I have a subsea gas well with reasonable amount of water content. Tieback distance to the host platform is about 5 miles, and it is an 8" pipeline. Initial calculations  show that there'll be slugging. So my flow assurance engineer advises periodical pigging operation.

My question is, is there any other slug mitigation method as effective or even better than pigging? As much as possible I don't want to do subsea pigging, it is  costly.

Pigging does not prevent slugging, pigging causes slugging as the pigs/spheres push accumulated liquids ahead of the them!  The only difference is that when you launch a pig, you have an idea of when the slug will arrive and can prepare for it.  Otherwise, slugs arrive when the physis of the pipeline decide its no longer possible to leave the accumulated liquids undisturbed and pick them up and blow them along downstream all at once.

You can try to keep flow velocities high enough such that liquids are sweept along and the slugging flow regime is avoided.  Slugging is more prevelant at low velocities.  The flow regeime also depends on ratio of gas to liquid flowrates and slope of the pipeline, so it still may not be possible to avoid, but you might be able to minimize it.  

HUGE anything offshore is expensive.  Get a quote on renting the deck space from the producer.  And ...I don't exactl think you'd want to pay for the trip out once a week to load the spheres either.  Depending on the distance, that can take a workboat 48 hours to get there and 48 to get back (in good weather) + associated dock time (some weather or breakdown repair downtime), and you're basically tying up a workboat on that job alone.

He may be referring to "water slugs". Water as a 3. phase (assuming that even though its a "gas well" what comes out is gas, condensate and water"-ball valve) will have a tendency to accumulate  and the arrive to the HP separator/slug catcher and then "fill up" the water separation section and cause the water to continue to 2. stage sep etc. The effect can be reduced by pigging. I think the recommendation (seen from this point of view) is sound. Your flow assurance eng. may also be able to tell you how big the water separation section must be if you dont pig?

Usually its a gas well,  that also produces associated water as well as some quantities of Gas condensates.  Slugging would then be the water and the condensates that tend to collect in low points or at the base of a riser to the next platform until they reduce the gas flow to the point where pressure builds and eventually  increases pressure and velocity enough to sweep the liquids out at once.

Whether he needs a vessel "slug catcher" or an extended dead-end pipeline segment "drip", increase velocities or implement regular pigging depends on the ratio of the quantity of liquids produced to that of gas and the resultant flow regime.  The problem with large vessels located upstream and close to the well, so that pigging the pipelines can be avoided, is that offshore space is very costly for placing large mostly empty vessels that can weigh a lot if they do happen to get full.  Additionally, a means to empty the vessel to a boat must also be employed.  Again not cheap.  If velocities can't be keep high enough to continuously sweep the line, the standard solution is to pig the liquids all the way back to the beach in a 2-phase flow pipeline to where a large vessel can be economically positioned onshore.

MORE NEWS