Turbulence conditioner for use with transit time ultrasonic...

Measuring and testing – Volume or rate of flow – By measuring vibrations or acoustic energy

Reexamination Certificate

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Reexamination Certificate

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06647806

ABSTRACT:

FIELD OF THE INVENTION
The present invention is related to the reduction of turbulence in a pipe. More specifically, the present invention is related to the reduction of turbulence with a conditioner so that the calibration coefficient of an ultrasonic flowmeter can be accurately determined using a volumetric displacement prover.
BACKGROUND OF THE INVENTION
Transit time ultrasonic flowmeters have exhibited excellent repeatability and absolute accuracy in many flow measurement applications. However, characteristics inherent in the nature of their measurements present difficulties when these meters are applied to custody transfer measurements of petroleum products. (A custody transfer takes place when ownership of a batch of a particular product changes. On a small scale, such a transfer takes place at the pump in a gas station.)
It is industry practice in custody transfer measurements to “prove” the meter; that is, to establish its calibration accurately, by independent means. Provers are usually devices of fixed and precisely established volume. The time required to deliver the volume of product defined by the prover is accurately measured by timing the transit period of a ball or piston, pushed by the product, from one end of the prover to the other. High-speed diverter valves initiate the prover run and bypass the prover when the ball reaches the end of its travel. The proving operation is synchronized with the operation of the custody transfer meter—the meter to be used to measure the amount of product delivered to a specific customer. The volumetric output measured by the custody transfer meter (in current practice, a turbine or positive displacement meter) during the prover run is compared to the volume of the prover and a meter factor (i.e., a calibration correction) is established.
It is also industry practice to perform a set of several prover runs—five is typical—to establish the “repeatability” of the meter factor of the custody transfer meter. Repeatability in the petroleum industry is usually defined as follows: the difference between the high and low meter factors from a set of prover runs, divided by the low meter factor from that set. Repeatability in the 0.02 to 0.05% range is taken as indicating that the custody transfer meter is in good condition—suitable for use in measuring the volume of the entire batch whose custody is to be transferred. [The batch volume may be hundreds or thousands of times larger than the prover volume.] The average meter factor as determined from the set of prover runs is used for the custody transfer measurement.
Unlike turbine and positive displacement flowmeters, a transit time ultrasonic flowmeter does not measure volumetric flow rate continuously, but instead infers it from multiple samples of fluid velocity. Specifically, the volumetric flow rate is determined from periodic measurements of the axial fluid velocity as projected onto one or more acoustic paths. The path velocity measurements are combined according to rules appropriate to their number and location in the pipe. Many meters employ parallel chordal paths arranged in accordance with a specific method of numerical integration.
The period over which an ultrasonic transit time meter collects a set of velocity measurements (one or more, depending on the number of paths) is determined by the path transit times, the number of paths, and/or the data processing capabilities of the meter itself. For liquid meters, the sample frequency will typically lie between 10 Hz and 1000 Hz.
An ultrasonic flow measurement is thus a sample data system on two counts:
(1) It does not measure the velocity everywhere across the pipe cross section but only along the acoustic paths, and
(2) It does not measure velocity continuously, but instead takes a series of “snapshots” of the velocity from which it determines an average.
Because of these properties, a transit time ultrasonic meter responds to flow phenomena like turbulence differently than other meters commonly used for custody transfer in the petroleum industry. More specifically, the individual flow measurements of transit time ultrasonic meters will be affected by the small scale random (i.e., turbulent) variations in local fluid velocity. These variations are both temporal and spatial, and an ultrasonic instrument must make multiple measurements to determine the true average flow rate—to reduce the random error contributions due to turbulence to acceptable levels. Turbine meters and positive displacement meters, on the other hand, respond to the flow field in the pipe as a whole; integration of the fluid velocity in space and time is inherent in the nature of their responses. Nevertheless, transit time ultrasonic meters are not encumbered by physical limitations like bypass leakage arid friction, and may therefore provide measurement capability over a wider range of velocity and viscosity conditions.
Although the velocity variations due to turbulence are random, multiple samples will only reduce their contribution to measurement uncertainty/repeatability—if the time interval over which the samples are taken is long compared to the periods of the low frequency contributors to the turbulence spectrum. Put another way, a transit time ultrasonic flowmeter can only meet petroleum industry expectations of repeatability—0.02 to 0.05%—if the number of samples of fluid velocity collected during a prover run include a large number of cycles of the lowest significant turbulence frequency. How many cycles? Enough to reduce the RMS contribution of this low frequency turbulence to the meter factor measurement to a level consistent with the repeatability requirements.
The centroid of the turbulence spectrum varies with fluid velocity. Caldon has measured turbulence intensity at Alden Research Laboratories over a range of fluid velocities typical of those encountered in petroleum and petroleum product pipelines. The data indicate a spectrum centered at about 3 Hz at about 4 feet/second. The spectrum is centered at: about 6 Hz at 8 feet/second, while it is centered at 10 Hz at a velocity of 14 feet/second. These frequency data are generally consistent with the turbulence literature. See, for example, “Structure of Turbulent Velocity and Temperature Fluctuations in Fully Developed Pipe Flow”, M. Hishida and Y. Nagano,
Journal of Heat Transfer
February 1979, incorporated by reference herein. This reference and most others on the subject plot the turbulence energy spectrum against the wave number of the turbulence, given by 2&pgr;f/U, where f is the frequency of the turbulence and U is the free stream velocity. The spectrum is expressed as turbulent energy per unit wave number increment. Turbulence intensity is here defined as [∫
T
u
i
2
dt/T]
½
/U, where [∫
T
u
i
2
dt/T]
½
is the root: mean square of the incremental turbulent velocities u
i
and U is the mean axial velocity. The incremental turbulent velocities u
I
represent the temporal and spatial departures of local velocities from the mean. T is a time period encompassing all significant turbulent variations.
The magnitude of the intensity measured by Caldon is also consistent with the literature. For a fluid path length roughly equivalent to a diametral path in a 16-inch pipe, an RMS intensity of 1.6% of the mean axial velocity was measured (for the 4 to 14 ft/sec fluid velocity range). This figure is comparable to that measured in much smaller pipes in the previously cited reference.
A 50-foot long pipe prover for pipeline operating at a flow velocity of 5 ft/sec will generate less than 10 seconds worth of flow data for each prover run. If the turbulence intensity is 1.6%, and the spectrum is centered near 4 Hz, about 40 samples of the low frequency turbulent variations will be collected during a prover run (in spite of the fact that the flowmeter might collect over 1000 measurements in the same 4 seconds). Five meter factor measurements from a single path flowmeter in this application would show a repeatability of about 0.6%. Multiple pa

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