Blowing the Drip: Liquid Removal From Gas Gathering Line Drip Pots and Low-Point Accumulators
Blowing the drip is the routine field operation of venting accumulated liquid from a drip pot (also called a line drip, trap, or low-point accumulator) — a small-diameter vessel or enlarged pipe section installed at the lowest geometric point of a natural gas gathering or transmission pipeline, where condensate, produced water, and glycol that drop out of the flowing gas stream collect by gravity and must be periodically removed to maintain pipeline capacity. Gas pipelines operating above their hydrocarbon dew point (the temperature and pressure at which liquids begin to condense from the gas phase) can nonetheless accumulate liquid at low points from two sources: well-stream liquids entrained in the gas before they fully separate at the wellhead separator, and retrograde condensation that occurs when the pipeline pressure and temperature fall into the two-phase region of the gas's phase envelope — particularly common in rich Montney, Deep Basin, and Pembina Cardium gas streams where condensate yield may be 20-100 bbl/MMcf. A drip pot is typically a 100-350 mm diameter vessel 0.5-3 m long welded into a low point in the pipeline, with a small isolation valve on the bottom outlet and a liquid level gauge (sight glass or float-type indicator) to estimate accumulated liquid volume. Blowing the drip means opening that bottom valve to allow accumulated liquid (and any gas in the pot) to discharge to a portable collection container, a permanently installed liquid tank, or a drain line routed back to the wellsite separator — a procedure that must be executed carefully to prevent a sudden uncontrolled slug of liquid from overwhelming the collection system, to avoid H2S exposure where the produced gas contains hydrogen sulfide, and to comply with AER Directive 060 requirements that all produced liquids be contained and not discharged to soil. In high-throughput WCSB Montney gathering systems handling 20-100 MMcf/day, drip pots may accumulate liquid at a rate of 1-5 m3 per week during summer operation and 5-15 m3 per week during winter, when lower ambient temperatures drive higher retrograde condensation in the 2-20 km of uninsulated surface gathering line between the compressor station and the wellpad. Manual drip-blowing on weekly field rounds is the standard practice on smaller gathering systems; automated pneumatic or hydraulic drip dump valves (controlled by a float-actuated pneumatic controller) are installed on higher-volume systems where manual frequency would exceed daily rounds, replacing the manual blow with an automated liquid level-controlled dump cycle.
Key Takeaways
- Why liquid accumulates at drip pots in gas pipelines: Gas leaving a wellhead separator is nominally free of liquid, but three mechanisms create liquid in the gathering pipeline downstream: retrograde condensation (gas cools below its hydrocarbon dew point in the buried or surface pipeline, dropping condensate); mist carryover (fine liquid droplets not captured by the wellhead separator mesh or vane pack, particularly at high gas velocities); and glycol carryover (triethylene glycol from dehydration units carried as mist into the gathering line). All three mechanisms concentrate liquid at low-lying pipeline sections where gravity and low gas velocity allow accumulation. A buried drip pot in the WCSB operates year-round at ground temperature (1-8°C), well below the dew point of most Montney gas streams at gathering pressures of 6-12 MPa, ensuring continuous slow condensation even in summer.
- Liquid carryover into compressors and the consequence of a neglected drip pot: The primary operational risk from an overflowing or neglected drip pot is liquid slug carryover into gas compression equipment downstream. Centrifugal compressors and reciprocating compressors are designed to compress gas, not liquid: a liquid slug entering the compressor cylinder or impeller at gas velocity causes hydraulic hammer, broken suction and discharge valves, and in severe cases, bent connecting rods or impeller damage. A single liquid slug event can damage a WCSB field compressor requiring CAD 25,000-120,000 in parts and 3-10 days of downtime. Most WCSB compressor packages have suction scrubbers (coalescing vessels) immediately upstream, but scrubbers become overloaded by large slugs. Reliable drip-blowing discipline is the upstream defence against slug carryover.
- Procedure for blowing a sour gas drip pot safely: When the gas stream contains H2S (Montney, Devonian Leduc, Foothills gas), blowing a drip pot requires: H2S monitor worn with alarm set at 10 ppm, positioning upwind of the drip outlet, confirming the drain hose runs to a sealed collection tank (no open tanks where H2S can accumulate in the space above the liquid surface), opening the isolation valve slowly to prevent slug flow, and never allowing liquid to spill to grade. If the collection tank is full or a hose connection fails, the operator must close the drip valve immediately rather than allowing produced liquid to contact soil — AER Directive 060 classifies any produced liquid release to soil as a reportable release requiring spill notification within 2 hours of discovery.
