Liquid carryover detection in natural gas pipelines: the importance of real-time monitoring. By Paul Stockwell.
Liquid carryover in natural gas pipelines is a pervasive yet often overlooked issue that has far-reaching consequences for both operational safety and efficiency. Despite existing industry guidelines and standards, such as those stipulated by the American Petroleum Institute (API) and the International Organization for Standardization (ISO), traditional monitoring techniques fall short. These systems are simply not equipped to handle the complexities of two-phase flows, where liquid and gas coexist in the pipeline, leading to considerable shortcomings in detection and risk mitigation.
Remarkably, around 60% of failures in gas processing plants can be directly attributed to liquid carryover. This is most acute at the critical inlet stages where gas treatment processes like de-sulphurisation and de-humidification occur. In these phases, liquid carryover significantly undermines operational efficiency, leading to complications like foaming. When foaming occurs, it often necessitates a substantial reduction in gas flow rates and incurs additional costs for de-foaming chemicals. As a precaution, operators commonly reduce gas flow rates intentionally, trading off optimal production levels for a semblance of safety.
But the problem extends beyond immediate operational challenges. Long-term effects such as fouling result from accumulated solids, which compromise the performance of heat exchangers, disrupt valve and pump operations, and can even jeopardise the final stages of NGL (Natural Gas Liquids) removal. These cumulative issues have a ripple effect, negatively impacting both safety protocols and profit margins.
Traditional computational fluid dynamics (CFD) models, despite their sophistication, often fall short of predicting the actual dynamics of liquid carryover in real-world operations. This exposes a glaring need for real-time monitoring solutions that can offer immediate, actionable insights. Process cameras have emerged as a game-changing technology in this context. They provide a real-time glimpse into pipelines, revealing frequently occurring mist or stratified flows even when the system is reported to be handling ‘dry gas’.
There is a notable discrepancy between traditional gas analysis systems and real-world conditions. Surprisingly, field data has shown that existing gas analyser systems do not detect or even register the presence of wet gas, despite the fact that wet gas is not an uncommon occurrence in pipelines. These traditional systems, therefore, offer a false sense of security, given that they fail to trigger alarms even when wet gas is present.
This limitation becomes particularly problematic for gas chromatographs, which rely on gas samples that are often not representative of the actual fluid in the pipelines. When wet gas is present, the liquid components are either removed or avoided, leading to skewed BTU calculations and inaccurate representations.
What’s the solution?
Process cameras offer a solution to this conundrum. They detect wet gas in real time. These cameras can inform gas processors when they are losing valuable NGLs and can indicate the ideal times for changing out filter cartridges. Beyond that, they provide an avenue for performance balancing across different gas processing trains, allowing for data-driven, evidence-based actions to improve phase separation and mitigate risks like foaming.
The integration of process cameras, such as Process Vision’s LineVu, has the potential to revolutionise the way gas processors manage the risks and inefficiencies associated with liquid carryover.
By offering a real-time, comprehensive monitoring solution, they support existing systems and pave the way for safer and more profitable natural gas operations.
Paul Stockwell is managing director of Process Vision.
