P. STOCKWELL, Process Vision, Basingstoke, England, UK
For more than 40 yrs, hydrocarbon dewpoint (HCDP) calculations have been the accepted standard for declaring natural gas “dry.”
This method, combining pressure, temperature and composition into an equation of state, has been fundamental to contracts, tariffs and safety cases. By ensuring the HCDP is well below expected operating temperatures, operators have sought to guarantee that gas remains in single-phase as it travels from source to point of use.
This article explores how natural gas liquids (NGLs) are entering gas networks without tripping alarms. Now, advances in process camera technology allow engineers to see high-pressure gas flows in real time. This direct observation is having a significant impact on the industry and opens new opportunities, confirming whether gas streams are genuinely dry. More deployments are showing that, in some cases, hydrocarbon liquids are present even when HCDP values suggest a comfortable margin between the actual temperature and the dewpoint temperature.
For both suppliers and receivers, this visibility presents a chance to significantly improve commercial outcomes:
For gas suppliers, detecting and managing condensate carryover means maximizing revenue by ensuring valuable natural gas liquids (NGLs) are recovered and sold rather than passing through custody points unnoticed. Even a small liquid volume fraction of just 0.1% in a 100-MMsft3d export line at 1,000 psi can equate to > 748 gal/d of sellable NGLs. At a conservative $51.30/bbl, that is > $5.6 MM/yr in potential revenue.
For gas receivers, early identification of liquids in the gas stream reduces downstream maintenance costs, mitigates corrosion and erosion risk, and optimizes pigging schedules. Avoiding unnecessary pig runs (often ~$35,000/mi) and unplanned compressor servicing directly protects the bottom line by $MM/yr while improving operational reliability.
The ability to see what is flowing offers a win–win scenario: greater profitability, enhanced safety margins and better-informed operational decisions for both parties.
This article shows that direct observation of gas flows can complement traditional HCDP analysis, why there are two different parameters that can differ and how integrating both can unlock new levels of performance and profitability in natural gas operations. It also offers three reasons why it is possible for NGLs to be present while dry gas is reported:
HCDP calculation. While HCDP is used widely across the natural gas industry, there have been a number of research papers warning of its limitations, including recent comparisons of six accepted calculation methods on a typical sales gas composition producing a reported HCDP temperature spread of 186°F (103°C).
These equations use a different approach to characterize the heavier hydrocarbons (C6+) found in natural gas. The divergence simply reminds us that phase envelopes are extremely sensitive to small changes in these heavier compounds that lie outside the routine analysis. When the author’s company’s process cameraa was introduced to observe activities inside live gas pipelines, it provided certainty regarding the phases present in the pipe. The presence of liquids in either mist flow or stratified flow are frequently observed while the reported HCDP is (for example) –40°F (–40°C). Initial thoughts might be that these observed liquids are therefore not NGLs (condensate), but rather glycol or compressor oil.
FIG. 1 shows the common liquid flow regimes observed by the company’s camera systema installations around the world. While small amounts of glycol and compressor oil may be present, mist flows are frequently seen to vaporize as the pipeline temperature increases slightly and returns when the pipeline temperature drops (FIG. 2), so observations of this nature could be described as the fundamental definition of a dewpoint.
Gas/liquid equilibrium. Comparing observations of liquid onset events with HCDP provides a second level of uncertainty. FIG. 3 shows an example of the onset of a liquid event known to be NGLs where HCDP did not react to the presence of volatile liquid hydrocarbons. While this explains how NGLs are getting into pipeline networks without tripping alarms, it raises concerns over the flow dynamics involved.
Why, with multiple examples in real-world conditions, does HCDP not respond with the onset of liquids observed with the author’s company’s camera systema? Even if the calibration of the measurement or calculation were in error, a change would be expected when liquids appeared or disappeared. This leads to the question: When gas is flowing in a pipeline over a slower flowing liquid, are the gas phase and liquid phase in equilibrium?
