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Wetter Isn't
Better
New Gas Flowmeter Wins Technology Award
By Mary Beckman for INEEL Research Communications
August 1999
| 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. |
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
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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.
FILLS VOID FOR HIGH-VOID FRACTION MEASUREMENTS
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."
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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.
THAT'S HEAVY, DUDE
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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.
ONE PHASE, TWO PHASE . . .
| 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. |
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
|
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. |
.
. . LIGHT PHASE, DENSE PHASE
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.
SEPARATION ANXIETY
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.
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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.
UNCOMMON SOLUTION FOR A COMMON PIPELINE
| 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. |
The Perry Equipment Corporation
from Mineral Wells, Texas, has licensed INEEL's
new flowmeter technology
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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: James Fincke
208-526-5423
jf1@inel.gov
Deborah Hill
208-526-4723
dahill@inel.gov
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