“O&G companies are becoming more receptive about newer [Coriolis] technologies,” observes Wade Mattar, Foxboro flow product manager with technology, software and consulting firm Invensys Process Systems (www.ips.invensys.com), Foxboro, Mass. It’s no surprise that costs drive interest. “Mechanical metering techniques such as positive displacement [PD] or turbine, although accurate, require a considerable amount of costly maintenance due to their moving-part construction,” says Mattar. How costly? Rebuilding a PD meter could cost as much as a new one, he remarks.Once, verifying Coriolis meters’ accuracy was an expensive affair, requiring removal of the meter from the line and then certified calibration, notes Tim Patten, engineering manager of Boulder, Colo.-based Micro Motion Inc. USA (www.emersonprocess/MicroMotion), a business unit of automation vendor Emerson Process Management.Easier calibration
But automated meter verification, done without taking meters offline, thus saving downtime losses, now produces numeric results that indicate structural changes in a Coriolis meter’s oscillating measurement tubes, Patten says. “The most important mechanical property is tube wall thickness, because it can change [due to corrosion and erosion, for example]. If the thickness changes, meter verification identifies this as a ‘meter stiffness change’ which can be an indication of calibration changes.” Having accurate and correctly calibrated meters means more money in corporate pockets. For example, custody transfer of crude oil is now being done with Coriolis flowmeters. The major barrier had been “proving” with compact provers, Mattar explains, noting that these devices verify accuracy of petroleum-measurement meters and are a means to periodically either check or reassign new meter factors. “Since a Coriolis flowmeter is not a frequency-based device, synthesized rather than mechanical pulses are provided. Response time in generating these pulses was previously insufficient—200 milliseconds (ms)—to allow traditional proving techniques,” Mattar says. But new-generation Coriolis flowmeters, with their digital technology, give responses within 20 ms, “and proving is now not as much of an issue.”Perhaps one of the thorniest multi-phase issues is gas entrainment in liquids. “Anyone who has had experience with the older-technology Coriolis flowmeters knows they were unable to cope—at all,” Mattar reflects. “This was due to the difficulty in controlling the oscillating tubes with analog circuitry, as well as the large amounts of additional power required to keep the meters running with traditional techniques.”Now, however, through new-generation Coriolis meters with synthesized drive signals and high-speed signal processing, the flow tubes keep oscillating, “even in the sometimes violent two-phase flow situations,” he explains. “The high-speed signal processing can further react to the variety of flow regimes—bubbly flows, stratified flows, slugging or churning flows—possible in these chaotic flows, [thus] allowing compensated mass flow and density measurements.”Patten adds that good signal processing in the transmitter is key to making a good measurement, regardless of the entrained gas. “Two-phase flow is very noisy because the ‘bubbles’ are continually sloshing around inside the pipe. In this sense, the noise is real, and the meter must measure the noise to accurately measure the true average flow rate,” he explains. “Because the noise tends to be high frequency, fast signal processing is critical.” But the multi-phase-measurement end-game is to remove separation completely and provide true multi-phase—three component and two-phase—and measurement at each oil or gas well, Mattar states.Indicating that the measurement art is moving in that direction, Mattar forecasts commercialization “quite quickly” of the technology. “I think we are very close,” he allows. “It will probably use combinations of currently available equipment with clever techniques to combine measurements. It will probably [also] require advances in modeling.”C. Kenna Amos, [email protected], is an Automation World Contributing Editor.
But automated meter verification, done without taking meters offline, thus saving downtime losses, now produces numeric results that indicate structural changes in a Coriolis meter’s oscillating measurement tubes, Patten says. “The most important mechanical property is tube wall thickness, because it can change [due to corrosion and erosion, for example]. If the thickness changes, meter verification identifies this as a ‘meter stiffness change’ which can be an indication of calibration changes.” Having accurate and correctly calibrated meters means more money in corporate pockets. For example, custody transfer of crude oil is now being done with Coriolis flowmeters. The major barrier had been “proving” with compact provers, Mattar explains, noting that these devices verify accuracy of petroleum-measurement meters and are a means to periodically either check or reassign new meter factors. “Since a Coriolis flowmeter is not a frequency-based device, synthesized rather than mechanical pulses are provided. Response time in generating these pulses was previously insufficient—200 milliseconds (ms)—to allow traditional proving techniques,” Mattar says. But new-generation Coriolis flowmeters, with their digital technology, give responses within 20 ms, “and proving is now not as much of an issue.”Perhaps one of the thorniest multi-phase issues is gas entrainment in liquids. “Anyone who has had experience with the older-technology Coriolis flowmeters knows they were unable to cope—at all,” Mattar reflects. “This was due to the difficulty in controlling the oscillating tubes with analog circuitry, as well as the large amounts of additional power required to keep the meters running with traditional techniques.”Now, however, through new-generation Coriolis meters with synthesized drive signals and high-speed signal processing, the flow tubes keep oscillating, “even in the sometimes violent two-phase flow situations,” he explains. “The high-speed signal processing can further react to the variety of flow regimes—bubbly flows, stratified flows, slugging or churning flows—possible in these chaotic flows, [thus] allowing compensated mass flow and density measurements.”Patten adds that good signal processing in the transmitter is key to making a good measurement, regardless of the entrained gas. “Two-phase flow is very noisy because the ‘bubbles’ are continually sloshing around inside the pipe. In this sense, the noise is real, and the meter must measure the noise to accurately measure the true average flow rate,” he explains. “Because the noise tends to be high frequency, fast signal processing is critical.” But the multi-phase-measurement end-game is to remove separation completely and provide true multi-phase—three component and two-phase—and measurement at each oil or gas well, Mattar states.Indicating that the measurement art is moving in that direction, Mattar forecasts commercialization “quite quickly” of the technology. “I think we are very close,” he allows. “It will probably use combinations of currently available equipment with clever techniques to combine measurements. It will probably [also] require advances in modeling.”C. Kenna Amos, [email protected], is an Automation World Contributing Editor.
