44 Air Monitoring


MEETING THE CHALLENGES OF NATURAL GAS STREAM ANALYSIS


Natural gas contains contaminants that need to be carefully monitored to avoid risks to health and safety, and to the very structure of the pipes that carry them. Constant monitoring of natural gas streams demands highly accurate, dependable, and low-maintenance analysers, yet conventional techniques have so far proved less than adequate. Gary Egerton of ABB Measurement and Analytics looks at the challenges and the analyser options.


T


he global energy industry is increasingly fi nding itself at a crossroads, as the twin pressures of energy security and


the growing evidence of climate change force energy providers and users alike to take a fresh look at the way they provide and consume energy. While the ultimate answer to making the transition to zero carbon emissions lies in renewable power sources, the infrastructural and other challenges associated with immediately switching to sources such as wind, solar, hydrogen and other sources of green energy generation mean that ways need to be found in the meantime to minimize emissions from fossil fuel sources.


Despite the increasing move to more renewable energy technologies, natural gas will continue to play a major role as we transition to non-hydrocarbon sources. The existing infrastructure, mature technology and the high energy density of natural gas will see it remain viable and economic for some time to come.


Although natural gas has clear advantages, it also poses signifi cant challenges. Natural gas has a number of naturally occurring contaminants that are present in the gas stream from the well head, including hydrogen sulphide (H2 and carbon dioxide (CO2


S), moisture (H2 ). These constitute a signifi cant hazard


to an operator’s business as they present risks to both safety and pipeline integrity.


S is a dangerous, toxic gas that can cause safety concerns, while excessive CO2


H2 levels reduce the gases’ heating value. Water


can also cause problems, with variations in temperature and pressure potentially accelerating internal pipe corrosion.


S is also of particular concern because of the risk it poses to pipeline integrity. Excessive concentrations of H2


H2 S of 5 ppm and


above increase the risk of internal corrosion within the natural gas infrastructure, including gas pipelines, storage facilities, and other mission-critical assets.


This corrosion occurs through hydrogen-induced cracking, or hydrogen embrittlement, a chemical phenomenon that causes metal alloys to fracture due to a build-up of hydrogen molecules within the crystal lattice structure. This can occur during forming or fi nishing processes, but the most common mode is the gradual diffusion of hydrogen atoms into a component’s structure throughout its service life.


Hydrogen concentration increases the internal pressure on the component, reducing key properties of the metals such as ductility and tensile strength. These localized fl aws can propagate through the surface of the metal, eventually leading to fractures.


This is such a problem that according to the US Environmental Protection Agency, pipelines designed for a service life of 100 years are failing within 20 years due to hydrogen sulphide corrosion. [1]


Constant monitoring essential These risks mean that measuring H2


S, H2


This means that continuous measurements of natural gas contaminants are required for several reasons, including custody transfer, tariff compliance, and process monitoring.


As well as being continuous, contaminant monitoring should also be performed in real-time. This enables the triggering of threshold alarms, allowing the plant to redirect contaminated streams that would otherwise compromise safety and operational yield.


This demands an accurate fl eet of gas analysers, and requires pipeline companies to manage them for reliability, integrity and safety and ensure they have effective process control of gas treatment. They also need to develop plans to manage analyser service, training, and lifecycles, investigate shutdowns and address measurement confl icts in custody transfer agreements.


Essentially, pipeline companies want to increase reliability of their operations and improve the safety of their pipelines. They want monitoring solutions that allow them to respond quickly to process upsets and gas monitors that are easy to install, use and maintain. They want to reduce instrument downtime and the need for site visits, cut the OPEX & CAPEX associated with analysers and protect the environment by ensuring they minimize gas emissions.


O and CO2


concentration is required at processing plants and natural gas custody transfer points to ensure the levels are low enough to meet the required quality specifi cations.


Parts of the natural gas value chain that can benefi t from accurate monitoring include pipeline operators, gas processing plants, natural gas storage facilities and local gas distribution stations.


Pipeline companies collect gas from various sources and make profi ts by transporting and selling it. Increasingly, CO2


is also O)


being captured and traded as a valuable commodity for industrial uses such as refrigerants, infl ation gas for life preservers, food preservation and carbonated drinks manufacture, and promoting the growth of plants in greenhouses. To make this business viable, trustworthy custody transfer from producer to buyer is essential, demanding a highly accurate gas analyser.


Companies also need to preserve the integrity of their infrastructure and operate a safe and reliable natural gas transmission network.


Things that frustrate these goals include lack of measurement precision and reliability, instrument unreliability in remote locations, lack of product support or updates for legacy technology, and complex instruments that are diffi cult both to operate and maintain.


Current measuring approaches


Mitigating the risk of natural gas contaminants can often be frustrating for pipeline operators, as companies are typically required to manage numerous different technologies and analysers. With each of the different contaminants requiring its own gas analyser, maintenance schedule, and specifi c skill set to operate and validate, this approach is complex, prone to failure and expensive.


Today’s analysers often provide inadequate measurement and instrument reliability, false readings – especially during process upsets – and require tedious, time-consuming maintenance. This is particularly problematic for analysers located in remote sites.


For example, one of the common methods is lead acetate tape gas detectors. Typically used to monitor scrubber effi ciency and for H2


S monitoring at fi xed points, these detectors indicate the


IET SEPTEMBER / OCTOBER 2023


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