An Evaluation of Risk of Hydrate Formation at the Top of a Pipeline
Water condensation and/or hydrate formation at the top of pipelines are serious design/operation considerations in pipelines with stratified flow. Water condensation could result in top-of-the-line corrosion, particularly in sour-gas systems. Hydrate formation is believed to be another serious risk if the inhibitor in the aqueous phase cannot protect against hydrate formation at the top of the pipeline.
In this paper, we report the results of some preliminary tests conducted in a new experimental setup constructed for investigating gas-hydrate risks in various operational scenarios (e.g., top of pipelines, deadlegs/jumpers, startups, shutdowns). The reported three series of tests conducted in the new experimental setup address hydrate-formation risks at the top of pipelines or deadlegs caused by temperature gradient, and the risk of hydrate formation in the gas phase in the presence of kinetic hydrate inhibitors (KHIs) during pipeline cool down and startup. The results provide a better evaluation of the risks involved in various systems and provide guidelines for avoiding the associated problems.
Gas-hydrate management is considered to be the most critical aspect of flow-assurance-design strategies because hydrate plugs can have major safety and economic impacts on flowline operation and can stop production completely for several days or months, and in the worst case, can result in pipeline abandonment. Hydrate-plug dissociation and remediation can be a costly and time-consuming process and can result in restrictions on system operations. The issues of hydrate prevention and (if needed) remediation are therefore very important. Current methods for avoiding gas-hydrate problems are generally based on one or a combination of the following three techniques: (1) injection of thermodynamic inhibitors (e.g., methanol, ethanol, monoethylene glycol) to prevent hydrate formation, (2) use of KHIs to sufficiently delay hydrate nucleation/growth, and (3) maintaining pipeline operating conditions outside the hydrate-stability zone (HSZ) by removing one of the elements required for hydrate formation. Currently, the most common hydrate-flow-assurance strategy is to rely on the injection of organic inhibitors (e.g., methanol, monoethylene glycol) or KHIs to inhibit hydrate formation in gas production and transportation. The current industry practice for hydrate prevention by chemical methods is to inject hydrate inhibitors at the upstream end of pipelines on the basis of the calculated/measured hydrate-phase boundary, water cut, worst-case pressure and temperature conditions, and the possible inhibitor loss to nonaqueous phases.
Executing Offshore Projects More Efficiently
Offshore project execution enhancement ideas are highlighted for debottlenecking, gas-hydrate-induced pipeline vibration, and the design of subsea systems for efficient startup.
Hydrate-Induced Vibration in an Offshore Pipeline
A computational fluid dynamics model is proposed to analyze the effect of hydrate flow in pipelines using multiphase-flow-modeling techniques. The results will identify the cause of pipeline failure, regions of maximum stress in the pipeline, and plastic deformation of the pipeline.
PHMSA Tags Construction Damage as Cause of Keystone Pipeline Spill
Weights used in the original construction of TransCanada’s Keystone Pipeline in South Dakota were identified as a preliminary cause of the failure that resulted in a 210,000-gal spill in November.
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