ONE of the main reasons for pipeline explosions, when natural gas is transported through pipelines to downstream industries, is the presence of moisture. When moisture condenses inside the pipeline, it may combine with hydrogen sulfide (H2S) and carbon dioxide (CO2) to become more acidic.
This causes pitting inside the pipeline, damaging it and other downstream equipment over a period. Hence, one of the critical processes before the natural gas is transported through pipelines is removal of moisture.
Figure 1 shows the internal corrosion in the pipeline which is mainly due to the water molecules combining with H2S and CO2.
The moisture in the pipeline is not only monitored for the protection of pipeline and assets, but also to maintain the quality of the natural gas being transported as the presence of moisture will always lower the heating value of natural gas.
Traditionally, the moisture content is monitored using various technologies, such as aluminum oxide, quartz crystal micro-balance, silicon sensors, etc. All these techniques have limitations in providing a reliable measurement.
In most of the cases, the moisture measurement using these technologies misleads the operator, ending in taking wrong decisions.
Another challenge while using the traditional techniques is the presence of the contaminants such as methanol, glycol, amines, H2S, chlorides or mercury, which affects the measurement performances, as they are primarily a contact-based measurement, that is, natural gas along with the contaminants will be in contact with the sensor and the detector to provide the measurements.
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