowlines, the wellhead side of the flowline may not be accessible. Depressurization may be done from the host platform side alone. A major concern in this operation is how fast a plug can accelerate after it breaks free due to the pressure imbalance. This paper shows how a transient multiphase flow simulator, OLGA, can be used to simulate hydrate plug movements. Simulations show that plug movements are influenced by a number of parameters including pressure differential across a plug, plug size, plug location, and the presence of oil or condensate. OLGA simulations were used to design field depressurization experiments carried out by Deepstar. Calculated plug velocities compare well with field data. Subsea flowline hydrate blockage dissociation operations pose severe safety concerns. An engineering approach to estimate the impact of such operations is presented in this paper. The method can be used to establish guidelines for field operations.

Introduction
Natural gas hydrates are ice-like solids formed when molecules of light hydrocarbons (Cl-C4), CO2, N2 and H2S contact water molecules at elevated pressures and reduced temperatures. For a given fluid composition, thermodynamic models can be used to predict the hydrate formation region, as indicated in Fig. I. Hydrates can exist at temperatures greater than the water freezing point of 32°F at high pressures. For the case shown in Fig. I, at 1000 psia, hydrates can exist at temperatures as high as 64°F. In oil and gas production systems, formation and agglomeration of hydrate particles can restrict flow and eventually plug pipelines and facilities, causing significant downtime and loss of production. Deepwater pipelines are particularly prone to hydrate formation due to the cold environment. Hydrate control is the most critical flow assurance issue every deepwater project must address. The key is to prevent hydrate formation. This can be accomplished by a number of methods including the removal of water or continuous injection of inhibitors. Three types of available inhibitors are thermodynamic inhibitors (methanol or glycol), kinetic inhibitors (KI) and anti-agglomerate (AA) inhibitors. Heat retention through the use of vacuum insulated tubing and pipe-in-pipe flowline insulation can also be used to keep the fluid temperature above the hydrate formation temperature. Active heating with flowline bundles is another option to consider. For a design to be valid in any project, the characteristics of the produced fluid and the reservoir performance must be known. Accurate phase behavior prediction, steady-state and transient flow calculations, and heat transfer modeling of the entire production system are required. For a system designed with adequate hydrate protection through either chemical injection or insulation, hydrate blockages can still occur when the injection system malfunctions or flow transients (start-up or shut-in) occur. For example, during an emergence shut-down, flowline fluids can drop to the ambient cold water temperature in a matter of hours even with insulation.