Scrubber

Key Takeaways

• Compressor suction scrubber design is critical for reciprocating and centrifugal compressor reliability because liquid ingestion by either type of compressor causes immediate and severe mechanical damage: in a reciprocating compressor, liquid ingestion during the compression stroke creates a hydraulic hammer effect (the incompressible liquid cannot be compressed like gas, causing the pressure to spike rapidly to the point where the compressor valve fails or the connecting rod bends or fractures), while in a centrifugal compressor, liquid droplets entering the impeller erode the impeller vanes and cause vibration and imbalance that can destroy the impeller in a short time; the suction scrubber is designed with a residence time (the time the gas spends in the vessel) sufficient to allow gravity settling of droplets above approximately 200 to 500 microns in diameter (depending on the vessel size and gas velocity), supplemented by a wire mesh or vane mist extractor at the gas outlet to remove finer droplets below the gravity settling limit; the suction scrubber is typically sized using the Souders-Brown equation for the mist extractor section and an L/D ratio of 3:1 to 5:1 (length-to-diameter ratio of the cylindrical vessel) to provide adequate gas residence time for gravity separation; the liquid level in the suction scrubber sump is monitored by level instruments (float-type or differential pressure level indicators) and controlled by automated dump valves that discharge accumulated liquid to a low-pressure collection vessel or drain system before the liquid level rises high enough to be re-entrained into the gas outlet and carried over to the compressor.
• Pipeline scrubbers installed at compressor stations and pig-trap outlets remove the accumulated pipeline liquids (water and condensate that have dropped out of the gas stream as the gas cools and pressure drops along the pipeline) before they enter the compressor or metering station: in a long-distance natural gas transmission pipeline, the gas entering the pipeline at the inlet conditions (typically at or above the hydrocarbon dew point at line pressure and temperature) gradually loses temperature as it flows through the buried pipeline, and when the pipeline temperature drops below the hydrocarbon or water dew point at the prevailing pressure, condensate and water drop out of the gas and accumulate in low points in the pipeline profile; pipeline pigging (the periodic passage of a cylindrical pig device through the pipeline driven by gas pressure) sweeps these accumulated liquids forward and delivers them as a liquid slug to the receiving pig trap, from which the scrubber separates the gas and liquid before the gas passes on to the compressor or meter; the slug volume delivered by a pig run depends on the pipeline geometry, the gas composition, and the time since the last pig run, and the scrubber must have sufficient liquid handling capacity (sump volume and dump valve flow rate) to process the maximum expected pig slug without backing up liquid into the gas outlet of the scrubber.
• Acid gas scrubbers in sweetening and sulfur recovery plants remove hydrogen sulfide (H2S) and carbon dioxide (CO2) from sour natural gas using liquid-phase chemical absorption, where the sour gas is contacted with an amine solvent (monoethanolamine, diethanolamine, or methyldiethanolamine) in a countercurrent absorption column, and then the rich amine loaded with H2S and CO2 is regenerated in a stripper to release the acid gases for further processing (conversion to elemental sulfur in a Claus sulfur recovery unit or injection for underground sequestration): while the amine absorber itself is technically a scrubber (it removes acid gas contaminants from the gas stream), the term "scrubber" in the context of amine treating more specifically refers to the supplementary vessels installed upstream of the amine absorber (to remove liquids and solids that would cause foaming in the amine solution) and downstream of the amine absorber (to remove any amine carryover from the treated gas before it enters the downstream system); amine foaming in the absorption column (caused by liquid hydrocarbons, glycol contamination, scale inhibitor residues, or mechanical seal lubricant entering with the gas feed) is one of the primary operational upsets in gas treating plants, causing reduced treating capacity and amine losses, and is prevented by proper design and operation of the inlet scrubber upstream of the absorber.
• Wellhead scrubbers for gas well production collect liquids produced with the formation gas at the wellhead, preventing the liquids from entering the gas gathering pipeline and accumulating in pipeline low spots where they create slug flow that interferes with gas metering accuracy and pipeline pressure management: the wellhead scrubber (also called a well test separator or wellsite separator in test configurations) is a compact vertical or horizontal vessel installed at the wellhead to separate gas from the associated liquids (formation water, condensate, and hydraulic fracturing flowback water in the early production period) before the gas enters the gathering line; in gas wells producing above the Turner critical rate, the well's own gas velocity is sufficient to transport liquids up the tubing and into the wellhead scrubber as liquid slugs and mist, and the scrubber collects these liquids for metering and disposal; in gas wells producing below the Turner rate (liquid loading), the wellhead scrubber collects the downslug of liquid that arrives during each slug cycle, allowing the gas to continue to the pipeline while the liquid is accumulated and pumped or trucked for disposal; the wellhead scrubber is also the primary point for monitoring produced water volume, which is required data for production reporting and water disposal planning.
• Cryogenic gas plant scrubbers and demisters in low-temperature separation units must handle the extreme temperature conditions (down to minus 100 to minus 150 degrees Celsius in cryogenic ethane and liquefied petroleum gas extraction plants) that cause conventional elastomeric mist extractor materials to become brittle and crack, requiring special low-temperature steel vessel bodies and wire mesh or vane type mist extractors manufactured from austenitic stainless steel or aluminum alloys that retain adequate ductility at cryogenic temperatures: the mist extractor in a cryogenic scrubber operates at temperatures where liquid hydrocarbon droplets (methane, ethane, propane) are very close to their boiling points and may partially vaporize as they drain down the mist extractor surface, creating a two-phase drain film that behaves differently from the liquid-only drain film in ambient temperature scrubbers; the thermal shock of cold liquid condensate impinging on a warm scrubber vessel body (for example, when a slug of cold condensate enters a scrubber that has warmed during a shutdown period) can cause severe thermal stress that cracks the vessel wall if the vessel is not designed for the full range of thermal transients; cryogenic scrubber vessel materials, weld procedures, and inspection requirements follow the low-temperature provisions of ASME Section VIII Division 1 and must demonstrate adequate Charpy impact toughness at the minimum design temperature to ensure that brittle fracture cannot occur under any credible operating condition.