Pipeline Slug Mitigation

[suraiya]

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.

 

[BigInch]

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 physics 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.

BigInch-born in the trenches.

http://virtualpipeline.spaces.msn.com

 

[dcasto]

Aw, one of those pesky cost vs benefits questions. Other than transportation of balls to the launcher, how is off shore more expensive than on shore? You can put an automated launcher at the off shore launcher and reload it once a week.

Put a HUGE slug catcher on shore.

 

[BigInch]

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.

BigInch-born in the trenches.

http://virtualpipeline.spaces.msn.com

 

[dcasto]

There are only two ways to increse velocity, more gas, lower pressure. So drill more HUGE wells or buy a HUGE compressor.

 

[BigInch]

Smaller pipe diameters or increased pressures will also increase velocity.

BigInch-born in the trenches.

http://virtualpipeline.spaces.msn.com

 

[sterl]

Separate the water out and pipe and pump it back independently or steam it off...
I know of one water hose connected to a floating diaphragm inertia pump....Wave action pumps the water out of a collector.

 

[MortenA]

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") 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?

Best regards

Morten

 

[pipehead]

suraiya, If you elect to continue with more pigging, add a slog cather. You can cut the cost in half if you go with a slug catcher made of fittings instead of one made as a vessel.

 

[BigInch]

Usually its a gas well, Natural Gas 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.

BigInch-born in the trenches.

http://virtualpipeline.spaces.msn.com

 

[MortenA]

Biginch

Im not so sure (as i stated before) that the essence of the problems are "slugs".

The problem in this case _could_ be that on occation a fairly large water slug may come along.

But im not sure and the the original poster has not replied back since the first post.

Best regards

Morten

 

[BigInch]

As I'm sure you know, for the most part wells generally produce at a constant stream at a particular gas to liquid ratio, so it would not be very likely that the slugs originate downhole. Usually its the pipeline flowrate at a velocity that allows liquid hold up that causes slugging of liquids at the downstream facilities. The fact that pigging has already been proposed is even a further indication that this is most likely the cause of the expected problem. As per above, if the gas to liquid ratio would allow transport without slugging, no pigging would be needed at all.

I took the OP statement, "Initial calculations show that there'll be slugging." as the problem for which the solution recommended by the flow assurance engineer was pigging the line. Even high water to gas ratios are not a transport problem, if both water and gas can both be moved at uniform flowrates without liquid hold-up. Its the slugging that requires the extra handling equipment to accomodate it.

In any case, you are right in that we do seem to have much more interest in beating this apparent dead horse than the OP....

BigInch-born in the trenches.

http://virtualpipeline.spaces.msn.com

 

[MortenA]

The water rate may be constant - but due to pipeline low and high points water may accumulate and the come as a slug. This slug will "usually" not be significantly larger (or smaller) than the normal extreems - but it will be almost only water. This could mean that the water separation compartment of the first stage separator/slug catcher would be too small.

This is common in offshore multiphase pipelines where the multiphase distance may be longer than on-shore and the pipeline normally follows the terrain.

Slugging in it self can be controlled to some degree by control of backpressure that is what multiphase simulation can help to investigate.

Since the original poster has not reverted i dont know if my suspicion is correct.

Best regards

Morten

 

[BigInch]

I think it depends on the well. I've had wells in the GOM that produced quantities of gas condensates that at first ran in the mist flow regime, only with a little water, until the wells aged and began to significantly increase water content, such that we had to install automatic sphere launchers and convert the entire 200 mile pipeline system (5 platforms) to a "real" 2-phase system. In some pipeline segments, we had uniform g/l ratio wave flow regimes and in others towards the beach where liquid content ratios increased even more so with the older wells and all condensates had dropped out, we had large slug flows.

The pipeline gas to liquid ratios, velocities and pipeline profile can combine to make about 5 different flow conditions, sometimes in the same pipeline system. But sometimes you don't need a slug catcher, just a separator system, at least until you start making slugs somewhere.

BigInch-born in the trenches.

http://virtualpipeline.spaces.msn.com

 

[DBenson78]

An alternative way to look at this would be to detect the approach of a naturally occurring slug utilising density meters (slug monitor) with set trigger points and then control the slugs impact on the downstream system by controlling the stroke of a choke valve.

 

[BigInch]

Still doesn't catch the slug, which is usually the end objective.

BigInch-born in the trenches.

http://virtualpipeline.spaces.msn.com