There's not a piece of equipment out there like it, so we believe it will take off like gangbusters. —Doyle J. Gould VP of Marketing and Business Development at PECO

Idaho Falls, Idaho—Unlike the purified gas that warms our homes, natural gas flowing from the wellhead is often a mishmash of gas and complex liquids. For decades, producers of natural gas have been dogged with trying to measure the gas portion accurately—the wet portion distorts the volume that standard gauges read as gas, and other methods are costly and labor-intensive. Now, a new flowmeter not only sidesteps the volume distortion problem allows accurate measurement of gas and liquid and is inexpensive enough to place on all wellheads.

The High Void-Fraction Multiphase Flowmeter developed out of the nuclear reactor safety expertise of its inventor, engineer James Fincke at the U.S. Department of Energy's Idaho National Engineering and Environmental Laboratory. The almost-maintenance-free wet gas flowmeter, which can measure the flow rate of gas and liquid from natural gas wellheads 5- to 10-times more accurately than conventional methods, in real time, and continuously, has been licensed by the Perry Equipment Corporation (PECO) in Texas and won Fincke and his PECO colleagues a 1999 R&D 100 Award.

R&D Magazine presents one hundred of these awards yearly for the most important new products. Bulent Turan, a manager in PECO's Flow Measurement Division that is testing and marketing the flowmeter, said, "The award tells us we've been going down the right track in developing this technology. This device provides the accuracy the industry has long been looking for."

The wet gas flowmeter is about three feet tall and fits on top of a natural gas wellhead.

PECO is currently installing the meter on natural gas wellheads to demonstrate it works as well in the real world as it did in the lab. Doyle J. Gould, Vice President of Marketing and Business Development at PECO, expects the meter to fill a natural gas industry void. "There's not a piece of equipment out there like it," he said, "so we believe it will take off like gangbusters."

Natural gas producers drill about 6000 new wells every year, and over 320,000 are expected to be in use in the United States alone by the year 2001. The natural gas flowing from these wells is usually mingled with either valuable liquid hydrocarbon or a briney mix of hydrocarbon and salt water. Current equipment to measure the volume of flow, such as mechanical test separators, costs between $50,000 and $400,000 and may be off by 10-20 percent of the volume.

The difficulty in measuring wet gas arises from the fact that gas and liquid are both fluids with different properties. In a standard flowmeter, the measured pressure of a flowing fluid can be used to determine its velocity, from which its volumetric flow rate is calculated. If the fluid is all gas or all liquid, the differential pressure accurately reflects the flow rate. With a mixture, however, there are no distinctions between the two, which results in uncertain measurement of both fluids. To determine the individual flow rates, the ratio of gas to liquid must be known.

"If you know how much liquid is there," said INEEL's Fincke, "you can account for it. But that's like knowing the answer before asking the question."

The inaccurate reading is a result of the design of the standard flowmeter. The basic flowmeter consists of a pipe that is constricted on one end. The constriction causes the fluid flowing through the pipe to accelerate. Before and after the constriction, two pressure measurements of the accelerating liquid are taken and the difference in pressure is converted into a volumetric flow rate.

The award tells us we've been going down the right track in developing this technology. This device provides the accuracy the industry has long been looking for. —Bulent Turan PECO Flow Measurement Division

If the fluid is single-phase, such as all gas, determining the volumetric flow rate is a simple, accurate calculation. In a gas-liquid mix, however, the denser fluid—liquid—accelerates much slower than the lighter one—gas. The differential pressure, then, is a skewed reading of the two fluids that overestimates the gas phase and underestimates the liquid phase.

To get around this, Fincke added a long throat past the constriction of a conventional flowmeter. The throat is long enough to give the liquid a chance to mostly catch up to the accelerating gas, and the gas and liquid components of the fluid equilibrate with new flow rates. A second differential pressure measurement of the equilibrated fluid allows the meter's computer to determine the volume flow rate with up to 20 times the accuracy of a conventional meter.

The multiphase flowmeter can meter natural gas at wellheads accurately, continuously, and in real time.

Fincke needed to determine how the equilibrated fluids behaved mathematically to calculate the correct flow rates in the wet gas flowmeter, and he did this using low-pressure air and water. "We developed a flowmeter geometry and some mathematical theory that relates the pressures to the flow rates," he said. "But then PECO wanted to do some testing with natural gas hydrocarbons at pressures similar to what you find at wellheads."

Using known amounts of separated natural gas and liquid hydrocarbon, the researchers mocked up a wellhead to gather data over a wide range of conditions and with different flowmeter geometries. The tests confirmed the validity of Fincke's mathematical models. INEEL's wet gas flowmeter is accurate with wet gas that contains up to 10% liquid. If natural gas is much wetter than that, Fincke said, the producers may have a problem that needs to be addressed in the field.

The natural gas industry currently avoids the problem of taking multiphase measurements by using mechanical separators that allow the liquid and gas components to be measured independently. For small natural gas producers, these separators may be the best option, said Fincke. Natural gas flows into a tall, skinny tank, where the two components settle out—liquid is removed from the bottom and gas from the top to be measured. Even so, the measurement can be off by as much as 20% of the gas volume.

Large producers use portable test separators that they cart around on flatbed trucks to measure their individual wellheads a couple times a year. Test separators for small and large producers are expensive, require workers to operate and don't monitor the flow continuously. The wet gas flowmeter, on the other hand, costs between $12,000 and $20,000, has no moving parts and can operate automatically and continuously.

Fincke said the wet gas flowmeter will be useful for two wide-ranging applications: reservoir management and common pipeline usage. Since the flowmeter is inexpensive and small—about 3 feet long—it can be used on all natural gas reservoirs all the time and even on offshore rigs. "The gas well problem is an area that was sorely lacking an economical solution," said Fincke.

The Perry Equipment Corporation from Mineral Wells, Texas, has licensed INEEL's new flowmeter technology

Sometimes a number of producers share a common pipeline from the same gas field. Since profits are based on the gas portion of the mixture, inaccurate metering can adversely affect producers' and distributors' compensation. The wet gas flowmeter will allow producers to determine how much gas their wellheads are contributing to common pipelines, and being within 2-4% of the volume is more acceptable than being off by 20%. "They need to know how much each is producing with accuracies that are agreeable to everyone sharing the pipeline," he said.

PECO is currently beta-testing the flowmeter on natural gas wellheads. "If a producer is interested," said Fincke, "PECO will size a meter for the well, bring it out, put it on the well long enough to convince the producer that it will work and do what we say it will do. And then the producer will buy it."

"We need to show the natural gas industry that the meter performs to meet their needs," said Fincke. "We hope it will become the accepted measurement solution."

Co-winners of the award were PECO manager of R&D Charles Ronnenkamp, PECO software engineer Daniel J. Householder, and PECO product development engineer Darrell Kruse.

Contact:

Steve Zollinger 208-526-9590 gaz@inel.gov

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