When pipeline operators talk about “dry gas,” they usually mean a stream that meets contractual specifications—often framed around hydrocarbon dewpoint limits and water content. Yet live visual monitoring tells another story: even gas that passes every lab test can still be laden with fine mists, stratified sheets, or slugs of liquid hydrocarbons, glycols, compressor oils, and water. Liquid contamination is what happens when free or entrained liquids ride along with the gas, threatening safety, efficiency, and profitability.
Where Does the Liquid Come From?
Pipeline “wetness” is rarely caused by a single factor. In most networks it’s a cocktail of sources that fluctuate with season, load, and maintenance status:
- Separator carryover – the “leaky umbrella”
Demister pads blind with rust or black powder, coalescers cartridges deform, and level controls stick in manual. The moment the interface creeps a few millimetres above the design weir, capture efficiency dives and micronize droplets slip past.
- Filter & coalescers bypass — the “ghost pass”
Inline particulate filters and fine mesh coalescers do an excellent job—until they don’t. Collapsed cartridges, torn socks, missing gaskets, or leaking bypass valves can let gas stream straight through with minimal pressure loss, dragging an atomised mist that operators assume has been removed. Visual monitoring routinely spots these events within minutes of a cartridge failure, long before DP transmitters alarm.
- Pressure/temperature swings – inline flash condensation
- Joule–Thomson cooling: Gas throttling across pressure regulators can chill the stream by 10–25 °C in milliseconds, forcing C₃+ components to condense.
- Seasonal & diurnal cooling: A pipeline that is “dewpoint safe” at 25 °C in August can turn two-phase at 5 °C in January.
- Rapid depressurisation: Blowdowns or trip events flash heavy ends that reenter the line when flow restarts.
- Process fluids and lubricants
- Glycol carryover: MEG/TEG aerosol escapes dehydration contactors when reboiler duty is low or internals are damaged.
- Compressor oil mist: Worn dry gas seals or wet gas screw compressors atomise lube oil that travels tens of kilometres downstream.
- Chemical additives: Antifoam, corrosion inhibitor, and oxygen scavenger often hitch a ride as stubborn, surfactant stabilised emulsions.
- Operational upsets & pigging
Start-ups, shutdowns, or pig runs scour films from pipe walls and low points. The resulting slugs can exceed 10 L and surge at >3 m s⁻¹—enough to dent elbows and meter tubes.
- Formation fluids in gathering systems
Associated water and condensate separate in low-pressure well flowlines, then reentrain when velocities climb or terrain dips, sending surprise liquid pockets into transmission lines.
- Hydrate inhibitor overdosing
Excess methanol or glycol injected for hydrate control lowers surface tension and drags droplets of condensate and water downstream. Over injection is common after cold front forecasts or hydrate alarms, leading to hours of wet gas until dosage is corrected.
Why It’s Hard to See (Until It’s Too Late) (Until It’s Too Late)
Most contracts still rely on hydrocarbon dewpoint (HCDP) calculations to classify gas as “dry.” But six different industry approved HCDP methods applied to the same gas mixture produced a temperature spread of 186 °F (103 °C)—wide enough for one method to declare the gas perfectly dry while another predicts liquid dropout at ambient conditions.
Sampling creates another blind spot: API 14.1 and ISO 10715 explicitly avoid two-phase flow, so the very droplets you care about are filtered out before the sample reaches the GC or dewpoint analyser.
Consequences of “Invisible” Liquids
- Equipment damage & downtime – Heavy mist or stratified NGLs can block fuel nozzles and combustor passages in gas turbines, forcing unplanned shutdowns and hot gas path repairs. Compressor seal failures linked to carryover cost operators tens of thousands per incident.
- Lost product & revenue – A seemingly trivial 0.1 % liquid volume fraction in a 100 MMSCFD pipeline equates to >10 000 gal of NGLs every day, worth millions per year at today’s prices.
