Flow AssuranceOil and gas flowlines provide abundant reactants and the necessary pressure and temperature conditions for hydrate stability. In 1934, Hammerschmidt[1] showed that hydrates were causing blockages in natural gas transmission lines.
Figure 1: A Hydrate Blockage Being Removed from a Pig Reciever Since that time, researchers have been developing models such as CSMGem[2] to predict the necessary thermodynamic conditions for hydrate stability. Prediction of the hydrate stability conditions using such models is now possible within experimentally measurable accuracy. Another important problem has been the prediction of how long it would take for a hydrate plug to dissociate once it had formed. A decade of research has allowed the CSMPlug program to make an order-of-magnitude estimate of the dissociation time under three different conditions: one-sided depressurization, two-sided depressurization, and electrical heating[3]. Traditionally hydrate blockages have been prevented by the addition of large quantities of thermodynamic inhibition chemicals such as methanol or mono ethylene glycol to the flowline. These chemicals lower the temperature required for hydrate formation. Recently, the industrial paradigm has been shifting from this time-independent approach of hydrate avoidance towards time-dependent hydrate management. Key to this paradigm shift has been the development and industrial implementation of Low Dosage Hydrate Inhibitors (LDHIs)[4] such as Kinetic Hydrate Inhibitors (KHIs) and Anti-Agglomerants (AAs). Time-dependent phenomena have long been a focus of research at the Center for Hydrate Research. Since 2003, our goal has been to understand the mechanisms for hydrate formation in oil flowlines. To this end, a hydrate kinetics model called CSMHyK has been developed, integrated into the OLGA® multiphase simulator, and tested against three different industrial scale flowloops[5]. The model currently uses an empirical equation for hydrate growth. The fitting parameter was regressed from the Exxon Mobil flowloop for one type of crude oil. John Boxall demonstrated that the same value of this fitting parameter could be applied to the Tulsa University flowloop for four different oils. Further refinement of the CSMHyK model is ongoing: Experiments by John Boxall and David Greaves in a high pressure cell fitted with FBRM and PVM probes are giving new insight into the way that entrained water droplets convert to hydrate agglomerates. High Pressure DSC measurements by Jason Lachance are probing the effect of hydrates on water-in-oil emulsion behavior and emulsion stability. Simon Davies is developing growth models with a more fundamental basis in order to identify the most critical unknown physical parameters. High Pressure Rheometers are allowing Patrick Rensing to understand how hydrate particles affect the flow properties of crude oils. To date, experiments and modeling have focused solely on hydrate formation in oil flowlines. Joe Nicholas is working to understand and model the growth mechanisms in gas flowlines. [1] Hammerschmidt E.G. Formation of Gas Hydrates in Natural Gas Transmission Lines. Ind. Eng. Chem. 1934;26:851. [pdf] |
