drip, Oil & Gas Glossary

In oilfield gas gathering, a drip is the accumulation of water and heavy hydrocarbon liquids that condense out of a flowing gas stream and collect at the low points of a flowline or pipeline, and by extension the term names both those liquids and the vessel installed to capture them. Raw natural gas leaving a wellhead or separator is rarely perfectly dry; it carries water vapor and heavier hydrocarbon components in the vapor phase that drop out as the gas cools and loses pressure travelling through buried gathering lines. Where the pipeline dips through a topographic low, crosses a creek, or simply follows the undulating profile of real ground, gravity pulls the condensed liquid down into that sag, and if it is not removed it builds into a liquid slug that partially or fully blocks the line, chokes gas throughput, causes erratic slugging into downstream equipment, and in winter can freeze or form a hydrate plug that shuts the line in entirely. To manage this, operators install a drip, also called a drip pot, drip leg, or drip station: a small vessel or a length of larger-diameter vertical pipe teed into the low point where gas velocity drops, liquids fall out and collect, and the accumulated drip is periodically drained or blown down to a tank, a drain line, or a truck for disposal. The liquid recovered, sometimes called drip gas, drip liquid, or in older usage natural gasoline, is a mix of formation water and light condensate that can be a valuable hydrocarbon product when clean or a nuisance stream requiring proper disposal when watery or sour. Historically drip gas was so light and volatile that it was informally used as a low-grade motor fuel in the field, a practice long since discontinued for safety and regulatory reasons. In the Western Canadian Sedimentary Basin, where extensive low-pressure gathering systems move sweet and sour gas across cold, rolling terrain to compression and processing, effective drip management is a routine but essential part of keeping lines flowing, protecting compressors from liquid carryover, and controlling hydrate risk, and it ties directly into a facility's liquids handling, methane venting, and disposal obligations under provincial regulation.

Key Takeaways

Condensed Liquids at Low Points: A drip is the water and heavy hydrocarbon condensate that falls out of a gas stream and pools where a flowline dips through a topographic low. As raw gas cools and loses pressure in a buried gathering line, vapor-phase water and heavier hydrocarbons drop to liquid, and gravity concentrates them in every sag along the route.
The Drip Vessel Captures It: A drip pot, drip leg, or drip station is a small vessel or enlarged vertical section teed into the low point. Gas velocity slows as it enters the larger cross-section, liquids settle out and collect, and the drip is periodically drained or blown down to a tank or truck rather than being allowed to slug down the line.
Prevents Line Loading and Hydrates: Unmanaged drip liquid builds into slugs that choke gas throughput, surge into downstream separators and compressors, and in cold WCSB conditions freeze or form gas hydrate plugs that block the line. Regular drip removal keeps the effective flow area open and reduces winter freeze-off and hydrate shut-in risk.
Drip Liquid Has Value and Hazard: The recovered stream, historically called drip gas or natural gasoline, mixes formation water with light condensate. Clean condensate is a saleable hydrocarbon; watery or sour drip is a disposal stream that may carry hydrogen sulphide. Handling, storage, and blowdown of drips must therefore address both product recovery and worker safety.
Routine Operations and Compliance: Draining drips is a scheduled operator task on WCSB gathering systems, and how the blown-down liquid and any associated gas are captured rather than vented ties into methane-reduction and liquids-disposal rules such as AER Directive 060. Poorly managed drip blowdown is both a lost-product and an emissions and safety concern.

Why Liquids Drop Out of the Gas Stream

Gas leaving a wellhead is saturated with water vapor and carries heavier hydrocarbon components in the vapor phase at reservoir temperature and pressure. As that gas moves through a buried gathering line it cools toward ground temperature and its pressure falls with distance, and both changes push the stream across its dew point so water and the heaviest hydrocarbons condense to liquid. The colder the ground and the richer the gas, the more liquid drops out. This is basic phase behavior, the same retrograde and dew-point physics that governs a plant inlet, playing out kilometre by kilometre in the field, which is why drips accumulate steadily and must be drained on a schedule rather than only after a line upset.

Drip Pot Design and Blowdown Practice

A drip pot is sized so that gas velocity through it falls low enough for liquid to settle out by gravity, typically an enlarged vertical vessel or barrel teed off the pipeline low point with a drain valve at the bottom. Operators blow down the pot on a route, draining collected liquid to a portable tank, a sump, or a vacuum truck, and on modern facilities the blowdown is captured rather than vented to control methane and any H2S. Sizing, drain frequency, and freeze protection are matched to the gas composition and the local terrain; a wet, sour system in rolling WCSB country needs more frequent, more carefully managed drip service than a dry sweet line on flat ground.

Fast Facts

The light condensate drained from pipeline drips was once so volatile and readily combustible that rural operators historically poured drip gas straight into farm trucks and equipment as an informal free fuel. The practice faded because unrefined drip gas has an unpredictable, often dangerously high volatility, can carry hydrogen sulphide, and burns poorly in modern engines, and because the recovered condensate is a metered, taxable hydrocarbon product that regulators require to be accounted for rather than casually consumed in the field.

A drip captures the same liquids a separator removes, but does so passively at pipeline low points rather than in an engineered vessel at the wellsite. The heavier hydrocarbon fraction it recovers is essentially condensate, and the reason liquids appear at all is the gas cooling past its dew point in the line. Left unmanaged, drip liquid combines with cold to create the gas hydrate plugs that shut in winter gathering lines, tying drip control directly to flow assurance.

Real-World WCSB Scenario: Freeze-Off on a Sour Gathering Line near Fox Creek

A sour gas gathering line moving Duvernay-area production near Fox Creek begins losing throughput each cold snap, with the gathering system operator seeing rising upstream pressure and falling delivered volume every time temperatures drop below minus 25 C. Investigation traces the problem to two low-point drips in a creek-crossing sag where accumulated water and condensate had not been drained on schedule; the standing liquid was freezing and forming hydrate, throttling the 168 mm line to a fraction of its capacity. The operator budgets roughly 45,000 CAD to upgrade the two drip stations with larger pots, methanol injection points, and captured blowdown to a closed tank.

With the enlarged drips draining on a tighter winter route and methanol suppressing hydrate formation at the crossings, the line holds full throughput through the next cold spell. Recovered condensate is now metered into the liquids stream as saleable product rather than freezing in the sag, and the captured blowdown keeps the associated gas and any H2S out of the atmosphere in line with the operator's Directive 060 obligations.