- Integrity & safety risks – Free liquids accelerate internal corrosion, erode meter runs, and can create slug flow that over stresses bends and separators, occasionally culminating in leaks or ruptures.
Seeing Is Believing: Real-time Visual Monitoring
Because traditional analytics infer liquid presence indirectly, more operators now pair them with direct visual evidence. Process Vision’s LineVu mounts a high-resolution, ATEX rated camera on a standard pipeline tap and streams live video to the control room. Operators immediately spot:
- Fine aerosol clouds drifting across the pipe floor (mist flow)
- Shiny films or rivulets crawling along the wall (stratified flow)
- Large slugs or “caterpillars” of compressor oil climbing vertical runs
By integrating these images with SCADA data, alarms trigger automatically when contamination exceeds user defined thresholds. Field trials across North America, Europe, and the Middle East consistently revealed liquids in lines certified as dry, exposing the limitations of dewpoint alone.
What Liquid Contamination Means to You
Different roles feel the pain—and the upside—differently. Here’s how eliminating hidden liquids can move the needle for each key persona in natural gas operations:
| Persona | Pain Point | What Visual Monitoring Delivers |
| Pipeline Operator / Asset Owner “See the unseen. Protect the pipeline.” | Compressor trips, unplanned shutdowns, NGL loss, compliance exposure | Live proof of contamination events lets teams adjust separators and regeneration processes in time to protect throughput and profitability. |
| Regional Manager “Proof that gets attention. Results that get credit.” | Difficult to validate improvement projects and win budget | Shareable video evidence of before and after conditions wins executive and field team buying for reliability upgrades. |
| Metering Manager “No damage. No doubts. Just data you can trust.” | Orifice and ultrasonic meters drift when liquids erode surfaces or alter density | 24/7 confirmation that flow remains single-phase underpins trustworthy measurement and justifies metering upgrades. |
| Local Site Manager “Easy to see. Easy to act.” | Complex graphs and alarms overload small teams | Realtime images translate gas quality alarms into unmistakable visuals everyone can act on safely. |
| Asset Integrity Manager “Spot risk before it spreads.” | Corrosion and fatigue crack growth from slug flow | Early warning lets integrity teams intervene before wall thinning or overpressure events become failures. |
| Financial Manager “Less risk. More return. No surprises.” | OPEX overruns and investor scrutiny | Quantifying hidden NGL loss and preventing damage improves ROI, controls costs, and boosts investor confidence. |
Remember: Every litre of unseen liquid that makes it past a separator is either a maintenance cost, a lost sale, or a safety risk—often all three.
A Smarter, Dual Validation Approach
- Keep dewpoint and gas chromatograph measurements – They remain vital for custody transfer and energy content.
- Add continuous visual confirmation inside the pipe – Cameras provide the missing ground truth, proving whether flow is truly single-phase.
- Link alarms to operations – When contamination appears, operators can tweak separator levels, adjust glycol recon duty, or slow ram pups before costly damage occurs.
Early adopters report 4× lower compressor maintenance costs and reduced pigging frequency by eliminating surprise liquid slugs.
Key Takeaways
- Liquid contamination is the unwanted presence of free or entrained liquids—NGLs, glycols, oils, water—in gas assumed to be dry.
- Separator inefficiencies, pressure/temperature shifts, fluid leaks, and operational upsets all contribute.
- Relying on dewpoint alone leaves a critical blind spot; calculation methods vary widely, and sampling ignores droplets.
- Realtime visual monitoring closes that gap, providing direct evidence and role specific value—from maintenance savings to investor confidence.
Bottom line: In today’s efficiency driven market, you can’t afford to fly blind. Combine your existing gas analysis with visual monitoring and turn “dry gas” from an assumption into a proven reality.
Next Steps
Whether you’re overseeing a national transmission network or a single remote compressor station, our discovery study quantifies hidden liquid risk in less than 30 days. Contact the Process Vision team to schedule a demo and see how LineVu can deliver wins—tailored to your role and responsibilities.
