The American School of Gas Measurement Technology (ASGMT) has been at the forefront of Flow Measurement training since its inception in 1966. Over the years, ASGMT has evolved to encompass comprehensive training in both gas and liquids measurement. With a commitment to excellence, ASGMT now offers an extensive curriculum comprising over 115 lecture classes, complemented by 48 Hands-On Product Training sessions led by industry experts.


September 16th – 19th, 2024


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October 1, 2018

There are many in our industry who would consider the advancement of the ultrasonic meter to be one of the most important improvements in gas measurement in the past twenty years. It is my opinion that the immense improvement in gas measurement is not so much the ultrasonic meter itself. Instead, I believe it is the meter’s ability to detect conditions that would compromise its own accuracy and ability to communicate those conditions to the user. It is in the area of communicating those conditions, that we often under-utilize the meters capabilities.

The natural gas pipeline industry has seen tremendous changes in the past twenty years, including a smaller multi- skilled workforce. The reality of today’s pipeline workforce is fewer technicians performing a wider range of tasks. Much of their measurement work is performed with less frequency, and on more complex equipment than ever before. Gaining the proficiency needed to recognize and troubleshoot ultrasonic meter problems, requires time and experience to learn. By bringing the meter’s diagnostic data into our SCADA system, we can provide alarms and trending capabilities that are not dependent on the frequency at which a Technician can visit a measurement facility. Furthermore, it is not dependent on whether a Technician has the necessary expertise to recognize potential meter problems.

Another change our industry has seen are meter stations with larger but fewer meters. With the high turn down capabilities of ultrasonic meters, large volume meter stations that before would have been built with four or more orifice meters are now built with one or two larger ultrasonic meters. Fewer meters, means we are placing a higher liability on each meter.

One factor that has not changed is the expectations of a tight pipeline balance. In fact, most of us have seen our lost and unaccounted for objectives reduced to a level that would have been impossible to meet twenty years ago. Fortunately, our ultrasonic meters have less uncertainty than the meters we used in the past, and provide us with enough data to warn us when their accuracy is in question. Unfortunately, our testing practices are not much different than the way we’ve tested orifice meters twenty five years ago. When testing orifice meters, we made sure the plate was clean, flat, and sharp; then the transmitters were calibrated. Similarly, with our ultrasonic meters, we look at the software display, pull a two minute log file, calibrate the transmitters, and then assume all is well until the next test cycle. You can be quite confident that the old sayings “ignorance is bliss” and “what you don’t know can’t hurt you” do not apply when searching your pipeline system for lost gas.

Much like our industry’s movement from chart recorders to Electronic Flow Measurement some 30 years ago, the development of Smart Measurement Diagnostic Systems is the natural progression of this technology. This is being accomplished by building on the previous developments of EFMs, PLCs and smart meters.

Coming soon