Scrub

Scrubbing is the process of removing impurities, liquid hydrocarbons, water, or trace contaminants from a gas stream by passing the gas through a scrubber, which is a vessel designed to bring the gas into close contact with a liquid absorbent or simply to knock out entrained droplets by gravity or mechanical impaction. In upstream oil and gas operations, scrubbers protect compressors from liquid damage, remove hydrogen sulfide and carbon dioxide from gas before pipeline entry, and separate produced liquids from the gas stream at the wellhead or production separator. Gas exits the scrubber cleaner and drier; the removed contaminants drain from the scrubber as liquid.

Key Takeaways

A gas scrubber separates entrained liquid droplets (water, condensate, or glycol) from a gas stream by slowing the gas velocity, allowing gravity to drop the heavier liquid to the bottom of the vessel, and collecting the liquid through a dump valve. This is the simplest type of scrubber, relying on mechanical separation rather than chemical absorption.
Amine scrubbing (also called gas sweetening) uses a liquid amine solution (monoethanolamine (MEA), diethanolamine (DEA), or methyldiethanolamine (MDEA)) to chemically absorb hydrogen sulfide (H₂S) and carbon dioxide (CO₂) from sour gas. The amine is then regenerated by heating, releasing the acid gases, and recirculated. This process is the standard method for treating sour gas before pipeline entry.
Glycol scrubbing is used for gas dehydration. Triethylene glycol (TEG) or diethylene glycol (DEG) absorbs water from the gas stream in a contactor column. The water-laden glycol is then heated to drive off the water and recirculated. This process reduces the water dew point of the gas to pipeline specifications (typically below -10°C).
Inlet scrubbers are installed at the inlet of a compressor to remove any liquid carryover from the upstream pipeline or separator. Even small amounts of liquid entering a reciprocating or centrifugal compressor can cause significant damage: liquid is incompressible, and a slug of liquid in a compressor cylinder can shatter valves or bend connecting rods.
In offshore gas processing, compact scrubbers (cyclonic separators or demister pads in pressure vessels) are preferred because they minimize the footprint on a platform or FPSO deck where space is limited.

What Is Scrubbing in Gas Processing?

Run tap water through a coffee filter and the filter catches coffee grounds. The water passes through but the solids are removed. A gas scrubber works on the same principle, but for a gas stream contaminated with liquid droplets, water vapor, or acid gases. The gas enters the scrubber, the unwanted component is separated out (either by gravity, by impaction on a surface, or by absorption into a liquid), and the cleaned gas exits the other end.

The simplest scrubbers are knockout drums: large cylindrical vessels where the gas velocity drops as the cross-section widens, giving liquid droplets time to fall to the bottom under gravity. These remove the larger droplets (above about 100 microns in diameter) effectively. For finer mists, wire mesh demisters or vane separators are added to coalesce smaller droplets before the gas exits.

More complex scrubbers use a liquid absorbent that captures specific contaminants chemically or physically. An amine scrubber removes H₂S and CO₂ from a sour gas stream. A glycol contactor removes water. A lean oil absorber removes heavier hydrocarbons (C₃ and above) from a rich gas stream. In each case, the gas and liquid come into intimate contact in a packed column or tray column, the contaminant transfers from the gas to the liquid, and the cleaned gas exits overhead while the loaded liquid is regenerated in a separate vessel.

Fast Facts

Canada has some of the world's most sour gas fields, particularly in Alberta's Foothills and northeastern British Columbia. The Sour Gas Capital of Canada title is often given to the Foothills region where fields like Jumping Pound, Waterton, and Quirk Creek produce gas with H₂S concentrations of 10 to 35 percent by mole. Shell Canada's Waterton gas plant and the Jumping Pound gas plant (now operated by various successors) have processed some of the world's sourest commercial gas through amine scrubbing for decades. AER regulations under the Energy Resources Conservation Act set strict limits on H₂S concentration in pipeline gas (typically less than 23 milligrams per cubic metre) that all sour gas must meet after scrubbing.

Inlet Scrubbers and Compressor Protection

Compressor protection is the most critical function of inlet scrubbers in production operations. A reciprocating compressor running at 1,000 to 1,500 RPM has pistons that travel at high speed through a cylinder. The piston compresses gas by reducing volume. If a slug of liquid enters the cylinder instead of gas, the liquid fills the cylinder and the piston attempts to compress an incompressible fluid. The result is a hydraulic lock that can shatter cast iron cylinder heads, break connecting rods, destroy valves, and in extreme cases cause catastrophic structural failure of the compressor.

