Finger-type and vessel-type slug catchers engineered to absorb sudden surges of liquid arriving from multiphase pipelines — protecting downstream separation and processing equipment from overload and shutdown.
Multiphase gas-liquid pipelines rarely deliver a steady, predictable mixture to the receiving facility. Terrain changes, pipeline pigging operations, and ordinary hydrodynamic instability inside the line all generate slugs — large surges of liquid that can arrive many times larger than the pipeline's average liquid holdup. A slug catcher is the static equipment, in vessel or piping-network form, sized to absorb the largest anticipated slug and release it to downstream separation and storage at a controlled, metered rate.
Fintelius sizes every slug catcher against transient pipeline simulation — terrain-induced slugging, pigging ramp-up volumes, and worst-case operating scenarios — before selecting a finger-type, vessel-type, or hybrid configuration to match the volume, pressure, and plot-space constraints of the site.
A slug catcher has to be sized for the worst credible combination of these mechanisms, not just steady-state flow.
Liquid accumulates in low points along an undulating pipeline profile and is periodically swept forward in large surges as gas velocity builds.
A pipeline pig sweeps accumulated liquid ahead of it, delivering the pipeline's entire liquid inventory as a single large slug on arrival.
Normal multiphase flow instability generates slugs continuously during steady operation, at a scale the slug catcher must absorb without upset.
Every unit follows the same disciplined path through design and fabrication, whatever its configuration.
Pipeline profile, pigging frequency, and ramp-up rate are modeled to estimate the largest anticipated slug volume.
Finger-type, vessel-type, or hybrid design is selected against required volume, pressure rating, and available plot space.
Large-diameter pipe manifolds or separator shells are rolled, welded, and fitted with gas risers, equalization lines, and internals.
All welds are radiographed and ultrasonically tested; thick sections undergo post-weld heat treatment where required.
The complete unit is hydrostatically tested, coated, and prepared for shipment as a skid or in sections for field erection.
A horizontal or vertical two-phase separation vessel — vertical configurations offer the highest separation efficiency, most economical for slug volumes under roughly 100 m³.
Large-diameter pipes arranged in parallel “fingers,” each with a gas/liquid separation section, an intermediate zone, and dedicated storage volume — the economical choice for high-pressure, high-volume applications.
Combines the separation efficiency of a vessel-type unit with the large storage capacity of a finger-type harp — a compromise configuration where both efficiency and volume matter.
Small design decisions compound into large differences in flooding behavior, foundation cost, and installed footprint.
An even number of parallel fingers balances flow distribution — odd counts commonly cause uneven loading and localized flooding in individual fingers.
Finger count and diameter are set from gas flow rate (actual cubic feet per second), with finger length then sized to the required storage volume.
Modern finger-type layouts can achieve roughly a 1:100 slope versus the 7:100 slope of older stratified designs — substantially reducing installation height and foundation cost.
Adequate straight-run inlet piping (on the order of 5 pipe diameters) promotes stratified flow entering the manifold for even distribution across fingers.
Riser and equalization piping balance gas pressure across all fingers, preventing one finger from over- or under-filling relative to the others.
High-strength carbon steel manifolds (to MSS-SP-75) suit non-corrosive streams; corrosion-resistant alloys are specified where CO₂ or H₂S content demands it.
Slug storage volume held between normal and high liquid level switches, with a weir maintaining predictable oil-water segregation.
Modular finger arrangements allow additional storage fingers to be added later without downtime or interruption to production.
Prevents oil-phase overflow into the water draw section during high-level operation.
Restricts oil carryover into water-draw piping, protecting downstream water treatment systems from hydrocarbon contamination.
Manifold inlet design accommodates pig arrival directly ahead of the slug catcher, managing the pipeline's full liquid inventory on pig passage.
Weld integrity verification and full-pressure hydrostatic testing prior to dispatch, per the governing piping or vessel code.
Buffering multiphase flowline slugging at the wellhead or gathering manifold ahead of primary separation.
Protecting gathering and transmission pipeline receiving facilities from pigging and terrain-induced slug arrivals.
Managing feedstock slugging ahead of downstream process units to prevent overload and unplanned shutdown.
Absorbing slug volumes generated by elevation changes along pipeline routes with fluctuating terrain profiles.
Stabilizing inlet flow ahead of dehydration, dew point control, and compression equipment.
Receiving the full pipeline liquid inventory swept ahead of a pig without upsetting downstream processing.