- Automated drip dump valves in high-throughput systems: On WCSB Montney gathering systems handling above 10 MMcf/day per drip pot location, manual blowing frequency may be required every 12-24 hours, which becomes uneconomic for remote sites. An automated pneumatic drip dump valve uses a float-type liquid level controller to open a 1-inch dump valve when liquid level reaches a preset high point and close it when the level drops to low point, dumping liquid to a vent-sealed collection tank. The tank is checked on weekly field rounds rather than daily. Modern WCSB SCADA systems integrate liquid level sensors at automated drip dump locations, flagging high-level alarms to the control room operator before overflow occurs. Capital cost of an automated drip dump installation: CAD 8,000-18,000 per location versus daily field truck rounds at CAD 600-900/day on a remote site.
- Produced water reporting and disposal from drip pots: Liquids recovered from drip pots in WCSB gas gathering systems are classified as produced water and condensate, both of which must be accounted for under AER Directive 017 (Measurement Requirements for Oil and Gas Operations). Condensate volumes recovered from drip pots may be eligible for royalty deduction as non-sales shrinkage if the volumes are metered and reported correctly. Produced water must be disposed of at a licensed disposal facility (Class II injection well or a licensed produced water disposal facility) — it cannot be land-applied or discharged to surface water regardless of low salt concentration. Operators with multiple drip pot locations often contract a produced fluids hauler to collect liquid from field tanks weekly, with manifested volumes logged against the gathering system's production accounting records.
Winter Drip Management: Deep Basin Gas Gathering System at Kakwa
A Deep Basin gas producer at Kakwa (Montney condensate window, 65 bbl/MMcf condensate yield, 8 MMcf/day throughput) operates a 38 km gathering system with 14 drip pot locations. In January (ambient minus 28°C, ground temperature minus 6°C at 0.5 m depth), condensate accumulation rates at the 7 lowest-lying drip locations increase from summer averages of 0.8 m3/week to 4.5 m3/week due to enhanced retrograde condensation in the cold surface piping sections. The operator upgrades 5 of the 14 locations from manual to automated pneumatic dump valves before the winter season (CAD 68,000 total capital). The 5 upgraded locations are checked on weekly rounds; the 9 remaining manual locations require bi-daily truck visits at a field operating cost of CAD 1,400/day for the 2-man field crew and pickup trucks. By February, one manual location (at a creek crossing dip where ground temperature is colder than average) begins accumulating faster than bi-daily blowing can clear, with visible liquid level at the drip sight glass reaching high-alarm at every round. Resolution: a temporary electric heat trace is wrapped around the drip pot body (CAD 2,200 material + 6 hours installation), raising the pot temperature enough to reduce condensation rate by 40% and allowing bi-daily blowing to keep up. Summer plan: add this location to the next-winter automated upgrade list.
Fast Facts
The drip pot and the practice of blowing the drip predate the modern natural gas industry — the same concept appeared in early 19th-century town gas distribution systems in Britain and Europe, where coal gas was distributed through cast iron pipes and accumulations of coal tar and water at low points required manual clearing by the "drip man," who walked the distribution mains with a bucket to empty each trap in sequence. The modern oilfield drip pot is functionally identical in concept, operating at pressures of 5-15 MPa rather than the few kilopascals of a town gas main, but the underlying physics (gravity-driven liquid accumulation at low-point pipe geometry, with periodic manual removal) has remained unchanged since the 1820s. The terminology "blowing the drip" reflects the original method of clearing the accumulation by allowing the pipeline pressure to push liquid out the drain valve, which was literally blowing the liquid out of the trap — as opposed to a pump or vacuum extraction.
Related Terms
Liquid accumulation in gas gathering systems is governed by the thermodynamic conditions that determine where the gas stream crosses into the two-phase region, with the key variable being the bottom-hole pressure (BHP) at the wellbore: high BHP wells deliver gas at high wellhead pressure, which compresses liquid mist more effectively and may shift the pipeline phase envelope such that the gas remains single-phase farther along the gathering line before retrograde condensation begins. Where drip pot liquids cannot be fully contained or collection tanks overflow, the result is a spill of produced hydrocarbons to soil that triggers the same regulatory notification and cleanup requirements as any other upstream release — procedures directly related to the environmental consequences of both routine production incidents and larger uncontrolled events described under blow-out, where scale of release and response cost are dramatically larger but the fundamental regulatory obligation (contain, report, remediate) is identical.