Improved measurement of water content in natural gas
Endress+Hauser digital press event of today February 8, had a significant title: “More insights into the process with advanced analysis technologies”. Here we report an interesting contribution about the measurement of water content in natural gas.
Contaminants in natural gas can cause a variety of problems for pipeline operators and petrochemical plants, especially when combined with water. This makes accurate and reliable measurement of water content in natural gas streams critical, but traditional techniques often fall short. Fortunately, new analyzers offer much improved performance.
by Sam Miller, Head of Technical Marketing, TDLAS/QF, Endress+Hauser Optical Analysis
Natural gas composition is controlled to some extent. Wherever natural gas is traded commercially, there are regulations as to its chemical content and attributes such as calorific value. Local specifications and ranges vary, but typically there are limits for total sulfur, hydrogen sulfide (H2S), carbon dioxide (CO2), oxygen (O2), and water (H2O). All of them are considered contaminants. Sulfur and its many compounds represent the most widely encountered contaminants in all fossil fuels and are known for their toxicity and pollutants. Oxygen degrades amine and some mercaptans which are used in natural gas treatment and CO2 dilutes the overall heat value.
The greater problem results when these contaminants combine with another: water. All of them work together with water to produce acids capable of attacking carbon steel piping, valves, and other equipment to cause internal corrosion and metal loss over time. Natural gas pipelines can corrode from the outside and inside, but internal metal loss is more difficult to recognize and measure. If the water condenses, it can react with the carbon dioxide or hydrogen sulfide to form an acid that might collect in a low spot and cause internal corrosion.
This leaves natural gas producers, pipeline companies, and users understandably concerned about water content, both liquid and vapor, in the gas flow since a pipeline leak or break caused by unchecked corrosion can cause enormous damage. Knowing the specific moisture content of the gas flow in real-time is thus critical.
Correct and consistent measurement of the water content
There is a small selection of measurement technologies capable of determining the amount of water in a gas pipeline. All typically involve extracting a sample for individual testing, rather than inserting a sensor for a continuous real-time reading. A common drawback to all these electrochemical and electromechanical approaches is the high potential for contamination. Some contaminants, such as compressor oil, methanol, and amine, can cause inaccurate readings. Other contaminants can poison the sensor and require its replacement.
A tunable diode laser absorption spectroscopy (TDLAS) analyzer is the most reliable mechanism to measure water content in natural gas. They use an infrared wavelength laser to isolate the very distinct peaks in the wavelength absorption spectrum, indicating water and other components in the stream. This means the analyzer can provide a water content measurement unaffected by glycol, methanol, amine, or hydrogen sulfide.
Real-time monitoring
TDLAS analyzers enable fewer outages, lower operating costs, and offer increased reliability, all of which provides users a long-term competitive advantage. The J22 TDLAS gas analyzer from Endress+Hauser, which includes the diagnostic, monitoring and verification functions of the Endress+Hauser Heartbeat technology, offers comprehensive process monitoring. Alarms for critical measurement values can prevent process outages.
The J22 gas analyzer includes web server functions that provide access to the data from any Internet-capable device, such as a laptop, smartphone or tablet. This is especially important if the instrument is installed in locations that are difficult for technicians and users to access.
Simple maintenance
Analyzers require specialized enclosures to protect their delicate mechanisms from the harsh surrounding environment. Thanks to the J22 gas analyzer’s robust enclosure, combined with improved isolation and enclosure heating, it can be deployed even in wet and cold climate zones.
Whenever maintenance is required, analyzers can be highly complex or difficult to take apart, so that extensive adjustments are needed during reassembly. Some analyzers require matched component sets, which forces users to purchase costly spare parts kits or send the analyzer back to the factory. This can impact the availability of measurements at critical transfer points. The J22’s modular design and easy-to-remove gas sample cells enable simple maintenance without long downtimes, even if the instrument is difficult to access.
Conclusions
Ensuring the reliable and safe operation of natural gas pipelines and other petrochemical systems requires the prevention of internal corrosion largely caused by condensation in conjunction with other contaminants.
In cases where the water content is critical, to date operators have had to rely on electrochemical methods, but the results are often inadequate. In contrast, TDLAS analyzers enable a high degree of accuracy and offer user-friendly interfaces, plus they deliver measurement values on a continuous basis in intervals of just a few seconds. That means users can determine at any time if the gas quality specification is being fulfilled or if corrective measures must be initiated. Users can furthermore continuously monitor the instrument by means of the diagnostic data.
The result is quick detection of gas contaminants and rapid implementation of the measures required to rectify the problem. Thanks to the improved connectivity, users can access the analyzer from virtually anywhere.