Inlet scrubbers are installed immediately upstream of every compressor in a gas gathering system. On an Alberta gas battery handling Cardium or Viking gas production, the compressor inlet scrubber typically includes a vertical knockout vessel with a wire mesh demister pad. The scrubber is equipped with a high-level liquid dump that automatically dumps any accumulated liquid to a dump tank if it rises above a safe level. Operators check the dump frequency during routine rounds; a scrubber that is dumping frequently indicates abnormal liquid carryover from upstream and needs investigation before it causes a compressor event.

Glycol Dehydration Scrubbing

All natural gas contains water vapor. When gas is cooled during transmission through a long, cold pipeline, that water vapor can condense into liquid water, which promotes hydrate formation (ice-like crystals that block pipelines), accelerates corrosion, and lowers the gas heating value. Pipeline specifications require gas to meet a water dew point specification, typically a dew point below -10°C at pipeline pressure.

Glycol dehydration units are installed at field processing facilities and at compressor stations. The wet gas enters the bottom of a contactor column and rises through a series of trays or structured packing. Lean TEG (triethylene glycol with less than 0.5 percent water) flows down through the contactor counter-current to the gas, absorbing water from the gas. The wet glycol exits the bottom of the contactor and flows to a reboiler where it is heated to 180 to 200°C, driving off the absorbed water as steam. The lean glycol is cooled and recirculated. A glycol unit on an Alberta gas battery can dry several hundred thousand cubic metres of gas per day and operates largely automatically with weekly operator checks.

Scrubbing is also called gas washing, gas cleaning, or gas treating depending on the specific process. A scrubber is also called a knockout drum (when it separates liquids by gravity), a contactor (when it uses a liquid absorbent), or a sweetening unit (when it removes H₂S and CO₂). Related terms include gas sweetening (the process of removing hydrogen sulfide and carbon dioxide from sour gas to meet pipeline quality specifications; most commonly done by amine scrubbing), amine (a class of organic nitrogen compounds used as the liquid absorbent in gas sweetening units; MEA, DEA, and MDEA are the most common amines in oilfield gas treating), glycol dehydration (the removal of water vapor from natural gas by absorption into triethylene glycol; the standard method for drying gas to pipeline water dew point specifications), demister (a mesh pad or vane assembly installed in a gas separator or scrubber to coalesce fine liquid mist droplets into larger drops that can fall by gravity; improves liquid knockout efficiency compared to an open vessel), and sour gas (natural gas containing hydrogen sulfide above a threshold concentration, typically greater than 5.7 milligrams H₂S per cubic metre; requires scrubbing before pipeline entry and special materials and procedures for safe handling).

How an Undersized Inlet Scrubber Shut Down a North Sea Platform Compressor for Six Days

A North Sea gas production platform in the UK sector was producing from a Jurassic Brent reservoir with a gradually rising water cut. The platform's inlet scrubber before the main export compressor had been sized for the initial dry gas rate of 4.5 million cubic metres per day with negligible liquid carryover. As the reservoir water cut rose, the well stream arriving at the platform began carrying increasing amounts of water and condensate droplets.

Over 18 months, the volume of liquid reaching the inlet scrubber increased from essentially zero to approximately 120 cubic metres per day. The scrubber's demister pad became fouled with scale and produced condensate, reducing its effective liquid knockout efficiency. On a morning when a pipeline pigging operation pushed a slug of accumulated condensate back to the platform, the scrubber could not handle the liquid surge. A significant quantity of liquid carried over into the compressor cylinder, causing a hydraulic lock on the second stroke after the slug arrived. The compressor rod failed and the machine came offline.

The repair required six days: two to isolate and cool down the compressor, one to remove and assess the damaged rod and connecting components, two to install a new rod and rebuilt cylinder, and one for startup testing. GBP 1.8 million in lost production from the shut-in well stream during the repair. An upgrade to a larger scrubber with an automated dump system and a pigging manifold bypass was installed during the subsequent scheduled shutdown at a cost of GBP 420,000. The scrubber sizing was driven by the original well deliverability profile, which had not been updated for the production company's revised water cut forecast. Scrubber sizing must be revisited when well production character changes.