This paper addresses hydrate mitigation in the presence of damaged insulation on production well jumpers in a Deepwater Field. The damage severity was sufficient to potentially require all well jumpers be replaced. The analysis described in the paper was performed to assess the viability of modifying the hydrate mitigation strategy instead of replacing the well jumpers or performing insitu repairs to the insulation. This work assesses the impact that insulation cracks have on well jumper cooldown time for Deepwater Operations. For this assessment, the estimated exposed surface area in the worst jumper did not exceed 4%. This is based on a field survey conducted in the fourth quarter of 2008. A safety factor of approximately two times the estimated exposed area was used to calculate the cooldown time. To represent the worst-case scenario, cooldown times were calculated assuming that the jumper would be gas-filled. Moreover, two extreme cases under forced convection heat transfer were assumed: first, that the fluid inside the jumper would be fully mixed and second, that stagnant fluid would be inside the jumper. Analysis by ExxonMobil indicated hydrate formation for the stagnant fluid case was not sufficient to form a blockage requiring hydrate remediation. For the fully mixed case, the shortest cooldown time observed was 3 hours for the worst damaged jumper. Based on these results, methanol displacement of the jumpers before cooldown time is exceeded, is recommended to avoid hydrate formation. In case of formation of a hydrate plug, depressurization followed by methanol displacement should be performed to dissociate the hydrate plug.


The subsea architecture for this Deepwater Field consists of a number of subsea production wells that are tied into several subsea production manifolds via well jumpers. The production manifolds are connected to subsea flowlines and risers, which transport the production fluids to a Floating Production, Storage, and Offloading (FPSO) vessel. The wellheads, well jumpers, production manifolds, flowline, riser, and jumpers are sufficiently insulated such that production fluid temperature during normal operating conditions is maintained above the hydrate formation temperature (HFT) and the wax appearance temperature (WAT). During an unplanned shutdown, the insulation on the subsea equipment is sufficient to allow for an 8 hour time period for operations to correct the cause of the shutdown. This time period is known as the decision time. At the end of the decision time period, the flowline, risers, production manifolds, and associated jumpers are displaced by circulating dead crude through the production system. The subsea architecture is developed such that dead crude from the FPSO can becirculated down one production riser through production manifolds and back to the FPSO via a second flowline and up that flowline's corresponding riser. The cooldown time provided by the insulation is sufficient to allow for the decision time and displacement time before the production fluids cool to HFT. The wellhead and well jumpers must be mitigated before decision time in order to prevent hydrate formation in the wellheads and well jumpers. The hydrate mitigation of the wellheads and well jumpers consists of displacing them with methanol. The methanol is pumped through tubes in a service umbilical line from the FPSO to the wellheads and well jumpers. This process begins at the fourth hour of the shut-in (light touch time) and is completed by the eighth hour of the shut-in (decision time).

This content is only available via PDF.
You can access this article if you purchase or spend a download.