Finding the Lost Flow with Ultrasonic Technology and Remote Expertise

Last week I did a post about pipeline surge pressure relief and a technical guide about this written by Emerson’s Daniel business. They are known for gas and liquid fiscal flow measurement solutions for the oil and gas industry.

I received a nice follow up note from Dave Seiler about a Latin American refiner who was fighting turbine meter maintenance problems due to large concentrations of foreign materials in the pipeline liquid flow. The problem was so acute that they actually had to install two meters in parallel so they could switch between meters while the other was being maintained.

DanielUltrasonicFlowmeterInstallationThe refinery engineers worked with the local Daniel team to replace the turbine meters with a 6-inch liquid ultrasonic flow meter. These do not have moving parts, unlike the turbine meters, which were being impacted by the particulates in the flow.

I didn’t know much about the ultrasonic technology in flow applications, so I googled around and found a Hydrocarbon Processing magazine article reprint, Use liquid ultrasonic meters for custody transfer, in the Daniel area of the website.

Dave is a co-author of this paper. The article does a great job of simplifying how the ultrasonic technology works. It also includes the math on how the ultrasonic flow measurement works.

My analogy, fresh from a rafting trip down the Guadalupe River, is to imagine that you’re floating down the river with an ultrasonic transducer on one bank, and another on the other bank a little further downstream. Ultrasonic pulses are sent between the two transducers in each direction. The pulse traveling across the river from the upstream one to the downstream one will obviously travel faster since it’s going across the river with the current. And of course, the reverse is true; it takes longer to travel across the river going upstream against the current. With the formulas in the article and enough perseverance, you can calculate the river’s flow rate from these time differences. For the 3D world of pipe flow, the authors’ explain:

The resulting time difference is proportional to the fluid velocity passing through the meter spool. Single and multiple acoustic paths can be used to measure fluid velocity. Multipath meters tend to be more accurate since they collect velocity information at several points in the flow profile.

Now back to the story… after the installation of an ultrasonic flow meter, the refiners saw that the meter was reporting low flow rates when the product in the pipe switched between gasoline and diesel.

The local Daniel service technicians collected maintenance logs using their Customer Ultrasonic Interface software (CUI) and sent it to the support team in Houston for detailed analysis. The team verified that the meter was working correctly for both liquids. They deduced that the flow was being diverted somehow during the transmix, or product switchover, where both products are flowing through the pipe until the switchover has been completed. This was possible because of the meters ability to accurately measure both flow rate and speed of sound of the liquid passing through the meter with extremely high accuracy.

The refiner verified that this is what indeed was happening where this transmix was being routed away through a smaller pipeline for further reprocessing. With the age of the refinery and the retirement of experienced operators, the current operators had not been able to see this transmix operation occurring in their process. The refinery engineers were impressed that the team in Houston could deduce this from their analysis of the data.

The refinery engineers involved in this project are presenting a workshop at this year’s Emerson Exchange in late September. If you face similar challenges, you might want to catch this one.

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