A wet-gas pipeline does not deliver a steady stream. Liquid collects in the low spots and then arrives all at once — a slug. The slug catcher is the big vessel, or the bank of big pipes, at the receiving end that swallows the slug, lets the gas go on, and meters the liquid out at a rate the plant can handle. This page explains it — and what an inspector looks at once one is in service.
The two designs ↓Ask a questionGas and liquid do not travel together politely in a long pipeline.
Condensate and water settle in every dip along the line. When enough gas builds up behind a pool, it pushes the whole pool down the pipe as a plug of liquid. Hilly routes and long subsea lines make big ones.
A pig run pushes every drop of liquid in the line ahead of it. That arrives at the receiver as one long slug — often the largest the receiving equipment will ever see, and the case it is usually sized for.
Raising the gas rate sweeps out liquid that had been sitting at the lower rate. Start-ups and shut-ins do the same. The plant sees a surge it did not ask for.
Inlet separators, compressors and treating units are sized for steady flow. A slug floods the separator, trips the compressor and carries liquid where it must not go. The slug catcher stands in front of all of that and takes the hit.
Same job, two shapes. The choice is mostly about how much liquid has to be held and at what pressure.
A horizontal two-phase separator with a very large liquid section. The gas disengages across the top; the liquid pools in the bottom and is let down under level control. Internals — an inlet device, baffles, sometimes cyclonic tubes — improve the split.
Several long, large-diameter pipes ("fingers") laid side by side on a slope between an inlet header and a liquid header. Gas separates in the first stretch and leaves through risers at the high end; liquid runs downhill and is stored in the fingers themselves until it is let down.
A third arrangement, the parking loop, is a length of pipeline looped back on itself that holds the slug and drains it slowly — effectively a one-finger catcher built from line pipe. It is treated as pipeline.
A slug catcher is pressure equipment first and a process unit second. The design basis decides which rulebook it lives under.
Material certs against the design, fit-up and weld inspection on every finger and header, NDT to the code percentage, PWHT charts, hydrotest and the final data package — every hold point in order, signed by the person who actually witnessed it. That is exactly the traveler a slug catcher needs, and it is exactly what AssetSentry™ ITP builds out for the shop. Its built-in templates include an ASME vessel / slug catcher plan.
Big, wet, cyclic and outdoors. Slug catchers collect most of the damage mechanisms a gas plant has.
A vessel-type unit is an API 510 vessel. A finger-type unit is inspected under 510 or 570 according to how it was designed and registered — check the record before you plan the inspection, not after.
Water and CO₂ or H₂S lie in the bottom of every finger and the low end of every drum. Thickness at the 6 o'clock position, at the liquid end and at the headers is the number that decides remaining life. Measure it on a grid, not at one spot.
Cooling wet gas condenses on the crown of the pipe. Top-of-line attack is easy to miss from the outside and shows up as pitting at 12 o'clock — UT the crown as well as the bottom.
Sand, scale and black powder arrive with the slug at velocity. The inlet header, the first fitting on each finger and any inlet device take the wear. Look for wall loss opposite the flow.
Every slug is a moving mass. Support welds, saddle attachments, small-bore connections and riser tie-ins see the cycles. MT or PT the toes; check the supports for movement, corrosion under the saddle and lost slope.
Long insulated or coated runs at low elevation are corrosion-under-insulation territory. Strip and look at the low points, the supports and anywhere water gets in and stays.
Inlet devices, baffles, vortex breakers and any cyclonic internals get erosion, fouling and cracked attachment welds. Open the manway and check them; carryover downstream is the sign they are failing.
Clean out the solids, UT the low points and crown on a grid, RT or UT the field welds you have never looked at, MT the attachments, and put the readings on the equipment record so the corrosion rate is real, not assumed.
t-min from the design code, corrosion rate from measured thickness over time, remaining life and the next interval from those — done from the readings, on the record, checkable by the next person.
About slug catchers, about inspecting one, or about this name. It goes privately to the owner of this site.