Often, it is when unusual things happen that we understand the mechanisms involved. FIG. 4 shows the increase in British thermal units (Btu) when gas flow is stopped for a few hours at a custody transfer point. Why does this happen if the only change is the flow stopping? During this period the temperature dropped by 2°F. The camera systema showed that there was a liquid stratified flow present at the time, and investigation of the gas chromatograph (GC) data showed that the C6+ element increased by 84% compared to the reading while gas flow was present. One explanation of this is that, with gas flow stopped, volatile liquids are vaporizing into the gas space above the liquid and come towards equilibrium with the gas phase. They are then picked up by the GC monitoring gas phase components. When the gas is flowing, the gas velocity is much quicker than the liquid velocity; so, the volume of gas that these liquids are vaporizing into is much bigger and changes between the presence of liquids and no liquids are minimal.
Sampling systems. Anyone that works with gas analyzers knows that liquids cause problems. So, American Petroleum Institute (API) 14.1 and International Organization for Standardization (ISO) 10715 sampling systems deliberately avoid liquids on the pipe floor by sampling from the middle of the pipeline diameter and filtering out droplets to protect the analyzers. The role of the sample system is to provide a representative gas sample from the pipeline. However, this means that any stratified flow is missed, and any mist flow is rejected before it reaches the analyzer or sample bottle. Engineers, therefore, receive an analysis of the gas phase only. The gas sample has already been stripped of the very liquids that increase Btu and threats in terms of corrosion, erosion and catastrophic failure to:
Compressors
Pipelines
Valves
Regulators.
Gas turbine power station customers will later struggle with blocked burner nozzles and holes in the turbine blades caused by hot NGLs. This leads to uneven combustion and an unbalanced turbine that accelerates maintenance and increases the threat of catastrophic failure. Liquids in the received gas also cause flowmeters to overread, meaning that power stations could be overcharged for the gas they use.
Visual confirmation is no longer “nice to have”: it is a direct way to close a costly accounting gap, safeguard high-value equipment and meet the asset integrity requirements of American Society of Mechanical Engineers (ASME) B31.8S-2022. Where HCDP alone can leave blind spots, real-time observation ensures operators know exactly what is moving through their pipelines, enabling better decisions, higher profitability and compliance with integrity management programs.
The camera’sa hardware. The camera is housed in a rugged stainless-steel enclosure, patented and certified for hazardous areas to UL/CSA Class 1 Div 1 and ATEX Zone 1. It connects to any available 1-in. (or larger) tapping point via threaded or flanged connection and is typically installed with an isolation valve for safe, controlled access (FIG. 5).
One North American transmission operator reported a 3-hr window from start of installation to capturing the first images with no interruption to gas flow.
Most pipeline networks already have the required tie-in points in place, enabling rapid deployment. The company’s cameraa discovery kitsb can be rotated between sites for 4-wk survey periods, allowing engineers to monitor separators, compressor inlets or other key locations before committing to permanent installations.
Do I have liquids in my gas? While the camera’sa video provides indisputable confirmation of liquid carryover, there are practical indicators operators can check that may suggest liquids are present even before deploying a camera:
Review supervisory control and data acquisition (SCADA) trends during a planned or unplanned flow stoppage of 30 min or more. If the Btu value rises noticeably when flow has been stopped for a short period, this can indicate heavier hydrocarbons have condensed in the line and are evaporating into gas phase.
Check HCDP data for the same flow-stop period. An increase in reported HCDP (e.g., from −40°F to −35°F) can point to liquids vaporizing while the gas was stationary.
Sample from a low-point drain during a no-flow condition. Liquids may not appear during normal flow due to the Venturi effect at the tapping point but can accumulate on the pipe wall and drop to the bottom once flow stops. Open the drain slowly: if the valve is opened abruptly, the pressure drop can cause rapid vaporization into mist. If possible, capture this on video.
