This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215580, “Safe and Successful Gas Hydrate Plug Remediation in Vega Asset—Norwegian Gas Condensate Subsea Production System,” by Seetharaman Navaneetha Kannan, SPE, Wintershall Dea and Colorado School of Mines, and Magne Torsvik and Luis Ugueto, Wintershall Dea, et al. The paper has not been peer reviewed.
Gas hydrate plugs in subsea flowlines create complex challenges in plug-remediation operations and can result in significant operational expenditures. This work chronicles a series of operational activities in detection of a hydrate blockage, modeling assessment, and safe and successful plug-remediation efforts in a 12-in. inner diameter (ID) flowline in Vega, a Norwegian Sea gas-condensate subsea asset. The operational experiences from hydrate-plug detection and melting, as well as modeling activities, provide valuable input for future hydrate-remediation operations.
Field layout consists of three daisy-chained subsea templates [South (S), Central (C), and North (N)]. At production startup in 2010, all templates housed two wells each. In 2021 and 2022, an infill well campaign took place, with one new well added to both the South and Central templates. The wells are named after the templates to which they are added [i.e., South includes Wells S1, S2, and S3 (Fig. 1)]. One multiphase flowline connects the three templates with, initially, 12-in. ID line from South to Central and Central to North and a 14-in. ID export line to the host. The backbone of the flow-assurance philosophy is continuous injection of monoethylene glycol (MEG) to the templates, with reclamation on the host platform.
Continuous MEG injection is used to ensure operation outside of the hydrate-formation window, even under shut-in conditions. Therefore, a 90:10 MEG/water mix is injected into each template’s manifold. The injection volumes are aimed to ensure an approximate MEG concentration of 50% in the produced aqueous fluids to the topsides.
Vega was initially designed to accommodate limited volumes of formation water only. Subsequently, formation-water-producing wells would be choked back gradually, worked over, or shut in. The design included only minor contingencies of a few cubic meters of saline water in the system.
The initial breakthrough of formation water in the S wells occurred well within the boundaries of the system. Because of the minor influx observed, the original MEG strategy was maintained. However, as water production increased, the well had to be choked down to remain within the limit of the MEG reclamation unit. At one point, the primary source of water from the well shifted from condensed water to formation water, but the actual MEG injection rates were not adjusted to address this new situation. Because of the subsea flowmeter accuracy on the still very low formation-water rates, this change was not picked up in time. This created a completely new operational scenario for which the original design had not accounted without considering the increased risk of hydrates in the field.
