Paul Stockwell, Process Vision, sets out the implications of new process imaging technologies for the measuring of gas quality, and in particular what it means for the traditional reliance on hydrocarbon dewpoint as the standard measure.
For decades, hydrocarbon dewpoint has been the standard measure for determining whether a gas is ‘wet’ or ‘dry’ – crucial in natural gas transmission, storage, and distribution. Traditionally, hydrocarbon dewpoint has served as the benchmark for gas quality, with many commercial agreements specifying that gas supplies must stay below a certain dewpoint to avoid penalties or product rejection. Indeed, gas is bought and sold on a dry gas basis. However, recent developments are challenging this traditional metric’s reliability, particularly with the advent of new process imaging technologies.
Unveiling the truth inside gas pipelines
The advanced pipeline camera system, LineVu offers real-time video insights into gas flows, revealing that traditional methods often fall short. These cameras are mounted on gas pipelines using standard tapping points, and they stream live images that allow operators to see exactly what is happening inside the high-pressure pipe. By identifying mist or stratified flows of liquids that are otherwise undetectable, these systems provide a clearer understanding of gas conditions than the hydrocarbon dewpoint ever could.
15 years ago, a project led by a major transmission system operator sought to understand why liquid contamination was entering the gas network without triggering alarms with any gas analysis system. This ultimately led to the development of LineVu, which uses image processing and machine learning to monitor and trip alarms when liquid carryover is detected. The technology has proven itself at custody transfer points, revealing a reality that hydrocarbon dewpoint calculations often miss substantial liquid quantities in pipelines that should theoretically be carrying dry gas.
The financial impact of liquid carryover
The cost of liquid carryover in gas pipelines is significant for all stakeholders, from gas suppliers to end-users like power stations. Liquids such as natural gas liquids (NGLs), compressor oil, or glycol, when undetected, can wreak havoc on systems, increase maintenance costs, and lead to substantial financial losses. For example, power stations dependent on natural gas turbines suffer when liquid carryover blocks fuel nozzles, causing imbalances in fuel burn and operational failures.
The losses compound further when considering the sheer volume of liquids escaping detection. Just 0.1% of liquid volume fraction in a 100 million f3/d gas stream could translate to over 10 000 gal./d of NGLs lost equating to millions of dollars in revenue losses annually. This is particularly problematic when conventional hydrocarbon dewpoint readings suggest the gas is dry, yet substantial mist or liquid flow is visibly present within the pipeline.
Hydrocarbon dewpoint’s inaccuracy in real-world conditions
Recent work has highlighted the inconsistency of hydrocarbon dew point calculations. This wide discrepancy demonstrates that the hydrocarbon dew point alone is not a reliable indicator presence of liquid in gas. Moreover, gas sampling techniques outlined in API 14.1 and ISO 10715 specifically exclude two phase flow, which further complicates accurate gas quality assessments for its dewpoint and calorific value (Btu).
Adding to this complexity is the fact that even small amounts of heavy hydrocarbons can create major operational challenges. It was shown by Embry and May that as little as three parts per billion (PPB) of heavy hydrocarbons can create excessive pressure drop across an LNG heat exchanger within 30 days, leading to expensive operational downtime.