If any of these conditions are observed, it suggests that liquids may be present either continuously or intermittently. A short-term study on an existing tapping point can then provide conclusive evidence, indicate the severity and support decisions on mitigation.
Processing and cloud analytics. Variations in brightness and texture on video frames translate into qualitative indices for mist density and pipe wall coverage. Still shots are uploaded once a minute and sent through a secure and encrypted link to a portal. A machine-learning (ML) model, trained on millions of tagged frames, classifies conditions, such as clear gas, light mist, heavy mist, distributed liquid flow and stratified liquid flow.
During studies, additional SCADA data—gas flow, process pressure, multi-train differential pressure, etc.—can be correlated with the image meta data in a second ML model that cross-plots process variables against image data for cause-and-effect dependencies. One gas processing plant learned that liquid level in the separator and the differential pressure between two trains were the main drivers of mist flow appearance; closer control of liquid levels can deliver a quick win when cause and effect can be demonstrated in this way.
Software maintenance is as seamless as updating a smartphone app. Firmware upgrade, security patches and algorithm improvements download automatically in the background. From a single browser tab, one engineer can now scroll through color-coded heat maps of liquid events for all their facilities.
Complementing traditional measurements. HCDP monitors, GCs, moisture analyzers and hydrogen sulfide (H2S) analyzers remain essential tools in gas quality measurement. The company camera systema does not replace these instruments but enhances their value by validating the critical assumption behind their readings: that the gas stream is in single-phase flow.
When video confirms that no liquids are present, operators can trust their existing measurement data with greater confidence. When mist or stratified flow is detected, those same images prompt timely remedial action and flag the need to treat flow measurements and gas analysis with heightened caution due to the presence of wet gas.
The systema is already proving its value in the field. A U.S.-based midstream operator uses it as an additional gas quality check at custody transfer points, while a Middle Eastern operator deploys it at compressor inlets to safeguard equipment. In both cases, the camera systema integrates seamlessly with established measurement systems, improving gas quality management, protecting assets and reducing costs for all stakeholders.
PRACTICAL ADVANTAGES ACROSS THE GAS VALUE CHAIN
Gas-processing trains. Live footage allows operators to balance parallel separators and run closer to optimum throughput. With tighter control on liquid carryover at the front end of gas processing, plants previously limited by fear of foaming can boost production by several percentage points of capacity because they can now watch, not guess, for liquid breakthroughs.
When the cameraa is installed on the export gas line, improved NGL recovery can be implemented and demonstrated, increasing the plant’s condensate revenue stream.
Custody-transfer metering. A pipeline operator used video evidence of stratified NGLs to escalate a gas quality problem with a gas supplier. The dispute was quickly resolved with footage from the author’s company’s systema on the supplier side showing that the liquid event was transient and that the event was over on the supply side. This prevented a valve closure or other action by the pipeline operator.
Compressor stations. Early detection and prevention of liquids in either mist flow or stratified flow can extend average dry gas seal life from roughly 1 yr to > 3 yrs in a natural gas compressor, significantly decreasing unplanned outages, servicing costs and seal gas consumption. With liquids often being present at startup, live footage can be used to hold off ramp-up until the liquids have moved through the compressor. Risks can be better evaluated for personnel safety and compressor trips or worse can be prevented.
Power stations. By the time natural gas reaches a turbine power station, it may carry unwanted contaminants, including liquids from upstream suppliers, compressor oil carryover and iron sulfide from pipe walls. If not effectively removed, these can cause significant damage. The camera’sa footage taken downstream of filter packs has revealed filter breakthrough under varying operating conditions: this is a problem that differential pressure (DP) readings can miss, since DP shows what the filter has already stopped.
With better visibility of what actually passes through, operators can fine-tune inlet gas heater control, prevent fuel nozzle blockages and reduce hot-spot formation, ultimately improving turbine performance and reliability.
