Slug catcher

If several widely spaced fields are feeding a single gathering and treatment centre it is common to perform primary separation of gas and oil (and possibly water) in the field. A field station may include a simple slug catcher, temporary storage tanks and pumps for getting the separated fluids to the main gathering and treatment centre. 

When raw natural gas comes to the surface it is often saturated with heavier hquids. Should the gas be cooled, in an undersea-pipeline for instance, then some of the heavier components condense to form a slug of liquid in the pipehne. These liquids are removed in a series of large pipes known as a slug catcher - Figure 3.1. 

Two-phase flow often presents design and operational problems not associated with liquid or gas flow. For example, several different flow patterns may exist along the pipeline. Frictional pressure losses are more difficult to estimate, and in the case of a cross-country pipeline, a terrain profile is necessary to predict pressure drops due to elevation changes. The downstream end of a pipeline often requires a separator to separate the liquid and vapor phases, and a slug catcher may be required to remove liquid slugs. 

In Plant 3 exposure monitoring efforts were focused on three routine maintenance events including inlet gas filter change out (downstream from the slug catcher), pipeline scrapper receiving event, area monitoring around the evaporation ponds. 

A simplified model was built of the onshore facilities. This model represents the main pieces of onshore equipment and represents all important throughput and capacity constraints. Constraints modelled are slug catcher level, slug catcher pressure, condensate separator level, pressure in condensate separators, product gas demand, coalescer interface level, level in storage tanks for condensate, produced water, MEG and the unseparated MEG-water mixture and the capacity in MEG separation and condensate stabilisation. 

A properly designed feed gas inlet separator and filter should be provided. A feed gas coalescer should be considered for feed gas streams contaminated with compressor lubricating oil and other finely dispersed aerosols (Ball and Veldman, 1991 Pauley, 1991). A properly sized slug catcher should be provided if slugs can accumulate in the feed gas line. 

A slug catcher 60 m long, having a 0.5 m diameter, and at a 2° angle with the horizontal plane has a liquid-filled length of 5 m as shown in Figure 1.16. Calculate the filled volume of the slug catcher. 

The distance from the bottom corner of the slug catcher up to the liquid level (h) can be calculated ash = 5 tan2° = 0.175 m. This is less than the radius of the pipe. For this condition, the top view of the surface will always look like a half-ellipse. 

The vessel.exe program has been developed to estimate the total and filled-liq-uid volumes and dry and wet surface areas for horizontal, vertical, and inclined (e.g., slug catcher) vessels. For horizontal and vertical vessels, the program also calculates the weight of the material and the hydro test weight. 

Dished ends have not been used in this calculation. In general, for the slug-catcher t5q e of calculations, the impact of dished ends is negligible. 

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