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mtariq80
03-15-2013, 01:55 AM
Hi Everyone,
I am working on Gas condensate pipelines and need support to solve one problem.
Brief description:- The 12” pipeline system has lot of NGL in the flowing gas stream, and Pipesim is predicting dropout of the liquid. The gas stream is saturated leaving the 2-phase separator at a pressure of ~ 50-70 psig, and the line goes underground and cools, causing liquid dropout. Around 300bbl liquid hold up is calculated by Pipesim.
Objective is to size the slug catcher. What pigging frequency should be considered? How fast this liquid will accumulate? What will basis of slug catcher design? How much margin shall be considered in slug volume as slug calculated by dynamic simulation would be more? Can anyone enlighten on these?
Regards,
MTQ

07-26-2013, 12:46 PM
Hi MTQ,

This will depend on operating conditions and pipe design as well as pipeline safety:
If the gas contains high H2S (sour gas) ,then normally following in any shutdown of the system you will need to depressurize the line and purge with sweet gas to eliminate corrosion and risk of toxic gas release. I remember of sour gas gathering flowlines where the pipeline was automatically pigged and purged by sweet gas when ever the pipe was shut down for any reason. Remember that when the pipe is out of service the condensation occurs and the corrosion at low points where corrosive liquid accumulate is severe and may lead to severe pitting corrosion.
- if the gas is sweet (no H2S) the pigging frequency depends on pipeline design. You should design the pipeline not to operate the line at a velocity lower than say 10 ft/sec to limit build up of what is called the 'static hold up " of the pipeline. Pls. note that contrary to dynamic hold up (which is the liquid comes in and goes out of the pipe), the static hold up depends on design of the pipe (diameter and normally gas superficial velocity). In the case that the static hold up is increasing within a period so that at the end of a specific time interval the pipeline pressure drop is no longer tolerable (decreased pipeline efficiency) then that will be the time to launch the pig. Other case where dictate the pigging are the maintenance period or application of batchwise corrosion inhibitors etc. You should also treat the onshore pipeline and offshore pipeline in different way as the hold up for deep offshore lines (especially risers) could lead to severe slugging.

To answer your second question (How fast would be the slug accumulation ). The slug will be accumulated to its maximum during transient state at the time of start up. It will be increased till the pipeline operation will become steady state (what comes in , goes out). At this time you will have a stable static hold up in the line plus the dynamic hold up which will not vary. The other cases which cause un-stability of the hold up are Ramp-up, pigging etc which shall be dealt separately. For all the above case you might need to run pipeline dynamic simulators to predict the time and the slug/ liquid hold up time (remember to use the proper model to come up with more or less accurate results).

There are some guidelines in the internet what type of slug catcher (finger type, vessel type (vertical or horizontal) or some other proprietary design to be used. In your case where the slug size is limited a vessel type SC is more feasible as it could require limited plot size and equipment cost. Remember to allocate the slug volume when you are sizing the SC. Follow the design guideline for conventional separators for normal separation of gas and liquid but allocate more volume for the slug. Design of finger type slug catcher is more sophisticated and normally Engineering companies have GL or software to size pipe slug catchers (One of the GL are also also available from Operating companies like Shell DEP and PETRONAS which is more or less the same as SHELL DEP. However you may do it by yourself using these GL with consultation of some piping design engineers. Remember that when you design Pipe type SC there are some piping engineering rules which you might consider together with mechanical process design of SC. eg the standard pipe length are SRL,or DRL which is 6 meters or 12 meters. To minimize number of field welds you need to consider these limitations , Other things which might affect the size (especially the separation area, risers, downcomers etc. are standard fitting sizes ) especially for large size piping.

And your final question (the margin): actually with your case where the SC will be small in size you can allocate good fat in your design however this depends on your expertise to use the proper model applicable for your case plus the pipeline profile, accuracy of the input data e.g. gas composition etc. Also a good credit can be given to the liquid processing unit capacity downstream of slug catcher so that you can take the benefit to divert the liquid inside the SC while it is being accumulated....

seddik-b
08-11-2013, 04:02 PM
For sulugcatcher sizing you need to conduct transient studies where you have to determine you pipeline envelope, the turndown , start-up and ramp-up cases and will govern the slug catcher sizing.
V-sulg catacher = VSurge - Vdrainage . for more information you can refer to DEP-31.40.10.12.

Hope this will help

Seddik