bouk,
On the basis that you mention compressor wash or low gas demand as the reason the well is shut in, I assume you are talking about re-starting a gas well after a long term shut in.
It is important to know the context of the well in question is it a subsea or a 'dry' platform well. In the former is it part of a collection of subsea wells (ie tied into a subsea manifold) or is it a single well tie-back or daisy-chain?
I hazard a guess that it is subsea on the basis that you mention seabed temperatures.
You are correct in being concerned about 'packing' a subsea flowline at seabed temperatures as the risk of hydrate formation is high at high pressures and low temperatures.
The only way this scenario is workable (ie maintaining pressure in the line during shut down) is if the line was suitably inhibited (using Methanol, ethanol, MEG etc) against hydrate formation BEFORE it was shut in.
If continuous inhibition is used during normal operation it is likely that this is the case, however careful checks need to be applied to determine any 'top-up' inhibitor requirements for shut in AND Re-start operations.
Existing Operating procedures should be available to provide with clear instructions and dosage rates to apply for planned (and unplanned) shutdowns.
As each development is different it is difficult to provide you with a general guidance as to what to do in each circumstance as there are many variables to consider. That's why i point you in the direction of the operating procedures if they exist, if they don't exist then a significant amount of engineering and simulation work is required to produce these procedures (which then need to be risk assessed / HAZOP'ed according to operators requirements). Even summarising this work without any specific details would take longer than appropriate in a forum such as this.
Regards
NMcC
Nick McCarthy
Flow Assurance Consultant