Liquefied natural gas (LNG) feed gas. One study showed that just 3 parts per billion (ppb) of heavy hydrocarbons (C12+) is sufficient to block a cold box in just 30 d. With many LNG plants having multiple supply lines, knowing which of these supply lines are delivering liquids is vital for continued, uninterrupted LNG production and to ensure a sufficient and effective filtration and separation system continues to perform throughout its design life.
Compromised cathodic protection systems. Asset integrity management programs, aligned with ASME B31.8S-2002, can use liquid carryover detection to identify heightened risks for feedback into mitigation actions to compressors and other critical infrastructure. Stratified flows often transport electrically conductive solids that can bridge isolating joints, weakening or bypassing cathodic protection systems. This increases the likelihood of corrosion and creates a slow, often unnoticed, pathway for methane release.
Early detection allows integrity teams to intervene with targeted pigging before the issue escalates into a reportable incident. This helps operators protect infrastructure, maintain compliance and meet methane-intensity reduction commitments demanded by investors and regulators worldwide.
A broader perspective on digital transformation. Cameras, analytics and cloud-based reporting may sound innovative, but they follow the same trajectory already well-established in other industries, from predictive maintenance on rotating machinery, to satellite monitoring of pipeline corridors, to drone inspections of flare stacks. The company’s camera systema applies this same digital transformation to process control, much like closed-circuit television (CCTV) transformed the security industry.
What sets the camera systema apart is its ability to connect directly to existing tapping points with minimal installation effort, while producing a small data footprint. Cybersecurity, often a concern with cloud-connected systems, has been built in from the start, with secure global access, remote software updates and continuous system health monitoring ensuring both operational resilience and data protection.
Takeaways. Flowmeters, GCs, moisture sensors and H₂S analyzers remain essential to gas commerce and safety, but they cannot capture every transient event modern pipelines experience. High-resolution cameras, combined with embedded and cloud-based ML, add the missing layer of direct evidence. These systems do not replace traditional tools—they make them more reliable by verifying the single-phase flow assumption on which their accuracy depends.
With simple retrofit hardware, rapid installation and minimal bandwidth requirements, the barrier to adoption is low. The benefits, however, are significant: recovered liquids, extended equipment life, reduced maintenance costs and improved environmental, social and governance performance. When operators can see the gas stream instead of merely inferring its condition, situational awareness improves, decisions are faster, disputes diminish and margins grow.
Digitalization in gas operations is no longer a buzzword. It is a practical, proven pathway to a more resilient, transparent and profitable gas value chain, combining the precision of calculated science with the undeniable clarity of direct observation. HP
NOTE
LineVu
LineVu Discovery Systems
Paul Stockwell is the Managing Director at Process Vision. With more than 40 yrs of experience in oil and gas systems, Stockwell was instrumental in the introduction of laser absorption spectroscopy using tunable diode lasers for natural gas measurements assisting in the development of the first TDL system for natural gas. This system has now become the industry-standard method for moisture measurement in natural gas. With a long history of dewpoint measurement systems, in 1991, Stockwell created International Moisture Analysers (IMA) with Business Partner David Parker. From the outset, the company intended to have the ability to look at multi-species analysis, and Stockwell served on working parties for the National Physical Laboratory in the UK for the improvement of moisture measurement. He developed a dewpoint measurement training program for process engineers covering hygrometry and a variety of techniques for measurement engineers.
As a Managing Director for 34 yrs, Stockwell has gained insight into the safety and cost impacts of processes and their problem areas.
The development of LineVu, a permanent monitor for gas/liquid separator efficiency, has revealed some surprises and shown that we still do not know everything about hydrocarbon dewpoint and what is going on in gas systems. In 2017, Stockwell led the de-merger of IMA to form Process Vision. He is the named inventor on 24 granted patents, with 9 pending patents, and firmly believes that a thorough understanding gained through imaging can make a significant difference to the oil and gas industry.
Stockwell now sits on two working groups for GPA Midstream and has presented > 30 papers at industrial conferences.